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G9D8ꢀD85ꢀ75>5B1<ꢀ@B9>39@<5Cꢀ?6ꢀ49CDB92ED9?>ꢀCICD5=ꢀ?@5B1D9?>ꢀ1>4ꢀꢁꢂ)ꢀ381B13D5B9CD93Cꢒꢀ  
ꢀꢀꢀꢋ?ꢍꢀLꢅ?>CDBE3D9?>ꢀ17B55=5>DMꢀ=51>Cꢀ1>ꢀ17B55=5>D ꢀ@EBCE1>DꢀD?ꢀD85ꢀ9>D5B3?>>53D9?>ꢀ  
CD1>41B4CꢀCE@5BC5454ꢀ2Iꢀ)ꢀꢉꢏꢐꢒꢌꢐꢎ1ꢀD?ꢀ)ꢀꢉꢏꢐꢒꢌꢌꢑ ꢀ25DG55>ꢀ1>ꢀ9>D5B3?>>53D9?>ꢀ3ECD?=5Bꢀ  
1>4ꢀ1>ꢀ5<53DB93ꢀED9<9DIꢀD81Dꢀ3?>D19>CꢀD9=5<9>5Cꢀ1>4ꢀ3?CDꢀ5CD9=1D5Cꢀ6?Bꢀ3?>CDBE3D9?>ꢀ?6ꢀ  
6139<9D95Cꢀ1>4ꢀ49CDB92ED9?>ꢀE@7B145CꢀD?ꢀ9>D5B3?>>53Dꢀ1ꢀꢁꢂ)ꢀ9>D?ꢀD85ꢀ49CDB92ED9?>ꢀCICD5= ꢀ  
1>4ꢀ945>D9695Cꢀ45C97> ꢀ@B?3EB5=5>D ꢀ9>CD1<<1D9?> ꢀ1>4ꢀ3?>CDBE3D9?>ꢀB5AE9B5=5>DCꢀ1CC?391D54ꢀ  
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ꢀꢀꢀꢋ@ꢍꢀLꢅECD?=5BMꢀ=51>Cꢀ1ꢀ@5BC?>ꢀ?Bꢀ5>D9DIꢀG8?ꢀB5359F5Cꢀ5<53DB93ꢀC5BF935ꢀ6B?=ꢀ1>ꢀ5<53DB93ꢀ  
ED9<9DINCꢀ49CDB92ED9?>ꢀCICD5=ꢀ?Bꢀ1ꢀ@5BC?>ꢀG8?ꢀ@1BD939@1D5Cꢀ9>ꢀ1ꢀ<5713Iꢀ>5Dꢀ=5D5B9>7ꢀ?Bꢀ  
49CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=ꢀD8B?E78ꢀ1>ꢀ1<D5B>1D9F5ꢀ5<53DB93ꢀCE@@<95Bꢀ?Bꢀ5<53DB93ꢀED9<9DIꢒꢀ  
ꢀꢀꢀꢋAꢍꢀLꢁꢅMꢀ=51>CꢀL49B53Dꢀ3EBB5>DꢒMꢀ  
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1CC?391D54ꢀ6139<9D95CꢀD81Dꢀ9Cꢀ3?>>53D54ꢀD?ꢀ1ꢀ49CDB92ED9?>ꢀCICD5=ꢒꢀꢀꢁꢂ)ꢀ9>3<E45Cꢀ2?D8ꢀ  
75>5B1D?BCꢀ1>4ꢀ5>5B7IꢀCD?B175ꢀ45F935Cꢀ31@12<5ꢀ?6ꢀ5H@?BD9>7ꢀ13D9F5ꢀ@?G5BꢀD?ꢀ1ꢀ49CDB92ED9?>ꢀ  
CICD5=ꢒꢀꢀ  
ꢀꢀꢀꢋCꢍꢀLꢁ9CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=Mꢀ=51>CꢀD85ꢀ49CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=ꢀ  
1@@B?F54ꢀ2IꢀD85ꢀ3?==9CC9?>ꢀ1>4ꢀ9>3<E454ꢀ9>ꢀ1>ꢀ5<53DB93ꢀED9<9DINCꢀD1B966ꢀ@EBCE1>DꢀD?ꢀC53D9?>ꢀ  
ꢏ1ꢋꢎꢉꢍꢀ?6ꢀꢎꢌꢈꢌꢀ(ꢃꢀꢈ ꢀ%ꢅ$ꢀꢉꢏꢐꢒꢏ1 ꢀ?Bꢀ5CD12<9C854ꢀ9>ꢀ1>ꢀ1<D5B>1D9F5ꢀ5<53DB93ꢀCE@@<95Bꢀ  
49CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=ꢀ@<1>ꢒꢀꢀ  
ꢀꢀꢀꢋDꢍꢀLꢁ9CDB92ED9?>ꢀCICD5=Mꢀ=51>CꢀD85ꢀCDBE3DEB5C ꢀ5AE9@=5>D ꢀ1>4ꢀ6139<9D95Cꢀ?G>54ꢀ1>4ꢀ  
?@5B1D54ꢀ2Iꢀ1>ꢀ5<53DB93ꢀED9<9DIꢀD?ꢀ45<9F5Bꢀ5<53DB939DIꢀD?ꢀ5>4ꢀEC5BC ꢀ>?Dꢀ9>3<E49>7ꢀ  
DB1>C=9CC9?>ꢀ1>4ꢀ75>5B1D9?>ꢀ6139<9D95CꢀD81Dꢀ1B5ꢀCE2:53DꢀD?ꢀD85ꢀ:EB9C493D9?>ꢀ?6ꢀD85ꢀ6545B1<ꢀ  
5>5B7IꢀB57E<1D?BIꢀ3?==9CC9?>ꢒꢀ  
ꢀꢀꢀꢋEꢍꢀLꢁ9CDB92ED9?>ꢀCICD5=ꢀCDE4IMꢀ=51>Cꢀ1ꢀCDE4I ꢀ3?>4E3D54ꢀE>45BꢀD85ꢀ9>D5B3?>>53D9?>ꢀ  
CD1>41B4CꢀCE@5BC5454ꢀ2Iꢀ)ꢀꢉꢏꢐꢒꢌꢐꢎ1ꢀD?ꢀ)ꢀꢉꢏꢐꢒꢌꢌꢑ ꢀD81Dꢀ45D5B=9>54ꢀG85D85Bꢀ1ꢀ49CDB92ED9?>ꢀ  
CICD5=ꢀE@7B145ꢀG1Cꢀ>55454ꢀD?ꢀ133?==?41D5ꢀD85ꢀ@B?@?C54ꢀ@B?:53Dꢀ1>4ꢀD85ꢀ3?CDꢀ?6ꢀ1ꢀ  
49CDB92ED9?>ꢀE@7B145ꢀ96ꢀB5AE9B54ꢒꢀ  
ꢀꢀꢀꢋFꢍꢀLꢁ9CDB92ED9?>ꢀE@7B145CMꢀ=51>ꢀD85ꢀ1449D9?>C ꢀ=?496931D9?>C ꢀ?Bꢀ9=@B?F5=5>DCꢀD?ꢀD85ꢀ  
49CDB92ED9?>ꢀCICD5=ꢀ>535CC1BIꢀD?ꢀ133?==?41D5ꢀ1ꢀꢁꢂ)NCꢀ3?>>53D9?>ꢀD?ꢀD85ꢀ49CDB92ED9?>ꢀ  
CICD5=ꢒꢀꢀꢀ  
ꢀꢀꢀꢋGꢍꢀꢀꢂ<53DB93ꢀED9<9DIMꢀ=51>Cꢀ1>Iꢀ@5BC?>ꢀ?Bꢀ5>D9DIꢀG8?C5ꢀB1D5Cꢀ1B5ꢀB57E<1D54ꢀ2IꢀD85ꢀ  
3?==9CC9?>ꢀ6?BꢀC5<<9>7ꢀ5<53DB939DIꢀD?ꢀB5D19<ꢀ3ECD?=5BCꢀ9>ꢀD89CꢀCD1D5ꢒꢀꢀꢄ?Bꢀ@EB@?C5Cꢀ?6ꢀ)ꢀ  
ꢉꢏꢐꢒꢌꢐꢎ1ꢀD8B?E78ꢀ)ꢀꢉꢏꢐꢒꢌꢌꢑꢀ?><I ꢀL5<53DB93ꢀED9<9DIMꢀ9>3<E45Cꢀ3??@5B1D9F5ꢀ5<53DB93ꢀED9<9D95Cꢀ  
D81Dꢀ1B5ꢀ=5=25BꢀB57E<1D54ꢀ1Cꢀ@B?F9454ꢀ9>ꢀC53D9?>ꢀꢉꢀ?6ꢀD85ꢀ5<53DB93ꢀ3??@5B1D9F5ꢀ=5=25Bꢗ  
B57E<1D9?>ꢀ13D ꢀꢑꢐꢐꢔꢀ(ꢃꢀꢎꢏꢓ ꢀ%ꢅ$ꢀꢉꢏꢐꢒꢈꢉꢒꢀ  
ꢀꢀꢀꢋHꢍꢀLꢂ<53DB931<<Iꢀ3?9>3945>DMꢀ=51>CꢀD81Dꢀꢑꢀ?Bꢀ=?B5ꢀ@B?@?C54ꢀꢁꢂ)Cꢀ1CC?391D54ꢀG9D8ꢀ  
@5>49>7ꢀ9>D5B3?>>53D9?>ꢀ1@@<931D9?>Cꢀ81F5ꢀ?@5B1D9>7ꢀ381B13D5B9CD93Cꢀ1>4ꢀ>1=5@<1D5ꢀ  
31@139D95CꢀG8938ꢀB5AE9B5ꢀD81Dꢀ49CDB92ED9?>ꢀE@7B145CꢀG9<<ꢀ25ꢀ>535CC1BIꢀ96ꢀD85ꢀꢁꢂ)Cꢀ1B5ꢀ  
9>CD1<<54ꢀ9>ꢀ5<53DB931<ꢀ@B?H9=9DIꢀG9D8ꢀ5138ꢀ?D85Bꢀ?>ꢀ1ꢀ49CDB92ED9?>ꢀCICD5=ꢒꢀꢀꢀ  
ꢀꢀꢀꢋIꢍꢀLꢂ<53DB931<<IꢀB5=?D5Mꢀ=51>Cꢀ1ꢀ@B?@?C54ꢀꢁꢂ)ꢀ9Cꢀ>?Dꢀ5<53DB931<<Iꢀ3?9>3945>DꢀG9D8ꢀ1ꢀ  
ꢁꢂ)ꢀD81Dꢀ9Cꢀ1CC?391D54ꢀG9D8ꢀ1ꢀ@5>49>7ꢀ9>D5B3?>>53D9?>ꢀ1@@<931D9?>ꢒꢀꢀ  
ꢀꢀꢀꢋJꢍꢀLꢂ<9792<5ꢀ5<53DB93ꢀ75>5B1D?BMꢀ=51>Cꢀ1ꢀ=5D81>5ꢀ4975CD5Bꢀ?BꢀB5>5G12<5ꢀ5>5B7IꢀCICD5=ꢀ  
G9D8ꢀ1ꢀ75>5B1D9?>ꢀ31@139DIꢀ<9=9D54ꢀD?ꢀ1ꢀ3ECD?=5BNCꢀ5<53DB93ꢀ>554ꢀ1>4ꢀD81Dꢀ4?5Cꢀ>?Dꢀ5H3554ꢀ  
59D85Bꢀ?6ꢀD85ꢀ6?<<?G9>7ꢕꢀꢀ  
ꢀꢀꢀꢀꢋ9ꢍꢀꢀꢎꢊꢐꢀ;.13ꢀ?6ꢀ177B571D5ꢀ75>5B1D9?>ꢀ1Dꢀ1ꢀC9>7<5ꢀC9D5ꢀ6?Bꢀ1ꢀB5>5G12<5ꢀ5>5B7IꢀCICD5=ꢒꢀꢀ  
ꢀꢀꢀꢀꢋ99ꢍꢀꢊꢊꢐꢀ;.13ꢀ?6ꢀ177B571D5ꢀ75>5B1D9?>ꢀ1Dꢀ1ꢀC9>7<5ꢀC9D5ꢀ6?Bꢀ1ꢀ=5D81>5ꢀ4975CD5Bꢒꢀꢀ  
ꢋ11ꢍꢀLꢂ>5B7IꢀCD?B175ꢀ45F935Mꢀ=51>Cꢀ1ꢀ45F935ꢀD81Dꢀ31@DEB5Cꢀ5>5B7Iꢀ@B?4E354ꢀ1Dꢀ?>5ꢀD9=5 ꢀ  
CD?B5CꢀD81Dꢀ5>5B7Iꢀ6?Bꢀ1ꢀ@5B9?4ꢀ?6ꢀD9=5 ꢀ1>4ꢀ45<9F5BCꢀD81Dꢀ5>5B7Iꢀ1Cꢀ5<53DB939DIꢀ6?BꢀEC5ꢀ1Dꢀ1ꢀ  
6EDEB5ꢀD9=5ꢒꢀꢄ?Bꢀ@EB@?C5Cꢀ?6ꢀD85C5ꢀBE<5C ꢀ1>ꢀ5>5B7IꢀCD?B175ꢀ45F935ꢀ=1Iꢀ25ꢀ3?>C945B54ꢀ1ꢀ  
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CD1>41B4CꢀCE@5BC5454ꢀ2Iꢀ)ꢀꢉꢏꢐꢒꢌꢐꢎ1ꢀD?ꢀ)ꢀꢉꢏꢐꢒꢌꢌꢑ ꢀD81Dꢀ45D5B=9>54ꢀD85ꢀCE9D129<9DIꢀ?6ꢀD85ꢀ  
9>D5B3?>>53D9?>ꢀ5AE9@=5>Dꢀ9>3<E49>7ꢀ1>IꢀC165DIꢀ1>4ꢀB5<9129<9DIꢀ3?=@<931D9?>Cꢀ1B9C9>7ꢀ6B?=ꢀ  
5AE9@=5>DꢀC1DEB1D9?> ꢀ=E<D9@<5ꢀD538>?<?795C ꢀ1>4ꢀ@B?H9=9DIꢀD?ꢀCI>38B?>?ECꢀ=?D?Bꢀ<?14Cꢒꢀ  
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ꢆ5>5B1D9>7ꢀꢄ139<9DI ꢀ1>4ꢀ9Cꢀ31<3E<1D54ꢀ1CꢀD85ꢀ=1H9=E=ꢀ1=?E>Dꢀ?6ꢀ5H@?BDꢀ1Cꢀ@5B=9DD54ꢀ2Iꢀ  
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5>79>55B9>7 ꢀ@B?3EB5=5>D ꢀ1>4ꢀ3?>CDBE3D9?>ꢀG?B;ꢀ96ꢀ49CDB92ED9?>ꢀE@7B145Cꢀ?Bꢀ  
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ꢀꢀꢀꢋ44ꢍꢀLꢄ1CDꢀDB13;Mꢀ=51>CꢀD85ꢀ@B?354EB5ꢀEC54ꢀ6?Bꢀ5F1<E1D9>7ꢀ1ꢀ@B?@?C54ꢀ9>D5B3?>>53D9?>ꢀ  
D81Dꢀ=1;5CꢀEC5ꢀ?6ꢀC3B55>9>7ꢀ@B?35CC5C ꢀ1Cꢀ45C3B9254ꢀ9>ꢀ)ꢀꢉꢏꢐꢒꢌꢉꢉꢀD?ꢀ)ꢀꢉꢏꢐꢒꢌꢊꢐꢒꢀꢀꢀ  
ꢀꢀꢀꢋ55ꢍꢀLꢄ?B35ꢀ=1:5EB5ꢀ5F5>DMꢀ=51>Cꢀ1>ꢀ13Dꢀ?6ꢀꢆ?4ꢖꢀ<12?Bꢀ49CDEB21>35ꢖꢀ13Dꢀ?6ꢀD85ꢀ@E2<93ꢀ  
5>5=IꢖꢀG1Bꢖꢀ9>CEBB53D9?>ꢖꢀB9?Dꢖꢀ69B5 ꢀCD?B= ꢀ?Bꢀ6<??4ꢖꢀ5H@<?C9?> ꢀ2B51;175 ꢀ?Bꢀ133945>DꢀD?ꢀ  
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7?F5B>=5>D1< ꢀ=9<9D1BI ꢀ?Bꢀ<1G6E<<Iꢀ5CD12<9C854ꢀ39F9<91>ꢀ1ED8?B9D95Cꢖꢀ?Bꢀ1>?D85Bꢀ31EC5ꢀ  
25I?>4ꢀ1ꢀ@1BDINCꢀ3?>DB?<ꢒꢀꢀꢃꢀ6?B35ꢀ=1:5EB5ꢀ5F5>Dꢀ4?5Cꢀ>?Dꢀ9>3<E45ꢀ1>ꢀ13Dꢀ?6ꢀ>57<975>35ꢀ?Bꢀ  
9>D5>D9?>1<ꢀGB?>74?9>7ꢒꢀꢀ  
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?Bꢀ?D85Bꢀ381B75ꢀD81Dꢀ9Cꢀ1CC5CC54ꢀ?>ꢀ1ꢀ@5Bꢀ=5D5B ꢀ@B5=9C5 ꢀ?Bꢀ3ECD?=5Bꢀ21C9Cꢒꢀꢀ  
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@5B6?B=1>35ꢀD5CDꢀ1>4ꢀ6E>3D9?>1<ꢀD5CDCꢀD?ꢀF5B96Iꢀ9>D5B?@5B129<9DIꢀ?6ꢀ1ꢀ3?=29>1D9?>ꢀ?6ꢀ  
45F935Cꢀ6?B=9>7ꢀ1ꢀCICD5=ꢓꢀ  
ꢀꢀꢀꢌ>ꢎꢀLꢅ?>6?B=9>7Mꢀ=51>CꢀD85ꢀ9>6?B=1D9?>ꢀ9>ꢀ1>ꢀ9>D5B3?>>53D9?>ꢀ1@@<931D9?>ꢀ9Cꢀ3?>C9CD5>Dꢀ  
G9D8ꢀD85ꢀ75>5B1<ꢀ@B9>39@<5Cꢀ?6ꢀ49CDB92ED9?>ꢀCICD5=ꢀ?@5B1D9?>ꢀ1>4ꢀꢁꢂ(ꢀ381B13D5B9CD93Cꢓꢀ  
ꢀꢀꢀꢌ?ꢎꢀLꢅ?>CDBE3D9?>ꢀ17B55=5>DMꢀ=51>Cꢀ1>ꢀ17B55=5>Dꢉꢀ@EBCE1>DꢀD?ꢀD85ꢀ9>D5B3?>>53D9?>ꢀ  
CD1>41B4CꢀCE@5BC5454ꢀ2Iꢀ(ꢀꢊꢐꢑꢓꢍꢑꢏ1ꢀD?ꢀ(ꢀꢊꢐꢑꢓꢍꢍꢒꢉꢀ25DG55>ꢀ1>ꢀ9>D5B3?>>53D9?>ꢀ3ECD?=5Bꢀ  
1>4ꢀ1>ꢀ5<53DB93ꢀED9<9DIꢀD81Dꢀ3?>D19>CꢀD9=5<9>5Cꢀ1>4ꢀ3?CDꢀ5CD9=1D5Cꢀ6?Bꢀ3?>CDBE3D9?>ꢀ?6ꢀ  
6139<9D95Cꢀ1>4ꢀ49CDB92ED9?>ꢀE@7B145CꢀD?ꢀ9>D5B3?>>53Dꢀ1ꢀꢁꢂ(ꢀ9>D?ꢀD85ꢀ49CDB92ED9?>ꢀCICD5=ꢉꢀ  
1>4ꢀ945>D9695Cꢀ45C97>ꢉꢀ@B?3EB5=5>Dꢉꢀ9>CD1<<1D9?>ꢉꢀ1>4ꢀ3?>CDBE3D9?>ꢀB5AE9B5=5>DCꢀ1CC?391D54ꢀ  
G9D8ꢀ9>CD1<<1D9?>ꢀ?6ꢀD85ꢀꢁꢂ(ꢓꢀ  
ꢀꢀꢀꢌ@ꢎꢀLꢅECD?=5BMꢀ=51>Cꢀ1ꢀ@5BC?>ꢀ?Bꢀ5>D9DIꢀG8?ꢀB5359F5Cꢀ5<53DB93ꢀC5BF935ꢀ6B?=ꢀ1>ꢀ5<53DB93ꢀ  
ED9<9DINCꢀ49CDB92ED9?>ꢀCICD5=ꢀ?Bꢀ1ꢀ@5BC?>ꢀG8?ꢀ@1BD939@1D5Cꢀ9>ꢀ1ꢀ<5713Iꢀ>5Dꢀ=5D5B9>7ꢀ?Bꢀ  
49CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=ꢀD8B?E78ꢀ1>ꢀ1<D5B>1D9F5ꢀ5<53DB93ꢀCE@@<95Bꢀ?Bꢀ5<53DB93ꢀED9<9DIꢓꢀ  
ꢀꢀꢀꢌAꢎꢀLꢁꢅMꢀ=51>CꢀL49B53Dꢀ3EBB5>DꢓMꢀ  
ꢀꢀꢀꢌBꢎꢀLꢁ9CDB92ED54ꢀ5>5B7IꢀB5C?EB35Mꢀ?BꢀLꢁꢂ(Mꢀ=51>Cꢀ1ꢀC?EB35ꢀ?6ꢀ5<53DB93ꢀ@?G5Bꢀ1>4ꢀ9DCꢀ  
1CC?391D54ꢀ6139<9D95CꢀD81Dꢀ9Cꢀ3?>>53D54ꢀD?ꢀ1ꢀ49CDB92ED9?>ꢀCICD5=ꢓꢀꢀꢁꢂ(ꢀ9>3<E45Cꢀ2?D8ꢀ  
75>5B1D?BCꢀ1>4ꢀ5>5B7IꢀCD?B175ꢀ45F935Cꢀ31@12<5ꢀ?6ꢀ5H@?BD9>7ꢀ13D9F5ꢀ@?G5BꢀD?ꢀ1ꢀ49CDB92ED9?>ꢀ  
CICD5=ꢓꢀꢀ  
ꢀ
ꢀ
ꢀ
ꢀ
ꢈꢀ  
ꢀ
ꢀꢀꢀꢌCꢎꢀLꢁ9CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=Mꢀ=51>CꢀD85ꢀ49CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=ꢀ  
1@@B?F54ꢀ2IꢀD85ꢀ3?==9CC9?>ꢀ1>4ꢀ9>3<E454ꢀ9>ꢀ1>ꢀ5<53DB93ꢀED9<9DINCꢀD1B966ꢀ@EBCE1>DꢀD?ꢀC53D9?>ꢀ  
ꢐ1ꢌꢏꢊꢎꢀ?6ꢀꢏꢍꢈꢍꢀ'ꢃꢀꢈꢉꢀ$ꢅ#ꢀꢊꢐꢑꢓꢐ1ꢉꢀ?Bꢀ5CD12<9C854ꢀ9>ꢀ1>ꢀ1<D5B>1D9F5ꢀ5<53DB93ꢀCE@@<95Bꢀ  
49CDB92ED54ꢀ75>5B1D9?>ꢀ@B?7B1=ꢀ@<1>ꢓꢀꢀ  
ꢀꢀꢀꢌDꢎꢀLꢁ9CDB92ED9?>ꢀCICD5=Mꢀ=51>CꢀD85ꢀCDBE3DEB5Cꢉꢀ5AE9@=5>Dꢉꢀ1>4ꢀ6139<9D95Cꢀ?G>54ꢀ1>4ꢀ  
?@5B1D54ꢀ2Iꢀ1>ꢀ5<53DB93ꢀED9<9DIꢀD?ꢀ45<9F5Bꢀ5<53DB939DIꢀD?ꢀ5>4ꢀEC5BCꢉꢀ>?Dꢀ9>3<E49>7ꢀ  
DB1>C=9CC9?>ꢀ1>4ꢀ75>5B1D9?>ꢀ6139<9D95CꢀD81Dꢀ1B5ꢀCE2:53DꢀD?ꢀD85ꢀ:EB9C493D9?>ꢀ?6ꢀD85ꢀ6545B1<ꢀ  
5>5B7IꢀB57E<1D?BIꢀ3?==9CC9?>ꢓꢀ  
ꢀꢀꢀꢌEꢎꢀLꢁ9CDB92ED9?>ꢀCICD5=ꢀCDE4IMꢀ=51>Cꢀ1ꢀCDE4Iꢉꢀ3?>4E3D54ꢀE>45BꢀD85ꢀ9>D5B3?>>53D9?>ꢀ  
CD1>41B4CꢀCE@5BC5454ꢀ2Iꢀ(ꢀꢊꢐꢑꢓꢍꢑꢏ1ꢀD?ꢀ(ꢀꢊꢐꢑꢓꢍꢍꢒꢉꢀD81Dꢀ45D5B=9>54ꢀG85D85Bꢀ1ꢀ49CDB92ED9?>ꢀ  
CICD5=ꢀE@7B145ꢀG1Cꢀ>55454ꢀD?ꢀ133?==?41D5ꢀD85ꢀ@B?@?C54ꢀ@B?:53Dꢀ1>4ꢀD85ꢀ3?CDꢀ?6ꢀ1ꢀ  
49CDB92ED9?>ꢀE@7B145ꢀ96ꢀB5AE9B54ꢓꢀ  
ꢀꢀꢀꢌFꢎꢀLꢁ9CDB92ED9?>ꢀE@7B145CMꢀ=51>ꢀD85ꢀ1449D9?>Cꢉꢀ=?496931D9?>Cꢉꢀ?Bꢀ9=@B?F5=5>DCꢀD?ꢀD85ꢀ  
49CDB92ED9?>ꢀCICD5=ꢀ>535CC1BIꢀD?ꢀ133?==?41D5ꢀ1ꢀꢁꢂ(NCꢀ3?>>53D9?>ꢀD?ꢀD85ꢀ49CDB92ED9?>ꢀ  
CICD5=ꢓꢀꢀꢀ  
ꢀꢀꢀꢌGꢎꢀꢀꢂ<53DB93ꢀED9<9DIMꢀ=51>Cꢀ1>Iꢀ@5BC?>ꢀ?Bꢀ5>D9DIꢀG8?C5ꢀB1D5Cꢀ1B5ꢀB57E<1D54ꢀ2IꢀD85ꢀ  
3?==9CC9?>ꢀ6?BꢀC5<<9>7ꢀ5<53DB939DIꢀD?ꢀB5D19<ꢀ3ECD?=5BCꢀ9>ꢀD89CꢀCD1D5ꢓꢀꢀꢄ?Bꢀ@EB@?C5Cꢀ?6ꢀ(ꢀ  
ꢊꢐꢑꢓꢍꢑꢏ1ꢀD8B?E78ꢀ(ꢀꢊꢐꢑꢓꢍꢍꢒꢀ?><IꢉꢀL5<53DB93ꢀED9<9DIMꢀ9>3<E45Cꢀ3??@5B1D9F5ꢀ5<53DB93ꢀED9<9D95Cꢀ  
D81Dꢀ1B5ꢀ=5=25BꢀB57E<1D54ꢀ1Cꢀ@B?F9454ꢀ9>ꢀC53D9?>ꢀꢊꢀ?6ꢀD85ꢀ5<53DB93ꢀ3??@5B1D9F5ꢀ=5=25B  
B57E<1D9?>ꢀ13Dꢉꢀꢒꢑꢑꢕꢀ'ꢃꢀꢏꢐꢔꢉꢀ$ꢅ#ꢀꢊꢐꢑꢓꢈꢊꢓꢀ  
ꢀꢀꢀꢌHꢎꢀLꢂ<53DB931<<Iꢀ3?9>3945>DMꢀ=51>CꢀD81Dꢀꢒꢀ?Bꢀ=?B5ꢀ@B?@?C54ꢀꢁꢂ(Cꢀ1CC?391D54ꢀG9D8ꢀ  
@5>49>7ꢀ9>D5B3?>>53D9?>ꢀ1@@<931D9?>Cꢀ81F5ꢀ?@5B1D9>7ꢀ381B13D5B9CD93Cꢀ1>4ꢀ>1=5@<1D5ꢀ  
31@139D95CꢀG8938ꢀB5AE9B5ꢀD81Dꢀ49CDB92ED9?>ꢀE@7B145CꢀG9<<ꢀ25ꢀ>535CC1BIꢀ96ꢀD85ꢀꢁꢂ(Cꢀ1B5ꢀ  
9>CD1<<54ꢀ9>ꢀ5<53DB931<ꢀ@B?H9=9DIꢀG9D8ꢀ5138ꢀ?D85Bꢀ?>ꢀ1ꢀ49CDB92ED9?>ꢀCICD5=ꢓꢀꢀꢀ  
ꢀꢀꢀꢌIꢎꢀLꢂ<53DB931<<IꢀB5=?D5Mꢀ=51>Cꢀ1ꢀ@B?@?C54ꢀꢁꢂ(ꢀ9Cꢀ>?Dꢀ5<53DB931<<Iꢀ3?9>3945>DꢀG9D8ꢀ1ꢀ  
ꢁꢂ(ꢀD81Dꢀ9Cꢀ1CC?391D54ꢀG9D8ꢀ1ꢀ@5>49>7ꢀ9>D5B3?>>53D9?>ꢀ1@@<931D9?>ꢓꢀꢀ  
ꢀꢀꢀꢌJꢎꢀLꢂ<9792<5ꢀ5<53DB93ꢀ75>5B1D?BMꢀ=51>Cꢀ1ꢀ=5D81>5ꢀ4975CD5Bꢀ?BꢀB5>5G12<5ꢀ5>5B7IꢀCICD5=ꢀ  
G9D8ꢀ1ꢀ75>5B1D9?>ꢀ31@139DIꢀ<9=9D54ꢀD?ꢀ1ꢀ3ECD?=5BNCꢀ5<53DB93ꢀ>554ꢀ1>4ꢀD81Dꢀ4?5Cꢀ>?Dꢀ5H3554ꢀ  
59D85Bꢀ?6ꢀD85ꢀ6?<<?G9>7ꢖꢀꢀ  
ꢀꢀꢀꢀꢌ9ꢎꢀꢀꢏꢋꢑꢀ;-13ꢀ?6ꢀ177B571D5ꢀ75>5B1D9?>ꢀ1Dꢀ1ꢀC9>7<5ꢀC9D5ꢀ6?Bꢀ1ꢀB5>5G12<5ꢀ5>5B7IꢀCICD5=ꢓꢀꢀ  
ꢀꢀꢀꢀꢌ99ꢎꢀꢋꢋꢑꢀ;-13ꢀ?6ꢀ177B571D5ꢀ75>5B1D9?>ꢀ1Dꢀ1ꢀC9>7<5ꢀC9D5ꢀ6?Bꢀ1ꢀ=5D81>5ꢀ4975CD5Bꢓꢀꢀ  
ꢌ11ꢎꢀLꢂ>5B7IꢀCD?B175ꢀ45F935Mꢀ=51>Cꢀ1ꢀ45F935ꢀD81Dꢀ31@DEB5Cꢀ5>5B7Iꢀ@B?4E354ꢀ1Dꢀ?>5ꢀD9=5ꢉꢀ  
CD?B5CꢀD81Dꢀ5>5B7Iꢀ6?Bꢀ1ꢀ@5B9?4ꢀ?6ꢀD9=5ꢉꢀ1>4ꢀ45<9F5BCꢀD81Dꢀ5>5B7Iꢀ1Cꢀ5<53DB939DIꢀ6?BꢀEC5ꢀ1Dꢀ1ꢀ  
6EDEB5ꢀD9=5ꢓꢀꢄ?Bꢀ@EB@?C5Cꢀ?6ꢀD85C5ꢀBE<5Cꢉꢀ1>ꢀ5>5B7IꢀCD?B175ꢀ45F935ꢀ=1Iꢀ25ꢀ3?>C945B54ꢀ1ꢀ  
ꢁꢂ(ꢓꢀꢀ  
ꢀꢀꢀꢌ22ꢎꢀLꢂ>79>55B9>7ꢀB5F95GMꢀ=51>Cꢀ1ꢀCDE4Iꢉꢀ3?>4E3D54ꢀE>45BꢀD85ꢀ9>D5B3?>>53D9?>ꢀ  
CD1>41B4CꢀCE@5BC5454ꢀ2Iꢀ(ꢀꢊꢐꢑꢓꢍꢑꢏ1ꢀD?ꢀ(ꢀꢊꢐꢑꢓꢍꢍꢒꢉꢀD81Dꢀ45D5B=9>54ꢀD85ꢀCE9D129<9DIꢀ?6ꢀD85ꢀ  
9>D5B3?>>53D9?>ꢀ5AE9@=5>Dꢀ9>3<E49>7ꢀ1>IꢀC165DIꢀ1>4ꢀB5<9129<9DIꢀ3?=@<931D9?>Cꢀ1B9C9>7ꢀ6B?=ꢀ  
5AE9@=5>DꢀC1DEB1D9?>ꢉꢀ=E<D9@<5ꢀD538>?<?795Cꢉꢀ1>4ꢀ@B?H9=9DIꢀD?ꢀCI>38B?>?ECꢀ=?D?Bꢀ<?14Cꢓꢀ  
ꢀꢀꢀꢌ33ꢎꢀLꢄ139<9D95CꢀCDE4IMꢀ=51>Cꢀ1ꢀCDE4IꢀD?ꢀC@5396Iꢀ1>4ꢀ5CD9=1D5ꢀD85ꢀ3?CDꢀ?6ꢀD85ꢀ5AE9@=5>Dꢉꢀ  
5>79>55B9>7ꢉꢀ@B?3EB5=5>Dꢉꢀ1>4ꢀ3?>CDBE3D9?>ꢀG?B;ꢀ96ꢀ49CDB92ED9?>ꢀE@7B145Cꢀ?Bꢀ  
9>D5B3?>>53D9?>ꢀ6139<9D95Cꢀ1B5ꢀB5AE9B54ꢓꢀ  
ꢀꢀꢀꢌ44ꢎꢀLꢄ1CDꢀDB13;Mꢀ=51>CꢀD85ꢀ@B?354EB5ꢀEC54ꢀ6?Bꢀ5F1<E1D9>7ꢀ1ꢀ@B?@?C54ꢀ9>D5B3?>>53D9?>ꢀ  
D81Dꢀ=1;5CꢀEC5ꢀ?6ꢀC3B55>9>7ꢀ@B?35CC5Cꢉꢀ1Cꢀ45C3B9254ꢀ9>ꢀ(ꢀꢊꢐꢑꢓꢍꢊꢊꢀD?ꢀ(ꢀꢊꢐꢑꢓꢍꢋꢑꢓꢀꢀꢀ  
ꢀꢀꢀꢌ55ꢎꢀLꢄ?B35ꢀ=1:5EB5ꢀ5F5>DMꢀ=51>Cꢀ1>ꢀ13Dꢀ?6ꢀꢆ?4ꢗꢀ<12?Bꢀ49CDEB21>35ꢗꢀ13Dꢀ?6ꢀD85ꢀ@E2<93ꢀ  
5>5=IꢗꢀG1Bꢗꢀ9>CEBB53D9?>ꢗꢀB9?Dꢗꢀ69B5ꢉꢀCD?B=ꢉꢀ?Bꢀ6<??4ꢗꢀ5H@<?C9?>ꢉꢀ2B51;175ꢉꢀ?Bꢀ133945>DꢀD?ꢀ  
ꢀ
ꢀ
ꢀ
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=1389>5BIꢀ?Bꢀ5AE9@=5>Dꢗꢀ1>ꢀ5=5B75>3Iꢀ?B45BꢉꢀB57E<1D9?>ꢀ?BꢀB5CDB93D9?>ꢀ9=@?C54ꢀ2Iꢀ  
7?F5B>=5>D1<ꢉꢀ=9<9D1BIꢉꢀ?Bꢀ<1G6E<<Iꢀ5CD12<9C854ꢀ39F9<91>ꢀ1ED8?B9D95Cꢗꢀ?Bꢀ1>?D85Bꢀ31EC5ꢀ  
25I?>4ꢀ1ꢀ@1BDINCꢀ3?>DB?<ꢓꢀꢀꢃꢀ6?B35ꢀ=1:5EB5ꢀ5F5>Dꢀ4?5Cꢀ>?Dꢀ9>3<E45ꢀ1>ꢀ13Dꢀ?6ꢀ>57<975>35ꢀ?Bꢀ  
9>D5>D9?>1<ꢀGB?>74?9>7ꢓꢀꢀ  
ꢀꢀꢀꢌ66ꢎꢀLꢄE<<ꢀB5D19<ꢀB1D5Mꢀ=51>CꢀD85ꢀ@?G5BꢀCE@@<Iꢀ1>4ꢀ49CDB92ED9?>ꢀ3?=@?>5>DCꢀ?6ꢀD85ꢀ3?CDꢀ?6ꢀ  
5<53DB93ꢀC5BF935ꢓꢀꢀꢄE<<ꢀB5D19<ꢀB1D5ꢀ4?5Cꢀ>?Dꢀ9>3<E45ꢀ1ꢀCICD5=ꢀ1335CCꢀ381B75ꢉꢀC5BF935ꢀ381B75ꢉꢀ  
?Bꢀ?D85Bꢀ381B75ꢀD81Dꢀ9Cꢀ1CC5CC54ꢀ?>ꢀ1ꢀ@5Bꢀ=5D5Bꢉꢀ@B5=9C5ꢉꢀ?Bꢀ3ECD?=5Bꢀ21C9Cꢓꢀꢀ  
ꢀꢀꢀꢌ77ꢎꢀLꢆ??4ꢀCD1>49>7Mꢀ=51>Cꢀ1>ꢀ1@@<931>Dꢀ81Cꢀ@194ꢀ9>ꢀ6E<<ꢀ1<<ꢀE>49C@ED54ꢀ29<<CꢀB5>45B54ꢀ  
2IꢀD85ꢀ9>D5B3?>>53D9>7ꢀ5<53DB93ꢀED9<9DIꢀ1>4ꢀ1>Iꢀ1<D5B>1D9F5ꢀ5<53DB93ꢀCE@@<95Bꢀ9>ꢀ1ꢀD9=5<Iꢀ  
=1>>5Bꢀ1>4ꢀ>?>5ꢀ?6ꢀD85C5ꢀ29<<Cꢀ1B5ꢀ9>ꢀ1BB51BCꢓꢀ  
ꢀꢀꢀꢌ88ꢎꢀLꢆ?F5B>=5>D1<ꢀ1ED8?B9DIMꢀ=51>Cꢀ1>Iꢀ6545B1<ꢉꢀCD1D5ꢉꢀ<?31<ꢉꢀ?Bꢀ?D85Bꢀ7?F5B>=5>D1<ꢀ  
B57E<1D?BIꢀ?Bꢀ14=9>9CDB1D9F5ꢀ175>3Iꢉꢀ3?EBDꢉꢀ3?==9CC9?>ꢉꢀ45@1BD=5>Dꢉꢀ2?1B4ꢉꢀ?Bꢀ?D85Bꢀ  
7?F5B>=5>D1<ꢀCE249F9C9?>ꢉꢀ<579C<1DEB5ꢉꢀBE<5=1;9>7ꢀ2?1B4ꢉꢀDB92E>1<ꢉꢀ?Bꢀ?D85Bꢀ7?F5B>=5>D1<ꢀ  
1ED8?B9DIꢀ81F9>7ꢀ:EB9C493D9?>ꢀ?F5BꢀD85ꢀ@1BD95CꢉꢀD859BꢀB5C@53D9F5ꢀ6139<9D95Cꢉꢀ?BꢀD85ꢀB5C@53D9F5ꢀ  
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STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own motion, to  
)
promulgate rules governing electric interconnection )  
and distributed generation, and rescind  
)
Case No. U-20890  
legacy interconnection and net metering rules.  
)
_______________________________________________________)  
Introduction  
The Michigan Energy Innovation Business Council (Michigan EIBC) appreciates the  
opportunity to provide comments on the draft Interconnection and Distributed Generation  
Standards (“draft standards”). We value the Michigan Public Service Commission’s (“MPSC”  
or “Commission”) efforts over the last three years to engage stakeholders in a  
comprehensive process to update Michigan’s interconnection standards. Increasing  
deployment of distributed energy, energy storage, and renewables as well as federal  
policies such as FERC Order 2222 elevate the importance of setting effective, forward-  
looking interconnection standards.  
Michigan EIBC has been deeply engaged in the development of the draft standards over  
the last three years and we believe that many aspects of the draft standards represent a  
significant improvement from the current rules. Specifically, we are strongly supportive of  
the addition of a pre-application process, simplified track review process for small projects,  
and fast track process. As detailed below, we have some remaining concerns with the draft  
1
standards that we encourage the Commission to address prior to full implementation.  
Additionally, we are troubled that a number of key decisions are left to utility procedures  
and that the process to develop those procedures does not include sufficient opportunities  
for upfront stakeholder engagement.  
Overall Comments  
Energy storage  
Michigan EIBC strongly suggests that the standards should more clearly define processes  
and procedures around energy storage. With new tariff changes and an increasing focus on  
reliability and resilience, use of energy storage is growing significantly in Michigan among  
residential/commercial customers and in conjunction with larger DER projects, and we  
anticipate increasing interest in distribution-connected storage as well. It is important that  
the interconnection standards spell out how storage will be treated and evaluated during  
interconnection screening and study process. The Commission should provide guidance to  
the utilities to enable the adoption of energy storage and the fair and accurate study of  
these technologies.  
Specifically, the Commission should more clearly spell-out how the utilities shall allow for  
power-limited export DERs. This is a significant challenge currently with some utilities  
creating significant roadblocks for behind-the-meter solar plus storage systems with  
inverter-limited export. We expect this will also be a challenge for front-of-the-meter  
distribution connected storage. It is important to recognize that export from DC coupled  
2
solar plus storage systems is limited by the inverter (and therefore, the total potential  
output is not the sum of the capacity of the solar system and the storage system). Similarly,  
in AC coupled systems, energy storage systems will have their own inverters which can limit  
export capacity. We suggest that the Commission should include specific standards for the  
utilities to follow as detailed in the 2019 Model Interconnection Rules from IREC. This  
follows guidance provided by FERC Order 845, which allows an interconnection customer  
to request service at a lower level than the nameplate generating facility capacity with the  
proper control technologies in place.  
In addition, it is critical in the legacy net metering (“LNM”) and distributed generation (“DG”)  
section that the addition of energy storage to an existing DG system with these appropriate  
limited-export controls does not qualify as a material modification and does not result in  
an applicant being terminated from the LNM or DG program. There could be a requirement  
that the customer notify the utility that a storage system has been installed, but there  
should be no need for any re-evaluation or a new interconnection application (i.e., no  
required re-application) if the appropriate limited-export controls are in place.  
Distributed generation standards  
It is critical to ensure that these rules create a path forward for DG customers to  
interconnect to the grid outside of the LNM or DG program (understanding that the caps  
for those programs may be reached again soon). It is concerning that in the  
“Interconnection penalties” section, any project less than 100 kW in size is excluded from  
3
remedies imposed by the Commission for failure to follow these standards. This seems to  
imply that projects less than 100 kW in size do not have a right to interconnection outside  
of the LNM/DG program. These rules currently appear to only contemplate access to  
interconnection for level 1, 2, and 3 customers through the existing LNM and DG programs  
– but with the caps rapidly approaching, customers need to have access to interconnection  
without needing to also enter one of those programs (e.g., without export, with an energy-  
only contract, or with a PURPA contract).  
Batch study process  
Michigan EIBC continues to encourage the Commission to carefully consider whether the  
proposed batch process could be streamlined or improved on. Specifically, we encourage  
the Commission to review PG&E’s interconnection process in California1 wherein a study  
track project is first subjected to a two-part Electrical Independence Test (EIT). If the project  
fails that test, it is then processed through a cluster study process. However, if the project  
passes the EIT, it can then be studied independently.  
Separately, Michigan EIBC continues to encourage the Commission to find ways to speed  
up the batch study process so that more than one batch can be processed every year.  
Based on experiences in other states, batch processes can be very problematic. The  
ꢀ
1 See https://www.pge.com/en_US/for-our-business-partners/interconnection-renewables/energy-transmission-  
and-storage/wholesale-generator-interconnection/wholesale-distribution-fast-track-interconnection-  
process.page?ctx=large-business.  
4
batching process will be useful if it is a process that allows utilities to group projects in a  
manner that makes sense and decreases personnel, time, and share costs. Otherwise, this  
process will only serve to increase the time and confusion for applicants.  
If a utility processes only one batch per year and then half the projects drop out at the end  
because it is too expensive to proceed, the utility would have to restudy the remaining  
projects. That could lead to a two-year delay. For a 6 MW project that was not able to go  
through fast track, for example, a two-year delay would effectively make it impossible for  
the project to be built. There should be ways to save time through the process that can  
allow at least two batches (perhaps with certain time periods overlapping) to occur each  
year. For example, a utility could start a new batch, do the pre-batch consultations, and  
retrieve payments before it was done with the last batch. The utility could also start the  
study process assuming that every project being studied in the last batch will go to  
completion, which would be the most protective assumption. If that is not an accurate  
assumption, it would be simple to remove a project that does not go to completion from  
the study (it is harder to add a project in after the study has started).  
Detailed Comments  
Part 1. General Provisions  
Definitions  
•ꢀ Definition of material modification: Michigan EIBC appreciates the addition to the  
definition of “material modification” that the modification needs to have been  
5
reviewed and needs to have been determined to cause a material impact on specific  
items including cost/timing/design, the distribution system, or safety/reliability.  
However, we are concerned that the definition of material modification no longer  
includes a statement indicating that a replacement of a component with a near-  
identical component does not constitute a material modification. Although this  
might be reasonably considered to be covered by addition of the list included in the  
definition, we believe that it would be clearer to additionally include this sentence.  
Addition of flowchart: In general, because these rules are new and complex, it would be very  
helpful for utilities and applicants to have a flowchart available listing all of the processes  
and timelines. Each utility could be required to include such a flow chart in their  
procedures or on their website. This would provide significant clarity and greater certainty  
for applicants -- especially because missing certain deadlines means that an application is  
deemed withdrawn. The availability of a flowchart would ensure that all applicants are  
aware of the timelines and requirements at each stage.  
Part 2. Interconnection Standards  
Legacy applications  
Michigan EIBC strongly believes that these rules should allow for valid distribution studies  
that are older than 6 months (e.g., 12 months old). These interconnection standards have  
been under development for nearly 3 years and, over that time, there have been many  
projects that have been unable to move forward beyond a distribution study due to  
6
excessive fees or changes to PURPA avoided cost values or other utility-driven challenges  
with interconnection. In addition, the Covid-19 pandemic has made it difficult for many  
projects to move forward due to financing, supply chain, and labor issues. As a result, it is  
unreasonable to require restudy for any project with a distribution study that is older than  
only 6 months.  
If there is a date restriction for distribution studies that qualify for no restudy (e.g., 12  
months), Michigan EIBC would also suggest adding a section that would allow projects with  
older distribution system studies to avoid restudy if the conditions have not significantly  
changed in that area of the distribution system.  
Transition batch  
It is important that the transition batch not be the only action that the utility takes for the  
entire first year that these rules are in place. Although clearing the queue is of great  
importance, it would be unreasonable to hold up all new applications until the transition  
batch is created. If possible, the transition batch and the first study batches should be run  
in tandem or with a shorter offset in timing.  
In addition, the start date of the transition batch must be made publicly available as soon  
as these rules are effective since many applications in the queue will be affected. Given  
that only Commission Staff will see the first draft of the utility procedures, it is important  
that the transition batch start date is published on the utility’s public website as soon as  
7
possible. We suggest in the concurrently filed redline that this be done within 10 business  
days of the effective date of the rules.  
In a similar manner as above, it is unreasonable to require that engineering reviews must  
have been completed within 6 months of the effective date of the rules to avoid repetition.  
Instead, the utility should only be allowed to require a new system impact study if the  
existing study is more than 12 months old and upon showing cause that a new study is  
necessary based on changing circumstances affecting the location of interconnection. The  
language in this section does not make this clear. Specifically, on page 12, “may not be  
required to pay for a new system impact study” is confusing because “may” could mean  
“shall not” (as we recommend) or “may depending on the utility’s discretion.”  
Finally, we recommend that applicants be allowed to reduce the capacity of the DER by  
more than 20% during the decision period between studies in the transition batch. It is  
unclear why this would be limited to 20%, especially if such a change does not impact other  
projects in the transition batch. There may be a need to decrease the capacity of a DER if  
the cost for a future study will be greater or if it appears that expensive interconnection  
upgrades will be required.  
Interconnection procedures  
It is concerning that both per these draft rules and the timeline set in Case No. U-21117,  
there appears to be no stakeholder input or engagement on the new utility procedures  
8
until at least 3 months after the drafts are filed. We would strongly recommend increased  
transparency and stakeholder engagement prior to the March and April 2022 stakeholder  
meetings. In addition, Michigan EIBC is supportive of the draft rule requiring “commission  
approval” prior to the revision of a utility’s procedures but feels the term is relatively vague.  
We suggest that “formal commission approval” would be more appropriate, necessitating  
that the utility file a formal proceeding and the Commission act upon such a filing with an  
official order. We would prefer that stakeholders were given the ability to participate in  
such a process, but at the very least, it is necessary that any changes to the utility  
procedures be done in a transparent manner and that approval is not simple approval by  
Commission Staff without appropriate public input.  
In addition, it is important that the Commission clearly indicate that it is the expectation  
and the norm that energy storage shall be able to be added to a LNM system easily and  
simply without impacting the 10-year grandfathering period and to a DG system without  
impacting program participation. There is no incentive for the utilities to make this simple  
or possible for customers. Given that it appears that the Commission would like this to be  
easily attainable for customers, this should be made clear to the utilities.  
Separately, the draft rules indicate in section (o) (page 14) that the utilities need to provide  
examples of “modifications that are not material modifications, acceptable material  
modifications, and unacceptable material modifications.” There are no definitions provided  
of “acceptable material modifications” and “unacceptable material modifications” and in  
9
fact, it does not on the face appear to make sense to use these terms. Either a modification  
is material, and therefore some amount of restudy is necessary, or a modification is not  
material, and therefore the application can proceed without restudy. The utility should not  
be able to determine whether an applicant is willing to pay for restudy (thereby making the  
material modification “acceptable”) or not willing to pay (thereby making the material  
modification “unacceptable”).  
Fees  
At the very least, the fees for pre-application reports, simplified track, non-export track, fast  
track, and transition batch should be set by the Commission and not set by the utilities in  
their procedures and then changed at the discretion of the utilities. Michigan EIBC suggests  
the Commission adopt the same fees charged by nearly all other states that have already  
updated their interconnection rules as detailed in the Michigan EIBC’s concurrently filed  
redline to the draft standards. There is no clear reason why Michigan’s utilities should have  
significantly higher costs than other Midwest utilities or, if they do currently have higher  
costs, why efficiencies could not be found to decrease costs. The initial fees for these items,  
as outlined in the draft rules, are reasonable and should be permanent.  
In addition, the fee caps for the study track items outlined in the draft rules are very high  
compared with similar fees charged in other states. We recommend lowering these initial  
fee caps with the expectation that most utilities will probably charge the maximum fee caps  
allowed. These values should not be determined based on a “middle ground” between  
10  
developers and the utilities – instead, they should be based on best practices from groups  
like IREC and other states with recently revised rule sets.  
Finally, there is no reason that a utility should be allowed to apply for a waiver from the fee  
caps. These fees for the study track (which are most likely to be costly and variable  
between projects) will be set by the utility. It is unclear why the Commission would even  
approve fee caps if it then allows a utility to apply for a waiver from those fee caps  
whenever the costs exceed the caps.  
Pre-application report  
Michigan EIBC greatly appreciates the addition of the pre-application report to these  
standards and appreciates the Commission Staff’s attention to this section. We continue to  
encourage the inclusion of the feeder identifier and feeder voltage in the pre-application  
report given that these data sets are important to understanding the likely impact of the  
DER on the grid. In addition, given that the pre-application report only includes readily  
available data, there is no reason why such reports should take the utility 5 weeks (25  
business days) to process. Instead, we suggest that 15 business days should be sufficient.  
Fast track  
Michigan EIBC believes that eligibility for the fast track should not be limited to level 4  
projects. Instead, as suggested by FERC, applicability should be for projects at least up to 4  
MW in nameplate capacity. The fast track should be a simple, cost-effective, relatively quick  
11  
process to determine whether a project can be quickly approved. There is no reason that  
slightly larger projects should not go through the fast track process in case some of them  
are able to pass the screens and not cause any issues for the grid or require upgrades.  
In addition, it is unclear why the Commission would allow the utility to include additional  
screens that undermine or negate any of the required screens. Such additional screens,  
which undermine any of the required screens, simply should not be allowed.  
Cost allocation  
The cost allocation requirements in the draft standards are vague and do not fairly allocate  
costs to each interconnection applicant. It is vital that cost allocation is done fairly and  
consistently, especially because interconnection upgrade costs can be significant and can  
be notably difficult to allocate given a batch study process. It is also important to ensure  
that costs attributable to all ratepayers are not assigned to interconnection applicants. We  
would suggest adding in a requirement that a utility use clear requirements (as outlined in  
our comments in the draft), based on procedures in other states, as a starting point for the  
cost allocation methodology included in the utility’s procedures. The utility could then  
modify the proposal in its procedures, but this would provide clearer guidance to utilities.  
Modification of an interconnection application  
It is important that this section aligns with the definition of “material modification” and with  
pervious sections in the standards. Specifically, it does not make sense for the utility to do a  
12  
a “cursory evaluation” to determine if a modification is a material modification given that  
the definition of material modification requires a review and specific findings.  
In addition, as described above, “acceptable material modification” and “unacceptable  
material modification” are not defined terms. Either a modification is material, and  
therefore some amount of restudy is necessary, or a modification is not material, and  
therefore the application can proceed without restudy. The utility should not be able to  
determine whether an applicant is willing to pay for restudy (thereby making the material  
modification “acceptable”) or not willing to pay (thereby making the material modification  
“unacceptable”). This section should be revised accordingly.  
Insurance  
Throughout this draft, projects sized at levels 1, 2, and 3 are treated in a similar manner  
(e.g., for fast track review, for the application process, for the study process, etc). These  
projects also would all potentially be eligible for legacy net metering/the distributed  
generation program. As such, it does not make sense to require additional insurance for  
projects less than 150 kW in capacity (level 3). We suggest removing the references to level  
3 from the insurance requirements in this section.  
In addition, according to Michigan EIBC members, in other states, a liability of $2 million is  
typically reserved for projects greater than 1MW (e.g., 2MW-6MW; level 5). $3 million in  
13  
liability is more for much larger projects that would be connected to the transmission  
system.  
Easements and rights-of-way  
The utility is responsible for procurement and obtaining easements or rights-of-way and  
the applicant pays the costs of those activities. The applicant cannot be responsible for  
obtaining rights-of-way/easements. This needs to be clarified.  
Part 3. Distributed Generation Program Standards  
Overall Comments  
As described above, it is critical to ensure that these rules create a path forward for DG  
customers to interconnect to the grid outside of the LNM or DG program (understanding  
that the caps for those programs may be reached again soon).  
Application Process  
The requirement that an energy storage device cannot export to the distribution system  
would seem to be counter to Order 2222 and future virtual power plant/aggregation  
opportunities with storage DERs. This would even be counter to the BYOD programs  
proposed by Michigan’s utilities wherein customer-sited batteries are used to provide grid  
services. We strongly encourage the deletion of this requirement.  
14  
For an existing customer with a signed Interconnection Agreement who would like to add  
an energy storage device, it needs to be clear both that this customer can do so without  
losing the 10-year grandfathering in the LNM program and without losing access to the DG  
program. This will become more critical as we near the caps in the programs because a  
customer who needs to reapply, as suggested in section (8), may find the DG program  
closed and then may not only not be able to add their storage device, but also, may be  
unable to continue to use their existing solar panels.  
15  
November 1, 2021  
VIA E-Mail to Executive Secretary at mpscedockets@michigan.gov  
Dan Scripps, Chair,  
Michigan Public Service Commission,  
P.O. Box 30221,  
Lansing, MI 48909.  
RE: Ford Motor Company Comments on Interconnection and Distributed Generation Standards, Case  
No. U-20890  
Dear Mr. Scripps,  
Ford intends to take leadership of the electric vehicle revolution by introducing the industry’s most  
compelling high-volume battery electric vehicle lineup and investing more than $30 billion by 2030 to  
develop connected and electric vehicles and services, including batteries. We’re electrifying our most  
iconic popular models, starting with the F-150 Lightning, the Mach-E and the E-Transit, and customer  
demand for these vehicles has exceeded our expectations -- we are well positionedꢀto haveꢀfully electric  
vehicles account for 40%ꢀto 50% ofꢀour U.S. sales by 2030.  
Electrification is an important part of our future and to our commitment to reach carbon neutrality no  
later than 2050, but substantial challenges must be overcome before this future can be realized. We  
know that adoption of electric vehicles by private customers, commercial and transit operators depends  
on reliable charging networks. That’s why we are so focused on delivering the Blue Oval Charge  
Network -- the largest public charging network in North America offered by automotive manufacturers  
-- and technology that improves the customer experience by allowing them to manage and  
customizeꢀtheirꢀcharging needs, routeꢀto nearby charging stations, and pay seamlesslyꢀall  
through theꢀFordPassꢀApp.  
We believe that both public utility and private company participation are needed to fully address these  
challenges. By working together, we can leverage our unique skillsets and focus, help remove barriers  
to electrification and address the distinct, varied needs of the EV and charging markets.  
To that end, we appreciate the opportunity to provide comments on the proposed revisions to  
interconnection and generation standards.  
1. Electric and Fuel Cell Vehicles should be added explicitly to the list of DERs and Generation sources  
noted in section R460.930.  
2. EVs can potentially qualify as Level 1 or Level 2 sources individually or Level 3+ as an aggregated  
source such for customers with depot charging capability.  
3. Develop a fast track process for EVs seeking interconnection as Level 1 or Level 2. Current fast track  
(R460.944 -950) is limited to Level 3+ connections only. For special EV interconnection situations where  
additional study is required, allow the use of the simplified track process (R460.940).  
4. Reduce the application and interconnection fees for individual customers or small business entities  
to a maximum to encourage DER participation.  
If you have any questions, please feel free to contact me at jmathew1@ford.com, or at 313 805-4121.  
Sincerely,  
Jacob Mathews  
Manager, EV Charging Strategy and Regulations  
Ford Motor Company  
General Offices:  
One Energy Plaza  
Jackson, MI 49201  
LEGAL DEPARTMENT  
SHAUN M. JOHNSON  
Senior Vice President  
and General Counsel  
Tel:  
(517) 788-0550  
Robert W. Beach  
Ian F. Burgess  
Fax: (517) 768-3644  
Don A. D’Amato  
Teri L. Dennings  
Gary A. Gensch, Jr.  
Matthew D. Hall  
Georgine R. Hyden  
Katie M. Knue  
*Washington Office:  
1730 Rhode Island Ave. N.W. Tel:  
Suite 1007  
(202) 778-3340  
MELISSA M. GLEESPEN  
Vice President, Corporate  
Secretary and Chief  
Washington, DC 20036  
Fax: (202) 778-3355  
Compliance Officer  
Robert F. Marvin  
Jason M. Milstone  
Rhonda M. Morris  
Deborah A. Moss*  
Maxwell K. Multer  
Chantez L. Pattman  
Michael C. Rampe  
Scott J. Sinkwitts  
Theresa A.G. Staley  
Janae M. Thayer  
Anne M. Uitvlugt  
Aaron L. Vorce  
Writer’s Direct Dial Number: (517) 788-7107  
Writer’s E-mail Address: ian.burgess@cmsenergy.com  
KELLY M. HALL  
Vice President and Deputy  
General Counsel  
November 1, 2021  
Emerson J. Hilton  
Adam C. Smith  
Bret A. Totoraitis  
Assistant General Counsel  
Ms. Lisa Felice  
Executive Secretary  
Attorney  
Michigan Public Service Commission  
7109 West Saginaw Highway  
Post Office Box 30221  
Lansing, MI 48909  
RE: MPSC Case No. U-20890 – In the matter, on the Commission's own motion, to  
promulgate rules governing electric interconnection and distributed generation and  
to rescind legacy interconnection and net metering rules.  
Dear Ms. Felice:  
Enclosed for electronic filing in the above-captioned proceeding, please find Consumers Energy  
Company’s Comments on Proposed Rule Changes.  
This is a paperless filing and is therefore being filed only in PDF.  
Sincerely,  
Ian F. Burgess  
S T A T E O F M I C H I G A N  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter of the Commission’s own motion, )  
to promulgate rules governing electric  
interconnection and distributed generation  
and to rescind legacy interconnection and  
net metering rules.  
)
)
)
)
)
Case No. U-20890  
CONSUMERS ENERGY COMPANY’S COMMENTS  
ON PROPOSED RULE CHANGES  
I.  
INTRODUCTION  
On September 9, 2021, the Michigan Public Service Commission (“MPSC” or the  
“Commission”) issued its Order and Notice of Hearing in Case No. U-20890 (“September 9, 2021  
Order”) regarding the promulgation of the Interconnection and Distributed Generation Standards  
and the recission of the legacy Electric Interconnection and Net Metering Standards, Mich Admin  
Code, R.460.601 et seq, which were adopted in the May 26, 2009 Order in Case No. U-15787.  
The September 9, 2021 Order, with the proposed rules attached, scheduled a public hearing for  
October 20, 2021, to allow presentations by interested persons and set a final deadline for written  
comments at 5:00 pm on November 1, 2021.  
Consumers Energy Company (“Consumers Energy” or the “Company”) has participated  
in ten stakeholder sessions addressing potential Interconnection Rules, and five stakeholder  
meetings addressing potential Distributed Generation rules, hosted by MPSC Staff between  
December 2018 and March 2020, as directed by the Commission in its November 8, 2018 Order  
in Case U-20344. Consumers Energy has provided feedback in response to two draft rule sets in  
strawman proposals on August 28, 2019, and May 1, 2020, respectively.  
1
The comments presented below are provided by the Company in response to the  
Commission’s September 9, 2021 Order. Consumers Energy appreciates the opportunity to  
provide further comments on these standards. The proposed rules attached to the September 9,  
2021 Order will govern certain electric services provided by the Company; therefore, Consumers  
Energy has a direct interest in this proceeding. In filing these comments in response to the most  
recent draft of the proposed Interconnection and Distributed Generation Standards, purusant to the  
September 9, 2021 Order, Consumers Energy reiterates its positions and recommendations  
previously expressed in its comments provided as feedback to strawman proposals on August 28,  
2019, and May 1, 2020, in addition to the comments presented below.  
II.  
COMMENTS  
A.  
R. 460.964 Interconnection Agreement  
Proposed R. 460.964(8) states:  
An applicant shall pay the actual cost of the interconnection  
facilities and distribution upgrades. The cost to the applicant for  
interconnection facilities and distribution upgrades may not exceed  
110% of the estimate without an itemized summary and explanation  
of cost increases being provided to the applicant prior to being  
incurred. The cost may not exceed 125% of the estimate without the  
consent of the applicant prior to the costs being incurred.  
Consumers Energy submits that R 460.964(8), as presently proposed, is problematic.  
Interconnection agreements, as currently constructed, do not address requirements that must be  
satisfied if costs exceed estimates, which could occur due to multiple unforeseen issues, including  
increased cost of material or labor, unexpected construction conditions (rock, wetland, habitats),  
cost of right-of-way or rerouting, or design changes. Consumers Energy suggests cost variability  
be addressed as needed in utility procedures or the utility interconnection agreements themselves  
and not in the interconnection rules. Additionally, R 460.964(8), as currently proposed, does not  
include a timeline by which an applicant must respond and provide consent to a utility prior to the  
2
cost being incurred. Without including a timeline by which the applicant must respond, it is likely  
that delays and disputes associated with communcations with applicants to obtain consent will  
ocurr.  
If the Commission preserves the langauge regarding costs exceeding estimates in the  
proposed rules, the Company proposes that the language below should be adopted to allow for  
mutually agreed upon mediation, if necessary, without an absolute statement dependent on the  
consent of only one party.  
Consumers Energy Proposed alternate R. 460.964(8):  
An applicant shall pay the actual cost of the interconnection  
facilities and distribution upgrades. The cost to the applicant for  
interconnection facilities and distribution upgrades may not exceed  
110% of the estimate without an itemized summary and explanation  
of cost increases being provided at the request of the applicant. If  
the cost exceeds 125% of the estimate then at the request of the  
applicant the utility shall provide further explanation on the  
differences between the cost and the estimate. If informal  
discussions are unsuccessful, then the parties may mutually agree to  
request formal mediation per R 460.906.  
B.  
R. 460.988 Easements and right-of-way  
The present language in Rule 88 stating the applicant is responsible for procurement of  
easements or right-of-way is problematic and is opposite from present practice for Interconnection.  
The utility needs to be responsible for procuring easements or right of way for utility lines it will  
own, while the applicant is responsible for the cost of providing or obtaining easements or right-  
of-way.  
C.  
R 460.982 Modification of the interconnection application  
The present language in Rule 82 assumes that a material modification request contains all  
requisite information for the electric utility to perform their review. Consumers Energy currently  
processes material modifications similar to new application requests involving submittal and  
3
review of an application packet. The Company recommends that the interconnection application  
submittal and review process in Rule 36 be incorporated into this rule.  
D.  
R 460.1006 Distributed generation program application and fees  
In R 460.1006 subsection 2a, the proposed rule states that the electric utility “shall  
complete its review of the distributed generation program application in parallel with processing  
the interconnection application.” Presently, this review is performed sequentially, allowing only  
conforming applications to proceed to program review. The Company has concern with  
performing both reviews in parallel due to concerns over needlessly increasing review volume. In  
the Company’s present process, the interconnection application is reviewed for completeness and  
then sequentially handed off to program review. This allows for only applications with all  
necessary information to be reviewed for program participation and thus reduces the volume of  
work in that area. Requiring the reviews to be performed in parallel would require all applications  
to be reviewed for participation regardless of completeness, which would introduce waste. The  
Company proposes that the language allow for serial processing of the interconnection and  
distributed generation program applications.  
E.  
Business days versus calendar days clarifications  
The Company noticed a few instances where timeframes were listed in “days” instead of  
“business days,” specifically in R 460.918.8a, R 460.918.16, and R 460.956.5a. As such, the rules  
as proposed are not exactly clear as to whether the timeframe is based on calendar days or business  
days. Therefore, the Company recommends that the Commission clarify within the rules that all  
timeframes be specified in business days.  
Respectfully submitted,  
CONSUMERS ENERGY COMPANY  
4
My name is Adam Schaller; I am the Vice President of Lakeshore Die Cast and my comments  
provided below on Case No. U-20890 are based on literature review and my personal  
experience trying to build and interconnect a distributed energy resource at my die casting  
company. My die casting company is located in Baroda, Michigan at 8829 Stevensville-Baroda  
Road in Berrien County. The utility responsible for power supply at my place of business is  
Indiana Michigan Power, subsidiary of American Electric Power. I’ve been at Lakeshore Die Cast  
in a management role since about 2010. In the years between 2010 and 2020 I saw my  
electricity usage rise by 50% and my price per month more than double. Die casting is an energy  
intensive business and utilities represent about 10% of my total costs. As a third generation die  
caster and manufacturer in Michigan, I am always looking for a competitive advantage. I saw  
how my utility cost increased and started investigating ways to slow down or stymie the  
increase. This search is what got me interested in on-site generation, particularly solar. In 2020 I  
installed and connected 150kW AC of generating capacity, the process was straight forward  
under the old interconnection rules. The latest rule set maintains the previous simplicity for this  
size of generator which is great. Over the last year my solar project generated about 25% of my  
total electrical usage and drastically reduced my utility cost. I was so impressed with my solar  
generation that I started down the path to install more generation. This time around I am  
working on a 1.25MW system which when combined with my old system will yield 1.4MW AC  
generation, this is about 2.5 times my current plant yearly demand. I’ve provided this backstory  
and information because it helps explain my current situation and why I’m commenting on this  
case. The new rules don’t do anything to address the confusion involved with trying to install  
solar generation over 150kW in size. The new rules just like old rules say these sized generators  
must be interconnected and give the rules for interconnecting them. This however is only part  
of the battle; the other part of the battle is getting the utility to find a tariff that will work and  
understanding that the utility is required to work with you. I think the new interconnection rule  
set should explicitly spell out that these sized generators are entitled to net metering as  
amended in EPACT (Energy Policy Act of 2005) and are qualified facilities as explained in PURPA  
(Public Utility Regulatory Policies Act). The fact that the old program was called “the net  
metering program” only adds to the confusion because “the net metering program” is not the  
same as net metering. My suggestion is that the commission incorporate a section to just  
explain this or just state what terms a 150kW generating facility that falls outside the distributed  
generation program are entitled to. These being, net metering as explained in EPACT and sale of  
power at full avoided cost as clarified in FERC order number 872 and outlined in PURPA.  
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'24:398ꢂ3++*+*ꢂ'3*ꢂ'9ꢂ9.+ꢂ9/2+ꢂ/9ꢂ/8ꢂ3++*+*ꢏꢂ"./8ꢂ)4397411'(/1/9>ꢂ/8ꢂ0+>ꢂ94ꢂ)'59:7/3-ꢂ8947'-+ꢂ  
8>89+28Bꢂ(+3+,/98ꢂꢗ1/0+ꢂ8+7;/3-ꢂ5+'0ꢂ14'*ꢐꢏꢂꢆ9ꢂ/8ꢂ'184ꢂ)7/9/)'1ꢂ94ꢂ7+)4-3/?+ꢂ/3ꢂ9.+ꢂ/39+7)433+)9/43ꢂ  
7+;/+<ꢂ574)+88ꢂ(+)':8+ꢂ/9ꢂ)'3ꢂ.+15ꢂ';4/*ꢂ47ꢂ2/9/-'9+ꢂ/25')98ꢂ94ꢂ9.+ꢂ*/897/(:9/43ꢂ8>89+2ꢏꢂ".:8ꢎꢂ  
/39+7)433+)9/43ꢂ7:1+8ꢂ8.4:1*ꢂ89:*>ꢂꢁ!!ꢂ/3ꢂ'ꢂ<'>ꢂ9.'9ꢂ9'0+8ꢂ/394ꢂ'))4:39ꢂ.4<ꢂ9.48+ꢂ8>89+28ꢂ'7+ꢂ  
')9:'11>ꢂ:8+*ꢂ/389+'*ꢂ4,ꢂ'88:2/3-ꢂ/3)477+)91>ꢂ9.+ꢂ+=5479ꢂ4,ꢂ,:11ꢂꢉ'2+51'9+ꢂꢍ'5')/9>ꢂ'9ꢂ'11ꢂ9/2+8ꢏꢂ  
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,4114<ꢂ'8ꢂ*+9'/1+*ꢂ/3ꢂ9.+ꢂꢒꢓ ꢕꢂꢅ4*+1ꢂꢆ39+7)433+)9/43ꢂ :1+8ꢂ,742ꢂꢆ ꢁꢍꢏꢂ"./8ꢂ,4114<8ꢂ-:/*'3)+ꢂ  
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9.+ꢂ/39+7)433+)9/43ꢂ541/)/+8ꢂ94ꢂ:9/1/9>ꢂ574)+*:7+8ꢏꢂ  
ꢀ*2/3/897'9/;+ꢂ7:1+8ꢂ574;/*+ꢂ89'(/1/9>ꢂ'3*ꢂ)+79'/39>ꢂ(>ꢂ574;/*/3-ꢂ9.+ꢂ'-+3)>B8ꢂ<7/99+3ꢂ541/)/+8ꢂ  
9.'9ꢂ.';+ꢂ9.+ꢂ+,,+)9ꢂ4,ꢂ1'<ꢏꢂ".+ꢂꢆ39+7)433+)9/43ꢂ :1+8ꢂ574548+*ꢂ/3ꢂ9./8ꢂ7:1+2'0/3-ꢂ574;/*+ꢂ  
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94ꢂ+=+7)/8+ꢂ9.+/7ꢂ1+-'1ꢂ7/-.98ꢂ:3*+7ꢂꢅ/)./-'3ꢂ1'<ꢎꢂ9.+ꢂꢀ*2/3/897'9/;+ꢂꢋ74)+*:7+ꢂꢀ)9ꢎꢂ'3*ꢂ,+*+7'1ꢂ  
1'<8ꢂ9.'9ꢂ'7+ꢂ'*2/3/89+7+*ꢂ'3*ꢂ+3,47)+*ꢂ(>ꢂ9.+ꢂ'-+3)>ꢏꢂ".+ꢂ2489ꢂ/25479'39ꢂ541/)/+8ꢂ/39+3*+*ꢂ(>ꢂ  
9.+ꢂꢍ422/88/43ꢂ,47ꢂ9.+ꢂ/39+7)433+)9/43ꢂ574)+88ꢂ8.4:1*ꢂ(+ꢂ/3)1:*+*ꢂ/3ꢂ9.+ꢂ7:1+8ꢎꢂ349ꢂ1+,9ꢂ,47ꢂ  
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43ꢂ9.+ꢂ5:(1/)ꢂ'3*ꢂ)7+'9+ꢂ34ꢂ1+-'1ꢂ4(1/-'9/438ꢂ,47ꢂ:9/1/9/+8ꢂ47ꢂ):8942+78ꢏꢂ%./1+ꢂꢘ4/39ꢂꢍꢁꢃ8ꢂ  
7+)4-3/?+ꢂ9.+ꢂ3++*ꢂ94ꢂ('1'3)+ꢂ+3,47)+'(/1/9>ꢂ</9.ꢂ,1+=/(/1/9>ꢎꢂ/3ꢂ57+;/4:8ꢂ)422+398ꢂ<+ꢂ.';+ꢂ  
/*+39/,/+*ꢂ85+)/,/)ꢂ'7+'8ꢂ<.+7+ꢂ/39+7)433+)9/43ꢂ89'3*'7*8ꢂ8.4:1*ꢂ(+ꢂ85+)/,/+*ꢂ/3ꢂ7:1+8ꢂ7'9.+7ꢂ9.'3ꢂ  
'8ꢂ-:/*+1/3+8ꢏꢂ%+ꢂ'184ꢂ+3*478+ꢂ9.+ꢂ574548+*ꢂ).'3-+8ꢂ/3ꢂ9./8ꢂ7+-'7*ꢂ574548+*ꢂ(>ꢂ9.+ꢂꢅ/)./-'3ꢂ  
ꢁ3+7->ꢂꢆ334;'9/43ꢂꢊ:8/3+88ꢂꢍ4:3)/1ꢏꢂ  
ꢀ8ꢂ/8ꢂ+;/*+39ꢂ,742ꢂ9.+ꢂꢍ422/88/43ꢂ!+59+2(+7ꢂꢒꢛꢎꢂꢒꢓ ꢕꢂꢃ7*+7ꢂ/3ꢂꢍ'8+ꢂꢉ4ꢏꢂ#ꢑꢒꢓ ꢝꢛꢎꢂ'ꢂ:9/1/9>B8ꢂ  
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/,ꢂ'ꢂ:9/1/9>ꢂ,'/18ꢂ94ꢂ)4251>ꢂ</9.ꢂ:9/1/9>ꢂ574)+*:7+8ꢎꢂ9.+ꢂꢍ422/88/43ꢂ2'>ꢂ349ꢂ7+1>ꢂ:543ꢂ:9/1/9>ꢂ  
574)+*:7+8ꢂ94ꢂ8:55479ꢂ'ꢂꢍ422/88/43ꢂ*+)/8/43ꢂ94ꢂ')9ꢂ47ꢂ7+,:8+ꢂ94ꢂ')9ꢏꢂꢂ  
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+;41;/3-ꢎꢂ84ꢂ9.+ꢂ,1+=/(/1/9>ꢂ94ꢂ).'3-+ꢂ574)+*:7+8ꢂ94ꢂ'))4224*'9+ꢂ3+<ꢂ9+).3414->ꢂ47ꢂ94ꢂ+3'(1+ꢂ  
247+ꢂ7'5/*ꢂ'*459/43ꢂ4,ꢂ2'70+9ꢂ'3*ꢂ9+).3414-/)'1ꢂ/334;'9/43ꢂ/8ꢂ'ꢂ*+8/7'(1+ꢂ,+'9:7+ꢂ4,ꢂ7:1+8ꢏꢂꢊ:9ꢂ94ꢂ  
9.+ꢂ+=9+39ꢂ5488/(1+ꢎꢂ<+ꢂ+3)4:7'-+ꢂ9.+ꢂꢍ422/88/43ꢂ94ꢂ'*459ꢂ7:1+8ꢂ9.'9ꢂ8+9ꢂ4:9ꢂ9.+ꢂ-+3+7'1ꢂ  
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</9.ꢂ8',+ꢂ'3*ꢂ7+1/'(1+ꢂ45+7'9/43ꢂ4,ꢂ9.+ꢂ-7/*ꢐꢏꢂ  
ꢇ
P.O. Box 11 • Ithaca, Michigan 48847  
989.763.0672 • michiganbiomass.com  
November 1, 2021  
Comment from Michigan Biomass on proposed interconnection rules  
Case No. U-20890  
Michigan Biomass is a coalition of the state’s wood-fire power plants supplying Consumers  
Energy Co. with energy and capacity under existing PURPA power purchase agreements.  
Following are our comments on proposed interconnection rules under case number U-20890.  
Michigan Biomass understands that the proposed interconnection rules in this case are focused on  
new generation systems expected to connect to the grid because of energy policy that went into  
effect in April 2017.  
There are six biomass plants1 in Michigan, between 18 MW and 38 MW in size, that have been  
selling energy and capacity to Consumers Energy under original PURPA contracts signed  
between 1985 and 1994. All are qualified facilities (QFs) under PURPA.  
Michigan Biomass has engaged this rulemaking process since it began in 2018 with Case No. U-  
203442, which initiated the workgroup process to draft strawman proposals for determining what  
constitutes a Legally Enforceable Obligations (LEO) under PURPA, and to establish revised rules  
on interconnection standards and processes to conform with actions by the Federal Energy  
Regulatory Commission.  
Throughout that process, and in formal comment under U-20344, members of the Michigan  
Biomass coalition held concerns that included:  
1. Existing facilities, by virtue of their existing agreements and physical interconnections,  
should not be subject to new interconnection rules intended to manage connection of new  
generation resources, mainly QFs interconnections such as wind, solar and storage resulting  
from changes in Michigan energy policy, utility renewable energy objectives, and FERC  
orders.  
2. The potential cost that new rules might bring to existing, interconnected QFs that have  
limited ability to recover those costs.  
3. Consideration of how the rules would impact existing facilities when existing power purchase  
agreements are renewed or amended.  
Throughout this process Michigan Biomass has maintained these existing facility  
interconnections should be exempt from new rules, and we believe that concern is addressed in  
section R 460.911 of the proposed rules that defines “applicability:”  
1 Cadillac Renewable Energy, Grayling Generating Station, Genesee Power Station, Hillman Power Co.,  
Viking Energy/McBain and Viking Energy/Lincoln  
2 In the matter, on the Commission’s own motion, to promulgate rules governing electric interconnection,  
a legally enforceable obligation, distributed generation, and legacy net metering (April 8, 2018)  
Rule 11. These rules apply to all interconnection applications filed on or after the  
effective date of these rules and interconnection applications filed prior to the effective  
date of these rules that do not have an executed construction or interconnection  
agreement. Interconnection applications with a construction agreement or  
interconnection agreement executed prior to the effective date of these rules are governed  
by their construction or interconnection agreement. (Case No. U-20344)  
Michigan Biomass supports this language in the proposed rules. In our reading of this section,  
these rules would not apply to a facility already interconnected because there would be no  
interconnection application “filed on or before” these rules go into effect, and because these  
facility interconnections are “governed by” interconnection agreements executed prior to the  
effective date of these proposed rules.  
Sincerely,  
Gary Melow, Director  
November 1, 2021  
RE: MPSC Case No. U-20890 - Comments on Draft Interconnection and Distributed  
Generation Standards  
Sunrun is the largest residential solar, storage, and energy management company in  
the United States with over 500,000 customers in 23 states and the District of  
Columbia and Puerto Rico. We see great potential to expand solar and storage access  
more broadly, particularly in the Midwest and especially in Michigan. The need to  
increase access to reliability solutions like solar and storage is needed now more than  
ever, with increased weather-related outages and increased interests in improving  
resiliency for all communities in Michigan.  
However, one of the barriers to solar and storage expansion is the lack of clear,  
transparent, and customer friendly interconnection processes. Michigan can benefit  
from near term business clarity to support resilient, clean distributed energy resources  
to provide customer and grid facing services that lower costs in transitioning to clean  
energy and address needs at the distribution system by alternative means. The  
customer experience in adopting clean energy technologies is crucial to achieving state  
and federal policy goals, but in many ways are unfortunately lacking in the  
interconnection rules as currently proposed.  
While Sunrun has not had the opportunity to participate in discussions that led to the  
most current proposed interconnection rules, we believe it necessary to provide input  
to support and ensure Michigan transitions to the most modern best practices to  
enable optimal solar and storage interconnection today and in the future. Sunrun has  
been active in modernizing interconnection processes and rules change initiatives  
across the country for solar and storage enablement through the utilization of smart  
inverters and inverter certified power controls to improve the interconnection  
experience for the customer and utility. We have proposed limited redline revisions to  
the rule based on best practices in other states. Additionally, and most importantly,  
Sunrun believes a second phase of this multi-year effort is needed to most adequately  
modernize interconnection, distribution planning and utility upgrade process. While  
the majority of future interconnection customers in Michigan can not cost effectively  
add storage today, the use of certified power control systems to limit export or the  
leveraging of advanced grid support functions to avoid upgrades and rapidly  
streamline interconnection will only come to fruition if utilities are engaged through  
595 Market Street, 29th Floor | San Francisco, CA 94105  
smart policy decisions. At minimum, the interconnection rule updates must provide  
real clarity on how inverter power control functions can enable customer savings  
through more cost effective interconnection. The proposed rules provide no clarity in  
this regard and fall significantly short in how other jurisdictions have updated rules to  
provide customer certainty. We respectfully submit the following brief overview of  
areas we highlight for consideration within the proposed rule redline.  
R 460.901a Definitions  
The current definitions provide limited clarity in how certified operational controls and  
the ongoing operating capacity of the distributed energy resource (DER) will be  
documented within the interconnection agreement, for proper technical assessment  
within technical screening process, and for documentation of the incremental impact on  
hosting capacity within distribution planning processes. Customers may utilize  
operational controls to limit export in order to more cost effectively interconnect and  
pass technical screens for customer service and distribution system without upgrade or  
delayed interconnection. Energy storage and certified operational control capabilities  
of inverters has modernized how DERs interact with the customer and grid,  
necessitating the need to expand definitions to enable customers adoption and prevent  
inaccurate technical screening assessment and negative follow through effect on  
hosting capacity.  
R 460.901a UL 1741 Implementation Date  
I commend Michigan for striving to adopt the latest version of UL 1741, although the  
implementation date propoped must be changed in light of the recent release of UL  
1741 Edition 3 on September 28, 20211. Initially, California and other forward looking  
states had planned for an implementation date of January 2022, although it is my  
understanding that following the release of IEEE 1547.1-2020; the Nationally  
Recognized Testing Laboratories (NTRL) identified testing challenges, leading to  
further revisions and creation of UL 1741 Edition 3. Historically, when California and  
Hawaii have implemented new inverter standards, they have allowed for one year of  
lead time for enough inverters to be certified for interconnection. The California Smart  
Inverter Working Group met Oct 28, 2021 to discuss implementation timing, where  
much uncertainty was raised on the length of time to get inverters certified through  
NRTLs. UL 1741 SA inverters are used in California, Hawaii, and other states today  
1 https://standardscatalog.ul.com/ProductDetail.aspx?productId=UL1741  
595 Market Street, 29th Floor | San Francisco, CA 94105  
allowing for utilization of advanced inverter functions and would be a good candidate  
for January 2022 implementation, followed by implementation of UL 1741 edition 3 no  
earlier than January 2023.  
Implementation date aside, there are further implementation considerations that  
Michigan must consider to maximize grid and customer benefit. For example, in Hawaii  
the original voltage and frequency ride through and trip settings implemented with UL  
1741 SA have not changed, but the inverters voltage response settings to local power  
conditions have evolved. With the implementation of UL 1741 SA new DERs were set  
with a constant lagging power factor as an approach to limit voltage rise and avoid  
traditional utility upgrade. Hawaiian Electric’s (HECO) research with National  
Renewable Energy Laboratory (NREL) evolved based on stakeholder input and orders  
from the Hawaii Public Utilities Commission denying blanket activation of the smart  
inverters volt-watt function. HECO continued to work with NREL with the focus of  
avoiding interconnection upgrades without causing excessive customer DER  
curtailment (volt-watt reduces power output (self-curtailment of energy) as voltage  
rises negating the need to utility voltage rise assessment and service upgrades for the  
majority of customers). In rare cases and when utility service infrastructure upgrade is  
truly needed, customer DER curtailment will increase, reducing the DER customers'  
operational benefit of the DER. In these cases the utility will come in after the fact and  
upgrade infrastructure when only truly needed. Consumers are protected from the risk  
of excessive curtailment, utility infrastructure is maximized, customers more cost  
effectively interconnection, and we have processes in place today in Hawaii that allow  
for consumer DER operational protection and instant interconnection for many  
customers following closure of electrical permits without prior notification to Hawaiian  
Electric2.  
R 460.946 Fast Track screening processes  
The Fast Track process from FERC SGIP has been enhanced by numerous states to  
better reflect the technical considerations of small inverter based DERs and limited  
export controls to further streamline the interconnection process. The 15% capacity  
screen within the initial technical review can be very problematic depending on how  
utilities administer the interconnection technical screening process, leading to  
needlessly long and more expensive interconnection processes based on a very  
conservative threshold. To resolve this, I have proposed additional clarity to this initial  
2 https://dms.puc.hawaii.gov/dms/DocumentViewer?pid=A1001001A21H23A83820D00035  
595 Market Street, 29th Floor | San Francisco, CA 94105  
capacity screen based on language specified within the supplemental review screen in  
order to ensure proper incremental assessment of the DER and proposed a deadline of  
January 2023 for the utilities to collect and utilize applicable/coincidental minimum  
loading data within interconnection process. Lack of distribution data can lead to  
improper assessment of the DERs impact on the distribution and to properly assess the  
incremental impact of the DER application, the applicable loading data must not be  
considered as part of the aggregate generation DER that is already reflected within the  
load data. The National Rural Electric Cooperative Association’s PV System Impact  
Guide in my opinion is a good reference for utilities needing help understanding how to  
properly use distribution data within technical screening and study processes3.  
Consistent with other jurisdictions that have updated rules for storage and more  
streamlined interconnection processes, export capacity and the size of the DER should  
facilitate further technical review streamlining. In my opinion, there is no reason for  
Level 1 DERs to ever be required to complete a supplemental review process if  
interconnection is being managed properly.  
R 460.980 Capacity of the DER.  
While I am unclear why section 460.980 is written specific to interconnection  
application requests for an increase in capacity for an existing DER, I recommend the  
language in this section be further clarified and include clear details on how a DER can  
limit export. I find it confusing to state that the application be based on the new  
nameplate capacity of the DER. Using nameplate capacity may be appropriate for  
some DERs, but with customers' adoption of energy storage, the assessment based on  
nameplate capacity necessitated the need to incorporate additional clarity and details  
within the interconnection rule to ensure accurate assessments of the DER within  
technical screening processes. The nameplate capacity of AC coupled storage DERs in  
particular will lead to wildly inaccurate assessment of the application, which will then  
carry over within the utilities hosting capacity tracking process to significantly decrease  
hosting capacity at the customer service and distribution system. States that have  
updated their interconnection rules have led to the evolution of varying new terms to  
more clearly explain the basis for DER assessment. In Colorado the term ongoing  
operating capacity was created and recommended to replace nameplate capacity  
within the first sentence of section 460.980. In addition allowances for limited and  
3
https://www.cooperative.com/programs-services/bts/Documents/SUNDA/NRECA%20-%20SUNDA%20Im  
pact%20Guide-v3%20final.pdf  
595 Market Street, 29th Floor | San Francisco, CA 94105  
non-export must be more clearly expressed within the rule and it may be appropriate  
to incorporate within section 460.980.  
R 460.1001 Application process (Export limitation)  
Section 460.1001 specifies a non export use case for energy storage, for which I see no  
need for. The purpose of interconnection rule update is to allow for a transparent  
process for proper assessment of the DERs impact on the utility service connect and  
distribution system. While we must ensure within the rule update that there is  
sufficient clarity and information for proper utility assessment, we must not limit  
storage to non export, as this should be a customer choice within the interconnection  
process.  
Sunrun appreciates the opportunity to provide the comments in support of the  
Commission's goal to modernize Michigan's interconnection rules and we would be  
happy to discuss our concerns and recommendations, if helpful.  
/s/ Steven Rymsha  
Steven Rymsha  
Director Grid Solutions, Public Policy  
Sunrun Inc.  
Phone (808) 220-7377  
Email:steven.rymsha@sunrun.com  
595 Market Street, 29th Floor | San Francisco, CA 94105  
DEPARTMENT OF LICENSING AND REGULATORY AFFAIRS  
PUBLIC SERVICE COMMISSION  
INTERCONNECTION AND DISTRIBUTED GENERATION STANDARDS  
Filed with the secretary of state on  
These rules take effect immediately upon filing with the secretary of state unless adopted  
under section 33, 44, or 45a(9) of the administrative procedures act of 1969, 1969 PA  
306, MCL 24.233, 24.244, or 24.245a. Rules adopted under these sections become  
effective 7 days after filing with the secretary of state.  
(By authority conferred on the public service commission by section 7 of 1909 PA 106,  
MCL 460.557, section 5 of 1919 PA 419, MCL 460.55, sections 4, 6, and 10e of 1939 PA  
3, MCL 460.4, 460.6, and 460.10e, and section 173 of the clean and renewable energy  
and energy waste reduction act, 2008 PA 295, MCL 460.1173)  
R 460.901a, R 460.901b, R 460.902, R 460.904, R 460.906, R 460.908, R 460.910, R  
460.911, R 460.914, R 460.916, R 460.918, R 460.920, R 460.922, R 460.924, R  
460.926, R 460.928, R 460.930, R 460.932, R 460.934, R 460.936, R 460.938, R  
460.940, R 460.942, R 460.944, R 460.946, R 460.948, R 460.950, R 460.952, R  
460.954, R 460.956, R 460.958, R 460.960, R 460.962, R 460.964, R 460.966, R  
460.968, R 460.970, R 460.974, R 460.976, R 460.978, R 460.980, R 460.982, R  
460.984, R 460.986, R 460.988, R 460.990, R 460.991, R 460.992, R 460.1001, R  
460.1004, R 460.1006, R 460.1008, R 460.1010, R 460.1012, R 460.1014, R 460.1016, R  
460.1018, R 460.1020, R 460.1022, R 460.1024, and R 460.1026 are added to the  
Michigan Administrative Code, as follows:  
PART 1. GENERAL PROVISIONS  
R 460.901a Definitions; A-I.  
Rule 1a. As used in these rules:  
(a) “AC” means alternating current at 60 Hertz.  
(b) “Affected system” means another electric utility’s distribution system, a municipal  
electric utility’s distribution system, the transmission system, or transmission system-  
connected generation which may be affected by the proposed interconnection.  
(c) “Affiliate” means that term as defined in R 460.10102(1)(a).  
(d) “Alternative electric supplier” means that term as defined in section 10g of 1939 PA  
3, MCL 460.10g.  
(e) “Alternative electric supplier distributed generation program plan” means a  
document supplied by an alternative electric supplier that provides detailed information to  
an applicant about the alternative electric supplier's distributed generation program.  
July 7, 2021  
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(f) “Alternative electric supplier legacy net metering program plan” means a document  
supplied by an alternative electric supplier that provides detailed information to an  
applicant about the alternative electric supplier's legacy net metering program.  
(g) “Applicant” means the person or entity submitting an interconnection application, a  
legacy net metering program application, or a distributed generation program application.  
An applicant is not required to be an existing customer of an electric utility. An electric  
utility is considered an applicant when it submits an interconnection application for a  
DER that is not a temporary DER.  
(h) “Application” means an interconnection application, a legacy net metering program  
application, or a distributed generation program application.  
(i) “Area network” means a location on the distribution system served by multiple  
transformers interconnected in an electrical network circuit.  
(j) “Business day” means Monday through Friday, starting at 12:00:00 a.m. and ending  
at 11:59:59 p.m., excluding the following holidays: New Year’s Day, Martin Luther King  
Jr. Day, Presidents Day, Memorial Day, Independence Day, Labor Day, Veterans Day,  
Thanksgiving Day, Christmas Eve, Christmas Day, and New Year’s Eve. Election Day,  
the day after Thanksgiving, and any day that meets the criteria of catastrophic conditions  
as defined in R 460.702(f) may also be excluded.  
(k) “Certified” means an inverter-based system has met acceptable safety and reliability  
standards by a nationally recognized testing laboratory in conformance with IEEE  
1547.1-2020 and the UL 1741 2020 edition except that prior to January 1, 2022,  
inverter-based systems which conform to the UL 1741 January 28, 2010 edition are  
acceptable.  
(l) “Commission” means the Michigan public service commission.  
(m) “Commissioning test” means the test and verification procedure that is performed  
on a device or combination of devices forming a system to confirm that the device or  
system, as designed, delivered, and installed, meets the interconnection and  
interoperability requirements of IEEE 1547-2018. A commissioning test must include  
visual inspections and may include, as applicable, an operability and functional  
performance test and functional tests to verify interoperability of a combination of  
devices forming a system.  
(n) “Conforming” means the information in an interconnection application is consistent  
with the general principles of distribution system operation and DER characteristics.  
(o) “Construction agreement” means an agreement, pursuant to the interconnection  
standards superseded by R 460.901a to R 460.992, between an interconnection customer  
and an electric utility that contains timelines and cost estimates for construction of  
facilities and distribution upgrades to interconnect a DER into the distribution system,  
and identifies design, procurement, installation, and construction requirements associated  
with installation of the DER.  
(p) “Customer” means a person or entity who receives electric service from an electric  
utility’s distribution system or a person who participates in a legacy net metering or  
distributed generation program through an alternative electric supplier or electric utility.  
(q) “DC” means “direct current.”  
(r) “Distributed energy resource” or “DER” means a source of electric power and its  
associated facilities that is connected to a distribution system. DER includes both  
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generators and energy storage devices capable of exporting active power to a distribution  
system.  
(s) “Distributed generation program” means the distributed generation program  
approved by the commission and included in an electric utility’s tariff pursuant to section  
6a(14) of 1939 PA 3, MCL 460.6a, or established in an alternative electric supplier  
distributed generation program plan.  
(t) “Distribution system” means the structures, equipment, and facilities owned and  
operated by an electric utility to deliver electricity to end users, not including  
transmission and generation facilities that are subject to the jurisdiction of the federal  
energy regulatory commission.  
(u) “Distribution system study” means a study, conducted under the interconnection  
standards superseded by R 460.901a to R 460.992, that determined whether a distribution  
system upgrade was needed to accommodate the proposed project and the cost of a  
distribution upgrade if required.  
(v) “Distribution upgrades” mean the additions, modifications, or improvements to the  
distribution system necessary to accommodate a DER’s connection to the distribution  
system.  
(w) “Electric utility” means any person or entity whose rates are regulated by the  
commission for selling electricity to retail customers in this state. For purposes of R  
460.901a through R 460.992 only, “electric utility” includes cooperative electric utilities  
that are member regulated as provided in section 4 of the electric cooperative  
member-regulation act, 2008 PA 167, MCL 460.34.  
(x) “Electrically coincident” means that 2 or more proposed DERs associated with  
pending interconnection applications have operating characteristics and nameplate  
capacities which require that distribution upgrades will be necessary if the DERs are  
installed in electrical proximity with each other on a distribution system.  
(y) “Electrically remote” means a proposed DER is not electrically coincident with a  
DER that is associated with a pending interconnection application.  
(z) “Eligible electric generator” means a methane digester or renewable energy system  
with a generation capacity limited to a customer’s electric need and that does not exceed  
either of the following:  
(i) 150 kWac of aggregate generation at a single site for a renewable energy system.  
(ii) 550 kWac of aggregate generation at a single site for a methane digester.  
(aa) “Energy storage device” means a device that captures energy produced at one time,  
stores that energy for a period of time, and delivers that energy as electricity for use at a  
future time. For purposes of these rules, an energy storage device may be considered a  
DER.  
(bb) “Engineering review” means a study, conducted under the interconnection  
standards superseded by R 460.901a to R 460.992, that determined the suitability of the  
interconnection equipment including any safety and reliability complications arising from  
equipment saturation, multiple technologies, and proximity to synchronous motor loads.  
(cc) “Facilities study” means a study to specify and estimate the cost of the equipment,  
engineering, procurement, and construction work if distribution upgrades or  
interconnection facilities are required.  
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(dd) “Fast track” means the procedure used for evaluating a proposed interconnection  
that makes use of screening processes, as described in R 460.944 to R 460.950.  
(ee) “Force majeure event” means an act of God; labor disturbance; act of the public  
enemy; war; insurrection; riot; fire, storm, or flood; explosion, breakage, or accident to  
machinery or equipment; an emergency order, regulation or restriction imposed by  
governmental, military, or lawfully established civilian authorities; or another cause  
beyond a party’s control. A force majeure event does not include an act of negligence or  
intentional wrongdoing.  
(ff) “Full retail rate” means the power supply and distribution components of the cost of  
electric service. Full retail rate does not include a system access charge, service charge,  
or other charge that is assessed on a per meter, premise, or customer basis.  
(gg) “Good standing” means an applicant has paid in full all undisputed bills rendered  
by the interconnecting electric utility and any alternative electric supplier in a timely  
manner and none of these bills are in arrears.  
(hh) “Governmental authority” means any federal, state, local, or other governmental  
regulatory or administrative agency, court, commission, department, board, or other  
governmental subdivision, legislature, rulemaking board, tribunal, or other governmental  
authority having jurisdiction over the parties, their respective facilities, or the respective  
services they provide, and exercising or entitled to exercise any administrative, executive,  
police, or taxing authority or power; provided, however, that this term does not include  
the applicant, interconnection customer, electric utility, or any affiliate thereof.  
(ii) “GPS” means global positioning system.  
(jj) “Grid network” means a configuration of a distribution system or an area of a  
distribution system in which each customer is supplied electric energy at the secondary  
voltage by more than 1 transformer.  
(kk) “High voltage distribution” means those parts of a distribution system that operate  
within a voltage range specified in the electric utility’s interconnection procedures. For  
purposes of these rules, the term “subtransmission” means the same as high voltage  
distribution.  
(ll) “IEEE” means institute of electrical and electronics engineers.  
(mm) “IEEE 1547-2018” means “IEEE Standard for Interconnection and  
Interoperability of Distributed Energy Resources with Associated Electric Power Systems  
Interfaces,” as adopted by reference in R 460.902.  
(nn) “IEEE 1547.1-2020” means IEEE “Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces,” as adopted by reference in R 460.902.  
(oo) “Independent system operator” means an independent, federally-regulated entity  
established to coordinate regional transmission in a non-discriminatory manner and to  
ensure the safety and reliability of the transmission and distribution systems.  
(pp) “Initial review” means the fast track initial review screens described in R 460.946.  
(qq) “Interconnection” means the process undertaken by an electric utility to construct  
the electrical facilities necessary to connect a DER with a distribution system so that  
parallel operation can occur.  
(rr) “Interconnection agreement” means an agreement containing the terms and  
conditions governing the electrical interconnection between the electric utility and the  
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applicant or interconnection customer. Where construction of interconnection facilities or  
distribution upgrades are necessary, the agreement shall specify timelines, cost estimates,  
and payment milestones for construction of facilities and distribution upgrades to  
interconnect a DER into the distribution system, and shall identify design, procurement,  
installation, and construction requirements associated with installation of the DER.  
Standard level 1, 2, and 3 interconnection agreements and level 4 and 5 interconnection  
agreements are types of interconnection agreements.  
(ss) “Interconnection coordinator” means a person or persons designated by the electric  
utility who shall serve as the point of contact from which general information on the  
application process and on the affected system or systems can be obtained through  
informal request by the applicant or interconnection customer.  
(tt) “Interconnection customer” means the person or entity, which may include the  
electric utility, responsible for ensuring a DER is operated and maintained in compliance  
with all local, state, and federal laws, as well as with all rules, standards, and  
interconnection procedures.  
(uu) “Interconnection facilities” mean any equipment required for the sole purpose of  
connecting a DER with a distribution system.  
(vv) “Interconnection procedures” mean the requirements that govern project  
interconnection adopted by each electric utility and approved by the commission.  
R 460.901b Definitions; J-Z.  
Rule 1b. As used in these rules:  
(a) “kW” means kilowatt.  
(b) “kWac” means the electric power, in kilowatts, associated with the alternating  
current output of a DER at unity power factor.  
(c) “kWh” means kilowatt-hours.  
(d) “Legacy net metering program” means the true net metering or modified net  
metering programs in place prior to commission approval of a distributed generation  
program tariff pursuant to section 6a(14) of 1939 PA 3, MCL 460.6a, and prior to the  
establishment of an alternative electric supplier distributed generation plan.  
(e) “Level 1” means a certified project of 20 kWac or less.  
(f) “Level 2” means a certified project of greater than 20 kWac and not more than 150  
kWac.  
(g) “Level 3” means a project of 150 kWac or less that is not certified, or a project  
greater than 150 kWac and not more than 550 kWac.  
(h) “Level 4” means a project of greater than 550 kWac and not more than 1 MWac.  
(i) “Level 5” means a project of greater than 1 MWac.  
(j) “Level 4 and 5 interconnection agreement” means an interconnection agreement  
applicable to level 4 and 5 interconnection applications.  
(k) “Low voltage distribution” means those parts of a distribution system that operate  
with a voltage range specified in the electric utility’s interconnection procedures.  
(l) “Mainline” means a conductor that serves as the three-phase backbone of a low  
voltage distribution circuit.  
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(m) “Material modification” means a modification to the DER nameplate rating,  
electrical size of components, bill of materials, machine data, equipment configuration, or  
the interconnection site of the DER at any time after receiving notification by the electric  
utility of a complete interconnection application. For the proposed modification to be  
considered material, it shall have been reviewed and been determined to have or  
anticipated to have a material impact on 1 or more of the following:  
(i) The cost, timing, or design of any equipment located between the point of common  
coupling and the DER.  
(ii) The cost, timing, or design of any other application.  
(iii) The electric utility’s distribution system or an affected system.  
(iv) The safety or reliability of the distribution system.  
(n) “Methane digester” means a renewable energy system that uses animal or  
agricultural waste for the production of fuel gas that can be burned for the generation of  
electricity or steam.  
(o) “Modified net metering” means an electric utility billing method that applies the  
power supply component of the full retail rate to the net of the bidirectional flow of kWh  
across the customer interconnection with the electric utility’s distribution system during a  
billing period or time-of-use pricing period.  
(p) “MW” means megawatt.  
(q) “MWac” means the electric power, in megawatts, associated with the alternating  
current output of a DER at unity power factor.  
(r) “Nameplate capacity” means the maximum active power, in kWac or MWac, at  
which a DER is capable of sustained operation.  
(s) “Nameplate rating” means all of the following at which a DER is capable of  
sustained operation:  
(i) Nominal voltage (V).  
(ii) Current (A).  
(iii) Maximum active power (kWac).  
(iv) Apparent power (kVA).  
(v) Reactive power (kvar).  
(t) “Nationally recognized testing laboratory” means any testing laboratory recognized  
by the accreditation program of the United States Department of Labor Occupational  
Safety and Health Administration.  
(u) “Network protector” means those devices associated with a secondary network used  
to automatically disconnect a transformer when reverse power flow occurs.  
(v) “Non-export track” means the procedure for evaluating a proposed interconnection  
that will not inject electric energy into an electric utility’s distribution system, as  
described in R 460.942.  
(w) “Parallel operation” means the operation, for longer than 100 milliseconds, of a  
DER while connected to the energized distribution system.  
(x) “Party” or “parties” means an electric utility, applicant, or interconnection customer.  
(y) “Point of common coupling” means the point where the DER connects with the  
electric utility’s distribution system.  
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(z) “Radial supply” means a configuration of a distribution system or an area of a  
distribution system in which each customer can only be supplied electric energy by 1  
substation transformer and distribution line at a time.  
(aa) “Readily available” means no creation of data is required, and little or no  
computation or analysis of data is required.  
(bb) “Reasonable efforts” mean, with respect to an action required to be attempted or  
taken by a party under these interconnection rules, efforts that are as timely as possible  
and consistent with those a party would take to protect its own interests.  
(cc) “Regional transmission operator” means a voluntary organization of electric  
transmission owners, transmission users, and other entities approved by the federal  
energy regulatory commission to efficiently coordinate electric transmission planning,  
expansion, operation, and use on a regional and interregional basis.  
(dd) “Renewable energy credit” means a credit granted pursuant to the commission's  
renewable energy credit certification and tracking program in section 41 of the clean and  
renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1041.  
(ee) “Renewable energy resource” means that term as defined in section 11(i) of the  
clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL  
460.1011.  
(ff) “Renewable energy system” means that term as defined in section 11(k) of the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1011.  
(gg) “Secondary network” means those areas of a distribution system that operate at a  
secondary voltage level and are networked.  
(hh) “Simplified track” means the procedure for evaluating a level 1 or level 2 proposed  
interconnection, as described in R 460.940.  
(ii) “Site” means a contiguous site, regardless of the number of meters at that site. A  
site that would be contiguous but for the presence of a street, road, or highway is  
considered to be contiguous for the purposes of these rules.  
(jj) “Spot network” means a location on the distribution system that uses 2 or more  
inter-tied transformers to supply an electrical network circuit, such as a network circuit in  
a large building.  
(kk) “Standard level 1, 2, and 3 interconnection agreement” means the statewide  
interconnection agreement approved by the commission and applicable to levels 1, 2 and  
3 interconnection applications.  
(ll) “Study track” means the procedure used for evaluating a proposed interconnection  
as described in R 460.952 to R 460.962.  
(mm) “Supplemental review” means the fast track supplemental review screens  
described in R 460.950.  
(nn) “System impact study” means a study to identify and describe the impacts to the  
electric utility’s distribution system that would occur if the proposed DER were  
interconnected exactly as proposed and without any modifications to the electric utility’s  
distribution system. A system impact study also identifies affected systems.  
(oo) “Temporary DER” means a DER that is installed on the distribution system by the  
electric utility with the intention of not operating at the site permanently.  
(pp) “Transition batch” means the group of interconnection applications processed  
pursuant to R 460.918.  
8
(qq) “True net metering” means an electric utility billing method that applies the full  
retail rate to the net of the bidirectional flow of kWh across the customer interconnection  
with the electric utility’s distribution system, during a billing period or time-of-use  
pricing period.  
(rr) “UL” means underwriters laboratory.  
(ss) “UL 1741” means the August 3, 2020 revision of “Standard for Inverters,  
Converters, Controllers and Interconnection System Equipment for Use With Distributed  
Energy Resources,” as adopted by reference in R 460.902.  
R 460.902 Adoption of standards by reference.  
Rule 2. (1) The standards specified in these rules are adopted by reference as follows:  
(a) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, August 3, 2020 revision,  
is available from Underwriters Laboratories at the internet website:  
https://standardscatalog.ul.com/Catalog.aspx at a cost of $395.00 at the time of  
adoption of these rules.  
(b) ANSI C84.1 – 2016 Electric Power Systems and Equipment – Voltage Ratings (60  
Hz), June 9, 2016, is available from the American National Standards Institute, Inc. at the  
internet website https://webstore.ansi.org/ at a cost of $111.24 at the time of adoption of  
these rules.  
(c) The following standards adopted by reference are available from IEEE at the  
internet website https://standards.ieee.org at the time of adoption of these rules.  
(i) The IEEE 1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating  
Installations on Power Systems, October 30, 2015, is available at a cost of $99.00 -  
$147.00 at the time of adoption of these rules.  
(ii) The IEEE 1547 - 2018, IEEE Standard for Interconnection and Interoperability of  
Distributed Energy Resources with Associated Electric Power System Interfaces, April 6,  
2018, is available at a cost of $149.00 - $224.00 at the time of adoption of these rules.  
(iii) The IEEE 1547.1-2020 IEEE Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces, May 21, 2020, is available at a cost of $197.00 - $296.00 at the  
time of adoption of these rules.  
(iv) The IEEE 519-2014 IEEE Recommended Practice and Requirements for  
Harmonic Control in Electric Power Systems, June 11, 2014, is available at a cost of  
$52.00 - $66.00 at the time of adoption of these rules.  
(2) The commission has copies of the standards specified in subrule (1) of this rule  
available for review at its offices located at 7109 W. Saginaw Hwy., Lansing, Michigan  
48917-1120. The mailing address is Michigan Public Service Commission, P.O. Box  
30221, Lansing, Michigan 48909-0221.  
R 460.904 Informal mediation.  
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Rule 4. (1) The parties shall attempt to resolve all disputes arising out of the  
interconnection process, as defined by R 460.901a through R 460.992, according to the  
provisions of this rule.  
(2) Prior to formal mediation under R 460.906, the parties shall attempt to resolve any  
conflict without commission intervention through direct discussion and informal  
negotiation.  
(3) In the event that parties are unable to resolve the dispute privately, the parties may,  
by mutual agreement, make a written request for informal mediation to the commission  
staff. The informal mediation shall be conducted by an interconnection ombudsperson  
who shall be a member of the commission staff and designated by the commission. Both  
parties may choose to have attorneys or appropriate representation present.  
(4) During informal mediation, the parties shall discuss relevant facts pertaining to the  
dispute and the relief being sought. The interconnection ombudsperson and relevant  
commission staff shall be present to facilitate the discussion and provide guidance among  
the parties. Parties shall operate in good faith and use best efforts to resolve the dispute.  
(5) If a resolution is reached by the end of the meeting or meetings, the parties may draft  
a resolution of the dispute.  
(6) If the parties reach impasse and are unable to resolve the dispute, the parties shall  
proceed to the formal mediation process described in R 460.906.  
R 460.906 Formal mediation.  
Rule 6. (1) If the parties have been unable to resolve a dispute through the informal  
mediation process under R 460.904, the parties shall then attempt to resolve the dispute in  
the following manner:  
(a) The complaining party shall file a written notice of dispute with the commission.  
The notice of dispute must state the specific grounds for the dispute, sufficient facts to  
support the allegations, the relief requested, and must contain all information, testimony,  
exhibits, or other documents and information within the party’s possession on which the  
party intends to rely to support the party’s position.  
(b) The complaining party shall give notice that it is invoking the procedures in this  
rule. The complaining party shall send the notice to the non-complaining party’s email  
address and file the notice with the commission.  
(c) The non-complaining party shall acknowledge the notice of dispute within 10  
business days of its receipt and identify a representative with the authority to make  
decisions on its behalf with respect to the dispute.  
(d) An administrative law judge shall serve as the mediator in these proceedings. The  
administrative law judge may request and receive assistance from commission staff.  
(e) Within 60 business days from the date the non-complaining party acknowledges the  
dispute, the mediator shall issue a recommended settlement.  
(f) Within 5 business days after the date the recommended settlement is issued, each  
party shall file with the commission a written acceptance or rejection of the  
recommended settlement. If the parties accept the recommendation, then the  
recommendation shall become an order. If a party rejects or fails to respond within 5  
10  
business days to the recommended settlement, then the dispute may proceed to a  
contested case hearing before the commission as provided in R 792.10415.  
(2) Nothing in these rules precludes a disputing party from filing a formal complaint  
with the commission, either instead of or after pursuing informal mediation or formal  
mediation pursuant to these rules.  
(3) The initiation of any form of dispute resolution by a party tolls any applicable  
deadlines under these rules until the dispute is resolved.  
R 460.908 Appointment of experts.  
Rule 8. (1) If a complaint is filed against an electric utility regarding a technical issue,  
the commission may, at its discretion, appoint 1 to 3 independent experts to investigate  
the complaint and report findings to the commission.  
(2) The experts shall submit a report to the commission with the results and conclusions  
of their inquiry and may suggest corrective measures for resolving the complaint. The  
reports of the experts must be received in evidence and the experts made available for  
cross examination by the parties at any hearing.  
(3) The reasonable expenses of experts appointed pursuant to subrule (1) of this rule,  
including a reasonable hourly fee or fee determined by the commission, must be  
submitted by these experts to the commission for approval and, if approved, must be  
funded under subrule (4) of this rule.  
(4) An electric utility or alternative electric supplier shall reimburse the experts  
appointed by the commission for the reasonable expenses incurred in the course of  
investigating the complaint.  
R 460.910 Waivers.  
Rule 10. An electric utility, customer, alternative electric supplier, applicant, or  
interconnection customer may apply to the commission for a waiver from 1 or more  
provisions of these rules and may request expeditious processing. The commission may  
grant a waiver upon a showing of good cause and a finding that the waiver is in the public  
interest.  
PART 2. INTERCONNECTION STANDARDS  
R 460.911 Applicability.  
Rule 11. These rules apply to all interconnection applications filed on or after the  
effective date of these rules and interconnection applications filed prior to the effective  
date of these rules that do not have an executed construction or interconnection  
agreement. Interconnection applications with a construction agreement or  
interconnection agreement executed prior to the effective date of these rules are governed  
by their construction or interconnection agreement.  
R 460.914 Transition non-study group.  
11  
Rule 14. (1) Interconnection applications that were filed before the effective date of  
these rules and that do not meet the eligibility criteria for transition batch study must be  
placed into the transition non-study group.  
(2) An electric utility shall determine whether an interconnection application in the  
transition non-study group is eligible to go through the simplified track, non-export track,  
or fast track within 30 business days of the effective date of these rules. Within 30  
business days of making the eligibility determination, an electric utility shall commence  
processing the interconnection application according to the applicable timelines in these  
rules.  
(3) An electric utility shall process incomplete or non-conforming interconnection  
applications according to R 460.936(7)(a) and (b).  
R 460.916 Legacy applications.  
Rule 16. (1) For applicants with interconnection applications that have complete  
distribution system studies and that have entered into a construction or interconnection  
agreement with an electric utility as of the effective date of these rules, the  
interconnection must be completed according to existing contractual arrangements.  
(2) For applicants that have distribution system studies which were completed by an  
electric utility within the 6 months prior to the effective date of these rules, but have not  
entered into a construction or interconnection agreement with an electric utility as of the  
effective date of these rules, the interconnection application must proceed to an  
interconnection agreement under R 460.964.  
(3) For applicants that have distribution system studies that were conducted and  
completed more than 6 months before the effective date of these rules, the electric utility  
may require a facilities study within the transition batch upon a showing that a new study  
is necessary based on changed circumstances affecting the location of interconnection.  
R 460.918 Transition batch study process.  
Rule 18. (1) An electric utility shall begin its transition batch 80 business days after the  
effective date of these rules.  
(2) Interconnection applications are eligible to join the transition batch if all of the  
following requirements are met:  
(a) The application does not qualify for simplified track, non-export track, or fast track.  
(b) The application was accepted at any time prior to the start of the transition batch,  
including prior to the effective date of these rules.  
(c) A distribution study on the interconnection application was not completed at any  
time prior to the effective date of these rules, or a distribution study was completed more  
than 6 months before the effective date of these rules and an electric utility decided a  
facilities study was necessary pursuant to R 460.916(3).  
(3) An applicant with an eligible interconnection application pursuant to subrule (2) of  
this rule may join the transition batch by signing a transition batch agreement and paying  
any required fees before the start of the transition batch.  
12  
(4) Pre-application reports may not be required for interconnection applications  
accepted before the effective date of these rules.  
(5) If an applicant with an interconnection application that is pending as of the effective  
date of these rules and that is otherwise eligible to join the transition batch has not  
submitted a complete and conforming application, an electric utility shall process the  
incomplete or non-conforming interconnection application according to R 460.936(7)(a)  
and (b). If the interconnection application is not deemed complete and conforming prior  
to an electric utility beginning its interconnection studies, the electric utility shall  
determine whether the interconnection application may be included in the transition batch  
study.  
(6) The interconnection applications in the transition batch must be studied as a group  
by an electric utility. DERs in the transition batch that are electrically remote may be  
studied on an expedited schedule, generally in the order the interconnection applications  
were deemed complete, but this expedited scheduling may not cause unreasonable delays  
in the evaluation of the other DERs in the transition batch.  
(7) An electric utility shall process the transition batch and provide facilities study  
results to interconnection applicants within 1 year of the start date. The start date for the  
transition batch must be specified in an electric utility’s draft interconnection procedures  
and published on an electric utility’s public website.  
(8) An electric utility shall offer to hold a scoping meeting, either in-person or via  
telecommunications, with every applicant in the transition batch. The scoping meetings  
must meet the following requirements:  
(a) All meetings must, to the extent feasible, take place within the first 30 days of the  
transition batch.  
(b) An electric utility shall not begin studies within the transition batch until it has held  
a scoping meeting with every applicant that had agreed to participate in a meeting. An  
electric utility may begin the batch study if 1 or more applicants is unreasonably delaying  
a meeting.  
(c) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting. An electric utility may meet with  
multiple applicants in the same meeting if agreed to by the electric utility and all the  
applicants that will attend the meeting.  
(d) During the scoping meeting, an electric utility shall identify and communicate to  
each applicant the studies it plans to perform and provide the cost of the transition batch  
study using either fees that comply with R 460.926, or, if interconnection procedures  
have been approved by the commission, fees that comply with the interconnection  
procedures. The cost estimate must assume that all applicants will stay in the transition  
batch throughout the batch study.  
(9) The transition batch process must include a system impact study and a facilities  
study. An electric utility may specify additional studies it may perform on the transition  
batch in its interconnection procedures.  
(10) Electrically coincident DERs within the transition batch are considered to have  
equal priority with each other.  
(11) An electric utility shall comply with R 460.960(1) and (2) when conducting a  
system impact study. However, applicants with interconnection applications that have  
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had an engineering review completed within the 6 months prior to the effective date of  
these rules may not be required to pay for a new system impact study.  
(12) An electric utility shall comply with R 460.962(1) when conducting a facilities  
study.  
(13) An electric utility shall provide written study results to each applicant at the  
completion of each study during the transition batch. An electric utility shall offer to  
hold at least 1 conference call with each transition batch applicant at the completion of  
each study. An electric utility may choose to group the consultation regarding multiple  
projects by 1 applicant and its affiliates into the same conference call. This conference  
call must provide a summary of outcomes and respond to questions from applicants.  
Where possible, conferences regarding the study results should be held within 30  
business days following completion of the study.  
(14) Within 40 business days following completion of the study, an applicant shall  
choose either to continue in the transition batch or withdraw. The fee for the next study  
in the transition batch is due by the end of the 40 business day period, unless extended by  
the electric utility. Applicants that withdraw from the transition batch may reapply with a  
new interconnection application.  
(15) Applicants may reduce the capacity of the DER by up to 20% during the decision  
period between studies, including up to and through the conclusion of the system impact  
study. If an applicant wants to increase the capacity of the DER by any amount or  
decrease the capacity of the DER by more than 20%, an electric utility may require the  
applicant to submit a new interconnection application and pay the appropriate fees.  
(16) Within 45 days of receiving the final transition batch study report, an applicant  
shall notify the electric utility whether it intends to proceed to an interconnection  
agreement pursuant to R 460.964 or withdraw. Failure to notify an electric utility within  
the required time period shall result in the interconnection application being withdrawn.  
(17) Under circumstances where an interconnection application is delayed due to an  
affected system issue, informal mediation pursuant to R 460.904, formal mediation  
pursuant to R 460.906, or a complaint, other interconnection applications in the transition  
batch must continue to progress. If feasible, due to the status of the transition batch  
study, the delayed interconnection application may rejoin the transition batch study after  
the affected system issue is resolved. An interconnection application that is the subject of  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint, may also rejoin the batch study at a later date, if feasible, due to the status of  
the batch study.  
(18) A transition batch study is considered complete 45 business days after all transition  
batch applicants, except those applicants whose DERs are still causing unresolved  
affected system issues, pursuing informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or a complaint, have withdrawn, or have received a  
final transition batch study report.  
R 460.920 Electric utility interconnection procedures.  
Rule 20. (1) An electric utility shall file applications for approval of interconnection  
procedures and forms within 30 business days of the effective date of these rules.  
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(2) The commission shall issue its order approving, rejecting, or modifying the proposed  
interconnection procedures and forms within 360 days of the effective date of these rules.  
If the commission finds the procedures and forms proposed by the electric utility to be  
inadequate or unacceptable, the commission may either adopt procedures and forms  
proposed by another party in the proceeding or modify and accept the procedures and  
forms proposed by the electric utility.  
(3) Until the commission accepts, rejects, or modifies an electric utility’s  
interconnection procedures and forms, the electric utility may use the proposed  
interconnection procedures and forms when processing interconnection applications with  
the exception of fixed fees and fee caps. An electric utility shall only charge fees that  
comply with the requirements of R 460.926 until the commission accepts, rejects, or  
modifies the proposed interconnection procedures and forms.  
(4) Two or more electric utilities may file a joint application proposing interconnection  
procedures for use by the joint applicants. The proposed interconnection procedures must  
ensure compliance with these rules.  
(5) The proposed interconnection procedures must, at a minimum, include all of the  
following:  
(a) All necessary applications, forms, and relevant template agreements.  
(b) A schedule of all applicable fixed fees and fee caps.  
(c) Voltage ranges for high voltage distribution and low voltage distribution.  
(d) Required initial review screens.  
(e) Required supplemental review screens.  
(f) The process for conducting system impact studies and facilities studies on DERs  
when there is an affected system issue.  
(g) Testing and certification requirements of DER telecommunications, cybersecurity,  
data exchange, and remote control operation.  
(h) Parallel operation requirements.  
(i) A method to estimate the expected annual kWh output of the generator or  
generators.  
(j) Acceptable methods or standards for power-limited export DERs.  
(k) A cost allocation methodology for study track DERs.  
(l) An evaluation of an interconnection application for a project that includes single or  
multiple types of DERs at a site for which the applicant seeks a single point of common  
coupling.  
(m) Details describing how an energy storage device may be integrated into an existing  
legacy net metering program system without impacting the 10-year grandfathering  
period.  
(n) For electric utilities that are member-regulated electric cooperatives, a procedure for  
fairly processing applications in instances in which the number of applications exceed the  
capacity of the electric cooperative to timely meet the deadlines in these rules.  
(o) Examples of modifications that are not material modifications, acceptable material  
modifications, and unacceptable material modifications.  
(p) The procedure for performing a material modification review.  
(6) An electric utility shall obtain commission approval to revise its interconnection  
procedures.  
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R 460.922 Online applications and electronic submission.  
Rule 22. (1) An electric utility shall allow pre-application report requests,  
interconnection applications, and interconnection agreements to be submitted  
electronically, such as, through the electric utility’s website or via email.  
(2) An electric utility shall dedicate a page on its website or direct customers to a linked  
website with information on these rules. The relevant information available to an  
applicant or interconnection customer via a website must include all of the following:  
(a) These rules and interconnection procedures in an electronically searchable format.  
(b) The electric utility’s applications and all associated forms in a format that allows for  
electronic entry of data.  
(c) Sample documents including, at a minimum, a 1-line diagram with required labels.  
(d) Contact information for the electric utility’s DER interconnection coordinator,  
including an email address and a phone number.  
(e) Directions for the submission of applications.  
R 460.924 Communications.  
Rule 24. (1) An electric utility shall designate 1 or more interconnection coordinators.  
The telephone number and e-mail address of the interconnection coordinator or  
coordinators must be made available on the electric utility’s website. The interconnection  
coordinator or coordinators must be available to provide reasonable assistance to the  
applicant or interconnection customer but is not responsible to directly answer or resolve  
all of the issues that may arise in the interconnection process.  
(2) An applicant may designate an application agent. An application agent may serve as  
the single point of contact for the applicant and may coordinate with the electric utility on  
the applicant’s behalf. Designation of an application agent does not absolve the applicant  
from signing interconnection documents or from complying with the requirements in  
these rules and the interconnection agreement.  
(3) An electric utility must be indemnified by the applicant and its application agent  
with respect to assistance provided by an interconnection coordinator or coordinators.  
R 460.926 Initial fees.  
Rule 26. (1) After the effective date of these rules, fees for the pre-application report,  
the simplified track, the non-export track, the fast track, and the study track may not  
exceed the initial fee caps listed in subrule (2) of this rule, and the caps must remain in  
effect until interconnection procedures are approved by the commission under R 460.920.  
(2) The initial fee amounts for all levels of DERs are as follows:  
(a) The pre-application report fee may not exceed $300.  
(b) The simplified track fee and any applicable legacy net metering program application  
fee pursuant to R 460.1004(7) or distributed generation program application fee pursuant  
to R 460.1006(6), together, may not exceed a total of $50.  
16  
(c) The non-export track fee may not exceed $100 + $1/kWac for certified DERs and  
$100 + $2/kWac for non-certified DERs.  
(d) The fast track initial review fee is $100 + $1/kWac for certified DERs and $100 +  
$2/kWac for non-certified DERs.  
(e) The transition batch fee for interconnection application review and the scoping  
meeting may not exceed $300.  
(f) The fee for a fast track supplemental review including all review screens may not  
exceed $5,000.  
(g) The study track fee for interconnection application review and the scoping meeting  
may not exceed $300.  
(h) The system impact study fee may not exceed $30,000.  
(i) The facilities study fee may not exceed $30,000.  
(3) The initial fees caps listed in subrule (2) of this rule, and any fixed fees subject to the  
initial fee caps charged by the electric utility, must be displayed prominently on the  
electric utility’s interconnection website.  
(4) An electric utility that expects to incur costs greater than the initial fee caps listed in  
subrule (2) of this rule in the evaluation of an interconnection application may file a  
request for a waiver pursuant to R 460.910.  
R 460.928 Fee and fee cap modifications.  
Rule 28. (1) An electric utility shall include in its proposed interconnection procedures  
fixed fees to replace the initial fee caps specified in R 460.926(2)(a), (b), (c), (d), (e), and  
(g), and any other fixed fees the electric utility considers necessary.  
(2) An electric utility shall include in its proposed interconnection procedures adjusted  
fee caps to replace the initial fee caps specified in R 460.926(2)(f), (h), and (i), and any  
other fee caps the electric utility considers necessary. An electric utility may charge  
actual costs up to the fee caps.  
(3) The fixed fees must be specific to level size and be based on estimates of reasonable  
costs to perform the applicable service or study. The fee caps must be specific to level  
size and be based on a reasonable range of costs for performing the applicable study.  
(4) The most recently approved fixed fees and fee caps must be listed in the electric  
utility’s interconnection procedures and displayed prominently on the electric utility’s  
interconnection website.  
(5) The fixed fees and fee caps that are approved for inclusion in the electric utility’s  
interconnection procedures by the commission may be reviewed at any time by the  
electric utility and adjusted, if necessary, subject to commission review and approval.  
(6) Any modification of fees may not be applicable to fees already paid.  
(7) An electric utility that expects to incur costs greater than its prevailing fee caps in  
the evaluation of an interconnection application may file a request for a waiver pursuant  
to R 460.910.  
R 460.930 Pre-application report request form.  
17  
Rule 30. (1) An applicant shall submit a completed pre-application report request form  
and the required fee for a pre-application report on a proposed level 4 or level 5 DER.  
(2) The pre-application report request form must include all of the following  
information:  
(a) Project contact information, including name, address, phone number, and email  
address.  
(b) Project location, as accurately as can be identified, which may be given by any of  
the following:  
(i) Street address with nearby cross streets and town.  
(ii) An aerial map with location clearly marked.  
(iii) GPS coordinates.  
(c) Account number, meter number, structure number, or other equivalent information  
identifying the proposed point of common coupling, if available.  
(d) Whether the DER is any of the following:  
(i) Solar.  
(ii) Wind.  
(iii) Cogeneration.  
(iv) Storage.  
(v) Solar with storage.  
(vi) Other type of DER.  
(e) Nameplate capacity of the DER types in alternating current kW.  
(f) Whether the DER configuration is single or 3-phase.  
(g) Whether the DER will be a stand-alone generator, meaning no onsite load other than  
station service.  
(h) Whether new service is requested. If there is existing service, the customer account  
number and site minimum and maximum current or proposed electric loads in kW, if  
available, must be included, and how the load is expected to change must be specified.  
(i) Whether the location is new construction.  
R 460.932 Pre-application report.  
Rule 32. (1) Using the information provided in the pre-application report request form  
described in R 460.930, an electric utility shall identify the substation bus, bank, or  
circuit most likely to serve the point of common coupling. This identification by the  
electric utility does not necessarily indicate that this would be the circuit to which the  
project ultimately connects.  
(2) An applicant may request additional pre-application reports if information about  
multiple points of common coupling is requested. No more than 10 pre-application  
report requests may be submitted by an applicant and its affiliates during a 1-week  
period. An electric utility may reject additional pre-application report requests.  
(3) The pre-application report must include all of the following information:  
(a) Total capacity, in MW, of substation bus, bank, or circuit based on normal or  
operating ratings likely to serve the proposed point of common coupling.  
(b) Existing aggregate generation capacity, in MW, interconnected to a substation bus,  
bank, or circuit likely to serve the proposed point of common coupling.  
18  
(c) Aggregate capacity, in MW, of generation not yet built but found in previously  
accepted interconnection applications, for a substation bus, bank, or circuit likely to serve  
the proposed point of common coupling.  
(d) Available capacity, in MW, of substation bus, bank, or circuit likely to serve the  
proposed point of common coupling.  
(e) Substation nominal distribution voltage.  
(f) Nominal distribution circuit voltage at the proposed point of common coupling.  
(g) Label, name, or identifier of the distribution circuit on which the proposed point of  
common coupling is located.  
(h) Approximate circuit distance between the proposed point of common coupling and  
the substation.  
(i) The actual or estimated peak load and minimum load data at any relevant line  
section or sections, including daytime minimum load and absolute minimum load, when  
available. If not readily available, the report must indicate whether the generator is  
expected to exceed minimum load on the circuit.  
(j) Whether the point of common coupling is located behind a line voltage regulator and  
whether the substation has a load tap changer.  
(k) Limiting conductor ratings from the proposed point of common coupling to the  
distribution substation.  
(l) Number of phases available at the primary voltage level at the proposed point of  
common coupling, and, if a single phase, distance from the 3-phase circuit.  
(m) Whether the point of common coupling is located on a spot network, area network,  
grid network, radial supply, or secondary network.  
(n) Based on the proposed point of common coupling, the report must indicate whether  
power quality issues may be present on the circuit.  
(o) Whether or not the area has been identified as having a prior affected system.  
(p) Whether or not the site will require a system impact study for high voltage  
distribution based on size, location, and existing system configuration.  
(4) The pre-application report may include only existing and readily available data. A  
request for a pre-application report does not obligate an electric utility to conduct a study  
or other analysis of the proposed DER if data is not readily available. The  
pre-application report must also indicate any information listed in subrule (3) of this rule  
that is not readily available. An electric utility may, at its discretion, return any portion of  
the pre-application report fee because some or all information does not exist.  
(5) Pre-application report requests must be processed in the order in which an electric  
utility received the requests.  
(6) An electric utility shall provide the data required in the pre-application report to the  
applicant within 25 business days of receipt of the completed request form and payment  
of the fee. The pre-application report produced by the electric utility is non-binding and  
does not confer any rights on the applicant.  
R 460.934 Site control.  
Rule 34. (1) Documentation of site control must be submitted with the application by  
the applicant.  
19  
(2) For level 3, 4, or 5 DERs, site control may be demonstrated by providing  
documentation that shows any of the following:  
(a) Ownership of, a leasehold interest in, or a right to develop a site for the purpose of  
constructing and operating the DER.  
(b) An enforceable option to purchase or acquire a leasehold site for this purpose.  
(c) A legally binding agreement transferring a present real property right to specified  
real property along with the right to construct and operate a DER on the specified real  
property for a period of time not less than 5 years.  
(3) For level 1 or 2 DERs, proof of site control may be demonstrated by the site owner’s  
signature on the application.  
(4) An applicant may redact commercially sensitive information from site control  
documents.  
R 460.936 Interconnection applications.  
Rule 36. (1) An electric utility shall provide an interconnection application for an  
applicant to complete, including for those applicants whose DERs will be configured to  
be non-exporting.  
(2) All documents required for a complete interconnection application must be listed on  
the interconnection application. For level 4 and 5 interconnection applications, the list of  
required documents must include a completed pre-application report.  
(3) For interconnection applications with proposed DERs that fall into level 1, an  
applicant shall provide a 1-line diagram and a site diagram.  
(4) For interconnection applications with proposed DERs that fall into levels 2 and 3, an  
applicant shall provide a 1-line diagram that is either sealed by a professional engineer  
licensed in this state or signed by an electrical contractor who is licensed in this state with  
the electrical contractor’s license number noted on the diagram. An applicant shall also  
provide a site diagram.  
(5) For interconnection applications with proposed DERs that fall into levels 4 and  
above, an applicant shall provide a 1-line diagram that is sealed by a professional  
engineer who is licensed in this state. An applicant shall also provide a site diagram.  
(6) Applications shall be reviewed to assess whether they are complete and conforming  
in the order in which they were received. An application is considered received when an  
electric utility receives the application, the application’s attachments, and the application  
fee. The application must be date-stamped for the first business day when the electric  
utility has received the interconnection application, the application attachments, and  
payment of the application fee. An electric utility shall notify the applicant of receipt of  
the application by the end of the third business day following the date of the date stamp.  
(7) The electric utility shall notify the applicant that the interconnection application is  
either complete and conforming, or incomplete, or non-conforming, within 10 business  
days of the date stamp.  
(a) If an interconnection application is determined to be complete and conforming by the  
electric utility, the applicant must be notified that the interconnection application is  
accepted. The electric utility shall also indicate whether the interconnection application  
will be processed using the simplified track, non-export track, fast track, or study track.  
20  
(b) If the application is incomplete or non-conforming, the electric utility shall provide  
to the applicant a written list of all deficiencies with the notification. The applicant shall  
have 60 business days from the date of electric utility notification to submit the necessary  
information and may provide up to 2 submissions during this time period. After each  
submission of information, the electric utility shall have 10 business days to notify the  
applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this rule,  
the utility may withdraw the application.  
(8) An electric utility shall comply with part 2 of these rules, R 460.911 to R 460.992,  
and its interconnection procedures when interconnecting DERs that it owns and operates  
onto its distribution system, with the exception of temporary DERs.  
(9) An electric utility shall use the same process when processing and studying  
interconnection applications from all applicants, whether the DER is owned or operated  
by the electric utility, its subsidiaries or affiliates, or others, with the exception of  
temporary DERs.  
(10) An electric utility shall review and update interconnection applications periodically  
to reflect new information required to properly review DERs, subject to commission  
review and approval.  
R 460.938 Public interconnection list.  
Rule 38. (1) An electric utility shall maintain a public interconnection list,  
which is available in a sortable spreadsheet format, and provide it to the  
public upon request. An electric utility that has received not less than 100  
complete interconnection applications in a year shall publish this list on the  
electric utility’s website. The public interconnection list must be updated  
monthly unless no changes to the spreadsheet have occurred in that month.  
The date of the most recent update must be clearly indicated.  
(2) The public interconnection list must include all of the following:  
(a) An application identifier.  
(b) The date that the electric utility received the application.  
(c) The date that the electric utility considered the application to be complete  
and conforming.  
(d) Whether the application is on the simplified track, non-export track, fast  
track, or study track.  
(e) The proposed DER nameplate capacity.  
(f) The proposed DER interconnection size level.  
(g) The DER technology type.  
(h) The county and township in which the proposed point of common coupling  
will be located.  
(i) The current status of the application’s progress in the interconnection process.  
(j) The labels, names, or identifiers of the distribution circuit and substation.  
R 460.940 Simplified track review.  
21  
Rule 40. (1) Level 1 and 2 applications, including applications that include an  
energy storage device so the export of power meets the requirements of  
level 1 or level 2, must be processed using the simplified track.  
(2) Within 10 business days after notifying an applicant that the application had been  
accepted, an electric utility shall perform a review by using up to all of the initial review  
screens specified in the electric utility’s interconnection procedures and notify the  
applicant if any interconnection facilities, distribution upgrades, further study, or  
application modifications are required for safe and reliable interconnection to the electric  
utility’s distribution system or for tariff compliance. If an electric utility chooses to  
perform a review by using a subset of the initial review screens, the exclusion of 1 or  
more screens may not be the only basis for the electric utility to require application  
modification or further study.  
(3) If the utility review notification indicates that no further study or  
application modifications are required, the applicant shall proceed under  
R 460.964 to an interconnection agreement.  
(4) If application modification is offered by the electric utility, the applicant  
shall either withdraw the interconnection application or provide a  
modified application within 60 business days from the date of electric  
utility notification, with up to 2 resubmissions during this time period to  
provide a modified application. After each submission of information,  
the electric utility shall notify the applicant within 10 business days that  
the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines  
required by this subrule, the electric utility may withdraw the application.  
When the applicant provides a modified application, the electric utility  
shall follow the procedure specified in subrule (2) of this rule.  
(5) If further study is required, the electric utility and the applicant shall decide whether to  
proceed to a supplemental review under R 460.950 or the study track under R 460.952, or  
to withdraw the application. The applicant shall have 20 business days to decide on a  
course of action and to notify the electric utility. In the absence of this notification, the  
electric utility may withdraw the application.  
R 460.942 Non-export track review.  
Rule 42. (1) Interconnection applications for DERs that will not inject electric energy  
into an electric utility’s distribution system are eligible for evaluation under  
the non-export track. Non-export eligibility requires an existing electrical  
service at the applicant’s premise.  
(2) Subject to review and approval by the commission, an electric utility may limit the  
eligibility of the non-export track in its interconnection procedures based  
on the characteristics of its distribution system.  
(3) Before submitting an interconnection application, a non-export track applicant may  
contact the electric utility for assistance in determining whether a  
non-export track review will be sufficient or the study track is necessary.  
22  
The electric utility shall provide the applicant assistance based on available  
information. If the applicant chooses to proceed, an interconnection  
application shall be submitted pursuant to R 460.936.  
(4) Within 20 business days after being notified that the application was accepted, the  
electric utility shall perform an initial review by using some or all of the initial review  
screens specified in the electric utility’s interconnection procedures and notify the  
applicant of the results. If an electric utility chooses to perform a review using a subset  
of the initial review screens, the exclusion of 1 or more screens may not be the only basis  
for the electric utility to require interconnection facilities, distribution upgrades, further  
study, or application modifications.  
(a) If the notification indicates that no interconnection facilities, distribution upgrades,  
further study, or application modifications are required, the electric utility shall provide  
specifications for any equipment the applicant will be required to install within 10  
business days of the applicant being notified. Within 10 business days of receiving the  
equipment specifications, the applicant shall notify the electric utility whether it will  
proceed under R 460.964 to an interconnection agreement or will withdraw the  
application. The applicant’s failure to notify the electric utility within the required time  
period shall result in the interconnection application being withdrawn by the electric  
utility.  
(b) If application modification is offered by the electric utility, the applicant shall either  
withdraw the interconnection application or provide a modified application within 60  
business days from the date of electric utility notification, with up to 2 resubmissions  
during this time period to provide a modified application. After each submission of  
information, the electric utility shall notify the applicant within 10 business day that the  
interconnection application is either accepted or rejected due to continuing deficiencies.  
If the applicant does not meet the timelines required by this subrule, the electric utility  
may withdraw the application. When the applicant provides a modified application, the  
electric utility shall follow the procedure specified in subrule (4) of this rule.  
(5) If further study is required, the electric utility shall present options and the applicant  
shall decide whether to proceed to a supplemental review under R 460.950, or to the  
study track under R 460.952, or to withdraw the application. The applicant shall have 20  
business days to decide on a course of action and notify the electric utility. In the absence  
of this notification, the electric utility may withdraw the application within the required  
time period.  
(6) When an applicant changes from a non-exporting system to an exporting system, the  
applicant shall submit a new interconnection application.  
R 460.944 Fast track applicability.  
Rule 44. (1) Level 3 and level 4 applications in which the DER is not  
proposing to interconnect with the electric utility’s high voltage  
23  
distribution system are eligible for the fast track. These level 3 and level  
4 applications may include applications that provide for the use of an  
energy storage device so the export of power meets the requirements of  
level 3 or level 4.  
(2) An applicant that is eligible for the fast track may forgo the fast track and  
proceed directly to the study track.  
(3) An applicant with an application that is outside the limitations specified in  
subrule (1) of this rule may petition the electric utility to have its  
application evaluated under fast track. The electric utility may approve  
or reject this request at its discretion.  
(4) In determining fast track eligibility, an electric utility may aggregate all  
proposed new generation on a site regardless of the existence of a shared  
point of common coupling or multiple points of common coupling.  
R 460.946 Fast track; initial review.  
Rule 46. (1) An electric utility shall list in its interconnection procedures the  
initial review screens specified in subrule (5) of this rule. An electric  
utility may add additional details to each of these screens in the  
interconnection procedures.  
(2) An electric utility may include additional initial review screens in its  
interconnection procedures. In its application requesting approval of  
interconnection procedures, an electric utility shall provide a detailed  
technical rationale for including each additional screen. If an additional  
screen conflicts with or undermines any of the initial review screens  
specified in subrule (5) of this rule, the rationale must include an  
explanation of how it does so.  
(3) The electric utility may waive application of 1, some, or all of the initial  
review screens.  
(4) Within 20 business days after an electric utility receives a complete and  
conforming application and associated payment, the electric utility shall  
perform an initial review and notify the applicant of the results. The  
initial review must consist of applying the initial review screens selected  
by the electric utility pursuant to subrule (3) of this rule to the proposed  
DER. The electric utility shall not require a supplemental review or a  
system impact study if the DER passes the applied initial review screens.  
(5) The initial review screens are all of the following:  
(a) The entire proposed DER, including all aggregated site generation and point  
or points of interconnection, must be located within the electric utility’s  
service territory.  
(b) For interconnection of a proposed DER to a radial distribution circuit, the  
aggregated generation, including the proposed DER, on the circuit may  
not exceed 15% of the line section annual peak load as most recently  
measured or calculated if measured data is not available. A line section is  
that portion of an electric utility’s distribution system connected to a  
24  
customer bounded by automatic sectionalizing devices or the end of the  
distribution line. The electric utility may consider 100% of applicable  
loading, if available, instead of 15% of line section peak load.  
(c) For interconnection of a proposed DER to the load side of network  
protectors, the proposed DER must utilize an inverter-based equipment  
package and, together with the aggregated other inverter-based DERs,  
may not exceed the smaller of 5% of a network’s maximum load or 50  
kWac.  
(d) The proposed DER, in aggregation with other DERs on the distribution  
circuit, may not contribute more than 10% to the distribution circuit’s  
maximum fault current at the point on the primary voltage nearest the  
proposed point of common coupling.  
(e) The proposed DER, in aggregate with other DERs on the distribution  
circuit, may not cause any distribution protective devices and equipment  
or interconnection customer equipment on the system to exceed 87.5% of  
the short circuit interrupting capability. An interconnection may not be  
proposed for a circuit that already exceeds 87.5% of the short circuit  
interrupting capability. Distribution protective devices and equipment  
include, but are not limited to, substation breakers, fuse cutouts, and line  
reclosers.  
(f) The initial review screen determines the type of interconnection to a  
primary distribution line for the proposed DER, according to the  
requirements specified in the table in this subdivision. This screen  
includes a review of the type of electrical service provided to the  
applicant, including line configuration and the transformer connection to  
limit the potential for creating over-voltages on the electric utility’s  
distribution system due to a loss of ground during the operating time of  
any anti-islanding function.  
Primary Distribution Line  
Type  
Type of Interconnection to  
Primary Distribution Line  
3-phase or single phase,  
phase-to-phase  
Result  
3-phase, 3 wire  
Pass screen  
Pass screen  
3-phase, 4 wire  
Effectively-grounded 3- phase  
or single-phase, line-to-neutral  
(g) If the proposed DER is to be interconnected on single-phase  
shared secondary, the aggregate generation capacity on  
the shared secondary, including the proposed DER, may  
not exceed 20 kWac or 65% of the transformer  
nameplate rating.  
(h) If the proposed DER is single-phase and is to be interconnected on  
a center tap neutral of a 240 volt service, its addition  
may not create an imbalance between the 2 sides of the  
25  
240 volt service of more than 20% of the nameplate  
rating of the service transformer.  
(i) If the proposed DER is single-phase and is to be interconnected to  
a 3-phase service, its nameplate rating may not exceed  
10% of the service transformer nameplate rating.  
(j) If the proposed DER’s point of common coupling is behind a line  
voltage regulator, the DER’s nameplate rating must be  
less than 250 kWac. This screen does not include  
substation voltage regulators.  
(6) If the proposed interconnection passes the initial review screens, or  
if the proposed interconnection fails the screens but the  
electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and  
power quality standards, the electric utility shall notify  
the applicant. If a facilities study is not required, the  
interconnection application must proceed under R  
460.964 to an interconnection agreement. If a facilities  
study is required, the interconnection agreement must  
proceed under R 460.962.  
(7) If the proposed interconnection fails any of the initial review  
screens, and the electric utility does not or cannot  
determine that the DER may be interconnected  
consistent with safety, reliability, and power quality  
standards, the electric utility shall notify the applicant,  
provide the applicant with the results of the application  
of the initial review screens, and offer all of the  
following options:  
(a) Attend a customer options meeting, as described in R 460.948.  
(b) Proceed to supplemental review under R 460.950.  
(c) Submit within 60 business days from the date of the electric utility  
notification, with up to 2 submissions during this time  
period, a complete and conforming revised  
interconnection application that includes application  
modifications offered or required by the electric utility.  
The application modifications must mitigate or eliminate  
the factors that caused the interconnection application to  
fail 1 or more of the initial review screens. After each  
submission of information, the electric utility has 10  
business days to notify the applicant that the  
interconnection application is either accepted or rejected  
due to continuing deficiencies. If the applicant does not  
meet the timelines required by this subrule, the electric  
utility may withdraw the application. After the electric  
utility determines the application is accepted, the revised  
26  
interconnection application must proceed under subrule  
(4) of this rule.  
(d) Withdraw the interconnection application.  
(8) If the applicant does not select a course of action under subrule (7)  
of this rule within 10 business days of notice from the  
electric utility, the electric utility shall withdraw the  
interconnection application.  
R 460.948 Fast track; customer options meeting.  
Rule 48. (1) Upon an applicant’s request, the electric utility and the applicant shall  
schedule a customer options meeting between the electric utility and the applicant to  
review possible facility modifications, screen analysis, and related results to determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The customer options meeting must take place within 30 business  
days of the date of notification pursuant to R 460.946(7).  
(2) At the customer options meeting, the electric utility shall offer all of the following  
options:  
(a) Proceed to a supplemental review pursuant to R 460.950.  
(b) Continue evaluating the interconnection application under the study track pursuant  
to R 460.952.  
(c) Submit within 60 business days from the date of the customer options meeting, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility, which mitigates or eliminates the factors that caused the  
interconnection application to fail 1 or more of the initial review screens. After each  
submission of information, the electric utility has 10 business days to notify the applicant  
that the interconnection application is either accepted or rejected due to continuing  
deficiencies. If the applicant does not meet the timelines required by this subrule, the  
electric utility may withdraw the application. After the electric utility accepts the revised  
interconnection application, it must proceed under R 460.946(4).  
(d) Withdraw the interconnection application.  
(3) Following the customer options meeting, the applicant has up to 20 business days to  
decide on a course of action and notify the electric utility. In the absence of this  
notification within the required time, the electric utility shall withdraw the application.  
(4) The customer options meeting may take place in person or via telecommunications.  
R 460.950 Fast track; supplemental review.  
Rule 50. (1) An electric utility shall list in its interconnection procedures the  
supplemental review screens specified in subrule (6) of this rule. An  
electric utility may add additional details to each of these screens in the  
interconnection procedures.  
(2) An electric utility may include additional supplemental review screens in its  
interconnection procedures. In its application requesting approval of  
27  
interconnection procedures, the electric utility shall provide a detailed  
technical rationale for the inclusion of each supplemental review screen. If  
an additional screen negates or undermines any of the supplemental review  
screens specified in subrule (6) of this rule, the rationale must include an  
explanation of the technical justification for the additional screen.  
(3) An electric utility may waive application of 1, some, or all of the  
supplemental review screens.  
(4) To receive a supplemental review, an applicant shall submit payment of the  
supplemental review fee within 20 business days of agreeing to a  
supplemental review. If payment of the fee has not been received by the  
electric utility within 25 business days, the electric utility shall withdraw  
the interconnection application.  
(5) Within 30 business days after the applicant pays the applicable supplemental  
review fee or fees, an electric utility shall perform a supplemental review  
and notify the applicant of the results. The supplemental review must  
consist of applying the initial review screens selected by the electric utility  
pursuant to subrule (3) of this rule to the proposed DER. The electric  
utility shall not require a system impact study if the DER passes the applied  
supplemental review screens.  
(6) The supplemental review screens must include all of the following:  
(a) Minimum load screen. Where 12 months of line section minimum load data,  
including onsite load but not station service load served by the proposed  
DER, are available, can be calculated, can be estimated from existing data,  
or can be determined from a power flow model, the aggregate DER  
capacity on the line section must be less than 100% of the minimum load  
for all line sections bounded by automatic sectionalizing devices upstream  
of the proposed DER. If minimum load data are not available, or cannot be  
calculated, estimated, or determined, an electric utility shall include the  
reason or reasons that it is unable to calculate, estimate, or determine  
minimum load in its supplemental review results notification under  
subrules (7) and (8) of this rule. All of the following must be applied by  
the electric utility:  
(i) The type of generation used by the proposed DER will  
be considered when calculating, estimating,  
or determining circuit or line section  
minimum load relevant for the application of  
the minimum load screen specified in subrule  
(6)(a) of this rule. Solar photovoltaic  
generation systems with no battery storage  
must use daytime minimum load. All other  
generation must use absolute minimum load  
unless an operating schedule is provided.  
(ii) When this screen is being applied to a DER that  
serves some station service load, only the net  
injection of electric energy into the electric  
28  
utility’s distribution system may be  
considered as part of the aggregate  
generation.  
(iii) The electric utility shall not consider as part of the  
aggregate generation, for purposes of this  
supplemental screen, DER capacity known to  
be already reflected in the minimum load  
data.  
(b) Voltage and power quality screen. In aggregate with existing generation on the line  
section, all of the following conditions must be met:  
(i) The voltage regulation on the line section can be maintained in  
compliance with relevant requirements under all system  
conditions.  
(ii) The voltage fluctuation is within acceptable limits as defined by  
the IEEE Standard 1453-2015, IEEE Recommended  
Practice for the Analysis of Fluctuating Installations on  
Power Systems.  
(c) Safety and reliability screen. The location of the proposed DER  
and the aggregate generation capacity on the line section  
may not create impacts to safety or reliability that  
require application of the study track to address. An  
electric utility shall consider all of the following when  
determining potential impacts to safety and reliability in  
applying this screen:  
(i) Whether the line section has significant minimum  
loading levels dominated by a small number  
of customers, such as several large  
commercial customers.  
(ii) Whether the loading along the line section is uniform.  
(iii) Whether the proposed DER is located less than 0.5  
electrical circuit miles for less than 5 kV or  
less than 2.5 electrical circuit miles for  
greater than 5 kV from the substation. In  
addition, whether the line section from the  
substation to the point of common coupling is  
a mainline rated for normal and emergency  
ampacity.  
(iv) Whether the proposed DER incorporates a time delay  
function to prevent reconnection of the DER  
to the distribution system until distribution  
system voltage and frequency are within  
normal limits for a prescribed time.  
(v) Whether operational flexibility is reduced by the  
proposed DER, such that transfer of the line  
section or sections of the DER to a  
29  
neighboring distribution circuit or substation  
may trigger overloads, power quality issues,  
or voltage issues.  
(vi) Whether the proposed DER employs equipment or  
systems certified by a recognized standards  
organization to address technical issues  
including, but not limited to, islanding,  
reverse power flow, or voltage quality.  
(7) If the proposed interconnection passes the supplemental  
review, or if the proposed interconnection  
fails the review but the electric utility  
determines that the DER may be  
interconnected consistent with safety,  
reliability, and power quality standards, the  
electric utility shall notify the applicant and  
the interconnection application must proceed  
pursuant to both of the following:  
(a) If the proposed interconnection requires a facilities  
study, the interconnection application must  
proceed under R 460.962.  
(b) If the proposed interconnection does not require further  
study, the interconnection application must  
proceed under R 460.964 to an  
interconnection agreement.  
(8) If the proposed interconnection fails any of the supplemental  
review screens or the electrical utility is unable to  
perform a supplemental review screen, and the electric  
utility does not or cannot determine that the DER may be  
interconnected consistent with safety, reliability, and  
power quality standards, the electric utility shall notify  
the applicant, provide the applicant with the results of  
the application of the supplemental review screens, and  
offer both of the following options:  
(a) Stop the supplemental review and continue evaluating the  
proposed interconnection under the study track under R  
460.952.  
(b) Withdraw the interconnection application.  
(9) For subrules (7) and (8) of this rule, if an applicant does not select a course of  
action within 10 business days of notice from the electric utility, the electric  
utility shall withdraw the interconnection application.  
R 460.952 Study track.  
30  
Rule 52. (1) An electric utility shall use the study track to evaluate an interconnection  
application that has been accepted under R 460.936 if 1 or more of the following  
conditions is met:  
(a) The DER is not eligible for the simplified track, the non-export track, or fast track.  
(b) The DER did not pass the initial review screens as part of the fast track and the  
applicant selected the study track option in the customer options meeting.  
(c) The DER did not pass 1 or more supplemental review screens.  
(d) The DER was evaluated under the simplified track or the non-export track and  
further study is required.  
(e) The DER is eligible for the fast track, but the applicant elected the study track.  
(2) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(a) of this rule, within 10 business days after the electric  
utility notifies the applicant that the interconnection application has been accepted  
pursuant to R 460.936, the electric utility shall provide an individual study agreement or a  
batch study agreement to the applicant, whichever is applicable under subrule (4) of this  
rule.  
(3) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(b), (c), (d), or (e) of this rule, within 10 business days  
after the applicant has notified the electric utility to proceed to the study track, the electric  
utility shall provide an individual study agreement or a batch study agreement to the  
applicant, whichever is applicable under subrule (4) of this rule.  
(4) An electric utility shall study all interconnection applications that qualify for study  
track either individually or in a batch study process. An electric utility shall not study 1 or  
more applications individually and at the same time study 1 or more different applications  
as part of a batch.  
(5) An electric utility’s interconnection procedures may include a provision for  
determining appropriate milestone payments to include with the system impact study fee  
and facilities impact study fee.  
R 460.954 Individual study.  
Rule 54. (1) An electric utility that is evaluating DERs in the study track individually  
shall process the interconnection applications in the order in which the applications were  
placed into the study track, taking into account withdrawn interconnection applications  
and electrically remote DERs.  
(a) An electrically remote DER in an individual study may be studied on an expedited  
schedule relative to electrically coincident DERs. Electrically remote DERs must be  
studied in the order the interconnection applications were considered complete.  
(2) When an interconnection application is delayed due to an affected system issue,  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint pursuant to R 792.10439 to R 792.10446, other interconnection applications  
that were placed into the study track on a later date may progress in the order in which  
the interconnection applications were placed into the study track.  
(3) An individual study process must consist of a system impact study pursuant to R  
460.960 and a facilities study pursuant to R 460.962. An electric utility may waive 1 or  
31  
both studies for a particular interconnection application. An electric utility may specify  
additional studies it may perform on an interconnection application in its interconnection  
procedures, provided the electric utility is able to meet all applicable timelines associated  
with an individual study process.  
(4) Interconnection applications that meet all of the following requirements must be  
admitted into an individual study:  
(a) An electric utility has elected to study all interconnection applications that qualify  
for study track individually.  
(b) An electric utility determined the application to be complete and conforming.  
(c) An application qualifies for study track pursuant to R 460.952.  
(d) An interconnection application has a pre-application report, when required by R  
460.936(2).  
(e) An applicant has paid all required fees.  
(f) An applicant has signed and returned an individual study agreement.  
(5) If an electric utility anticipated that it would use a batch study process but received  
only 1 interconnection application that qualified for the study track, the electric utility  
shall consider the first day of what would have been the batch study process to be the day  
the application was determined to be complete and conforming and shall use the  
individual study process to evaluate the application with all applicable timelines.  
R 460.956 Batch study process.  
Rule 56. (1) This rule applies only to those electric utilities that have elected to study  
DERs that qualify for study track in a batch process.  
(2) A batch consists of 2 or more interconnection applications that will be studied as a  
group by the electric utility. One or more DERs in the batch that are electrically remote  
may be studied on an expedited schedule, but expedited scheduling of 1 or more DERs  
may not cause unreasonable delays in the evaluation of the other DERs in the same batch.  
(3) An electric utility shall process at least 1 batch per year. The start and end dates for  
each batch study must be published on the electric utility’s public website not less than 60  
days prior to the start of the batch.  
(4) Interconnection applications that meet all of the following requirements must be  
admitted into a batch study:  
(a) The electric utility elected to study all interconnection applications that qualify for  
study track in a batch study process.  
(b) The electric utility considered the application complete and conforming within a  
1-year period immediately before the batch study commences.  
(c) The accepted application qualifies for study track pursuant to R 460.952.  
(d) The interconnection application has a pre-application report when required by R  
460.930(2).  
(e) The applicant has paid all required fees including any milestone payments as  
described in the electric utility’s interconnection procedures.  
(f) The applicant has signed a batch study agreement.  
32  
(5) An electric utility shall offer to hold a scoping meeting, either in-person or via  
telecommunications, with every applicant in a batch. The scoping meetings and the  
electric utility must meet all of the following requirements:  
(a) All meetings must, to the extent feasible, take place within 30 days of the batch start  
date.  
(b) An electric utility shall not begin studies within a batch until it has held a scoping  
meeting with every applicant who agreed to participate in a meeting. An electric utility  
may begin the batch study if an applicant is unreasonably delaying a meeting.  
(c) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting. An electric utility may meet with  
multiple applicants in the same meeting if agreed to by the electric utility and all the  
applicants that will attend the meeting.  
(d) During the scoping meeting, the electric utility shall identify and communicate to  
each applicant the studies it plans to perform and estimate the cost of the batch study,  
using either the fees that comply with R 460.926, or, if interconnection procedures have  
been approved by the commission, fees that comply with the interconnection procedures.  
The cost estimate must assume that all applicants will stay in the batch throughout the  
batch study.  
(6) The batch process must consist of a system impact study pursuant to R 460.960 and  
a facilities study pursuant to R 460.962. The electric utility may specify additional studies  
it may perform on a batch study in its interconnection procedures.  
(7) Interconnection applications within a batch must be considered to have equal priority  
with each other.  
(8) An electric utility shall follow R 460.960(1) and (2) when conducting a system  
impact study.  
(9) An electric utility shall follow R 460.962(1) when conducting a facilities study.  
(10) An electric utility shall provide written study results to each applicant at the  
completion of each study during the batch study. An electric utility shall offer to hold a  
conference call with each batch applicant at the completion of each study phase, with the  
electric utility making reasonable efforts to accommodate applicants’ availability when  
scheduling the call. An electric utility may choose to group the consultation of multiple  
projects by the applicant and its affiliates into the same conference call. The conference  
call must provide a summary of outcomes and answer questions from applicant. All  
conferences regarding the study results should be held within 30 business days following  
completion of each study phase.  
(11) Within 45 business days following the completion of each study phase, the  
applicant shall choose to either continue to the next study phase of the batch study or  
withdraw. The fee for the next study phase in the batch study is due by the end of the 45  
business days, unless extended by the electric utility. An applicant that withdraws from  
the study may reapply with a new interconnection application.  
(12) Applicants may reduce the capacity of the DER by up to 20% during the decision  
period between study phases until the conclusion of the system impact study. If the  
applicant wants to increase the capacity of the DER, the electric utility may require the  
applicant to submit a new interconnection application and pay the appropriate fees.  
33  
(13) Within 45 business days of the applicant receiving the final batch study report from  
the electric utility, the applicant shall notify the electric utility of its plan to proceed to R  
460.964 for an interconnection agreement or withdraw its interconnection application. If  
the applicant fails to notify the electric utility within 45 business days, the electric utility  
may withdraw the interconnection application.  
(14) If an interconnection application is delayed due to an affected system issue,  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint pursuant to R 792.10439 to R 792.10446, the other interconnection  
applications in the batch must continue to progress through the batch study process. If  
feasible, considering the status of the batch study, the delayed interconnection application  
may rejoin the batch study after the affected system issue is resolved. An interconnection  
application that is the subject of informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or a complaint pursuant to R 792.10439 to R  
792.10446, may rejoin the batch study at a later date, if feasible, considering the status of  
the batch study.  
(15) A batch study is considered complete 45 business days after all batch applicants,  
except those applicants whose DERs are either causing unresolved affected system  
issues, pursuing informal mediation pursuant to R 460.904, pursuing formal mediation  
under R 460.906, or pursuing a complaint under R 792.10439 to R 792.10446, have  
withdrawn, voluntarily or otherwise, or have received the final study results from the  
electric utility.  
R 460.958 Scoping meeting for interconnection applications that are to be  
studied individually.  
Rule 58. (1) This rule applies only to those electric utilities that have elected to  
individually study DERs that qualify for study track.  
(2) Upon request of the applicant, the electric utility and the applicant shall  
schedule a scoping meeting between the electric utility and the applicant to  
discuss the interconnection application and review existing fast track  
results, if any. The scoping meeting must take place within 20 business  
days after the interconnection application is considered complete by the  
electric utility or, if applicable, the fast track has been completed and the  
applicant has elected to continue with the system impact study or facilities  
study.  
(3) Scoping meetings are limited to 1 hour per application. Multiple applications  
by the same applicant may be addressed in the same meeting.  
(4) The scoping meeting may occur in-person or via telecommunications.  
(5) During the scoping meeting, the electric utility shall identify and  
communicate to the applicant whether the applicant must proceed to a  
system impact study, a facilities study, or an interconnection agreement and  
the basis for that decision, and 1 of the following must occur:  
(a) If a system impact study must be performed, the interconnection application  
proceeds to R 460.960.  
34  
(b) If a facilities study must be performed, the interconnection application  
proceeds to R 460.962.  
(c) The interconnection application must proceed to R 460.964 for an  
interconnection agreement.  
R 460.960 System impact study agreement, scope, procedure, and review meeting.  
Rule 60. (1) For all DERs being studied individually or as part of a batch, all of  
the following apply:  
(a) An electric utility shall provide the applicant a system impact study  
agreement within 5 business days of proceeding to this rule.  
(b) A system impact study agreement must include all of the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee.  
(iii) If necessary, a list of any additional and reasonable technical data needed  
from the applicant to perform the system impact study.  
(iv) A timeline for completion of the system impact study.  
(v) A list of the information that must be provided to the applicant in the system  
impact study report.  
(c) An applicant who has requested a system impact study shall return the  
completed system impact study agreement, provide any additional technical  
data requested by the electric utility, and pay the required fee within 20  
business days. An electric utility may consider the application withdrawn if  
the system impact study agreement, payment, and required technical data  
are not returned within 20 business days.  
(d) A system impact study must identify and describe the electric system impacts  
that would result if the proposed DER was interconnected without electric  
system modifications. A system impact study must provide a non-binding  
good faith list of facilities that are required as a result of the application and  
non-binding estimates of costs and time to construct these facilities.  
(e) An electric utility shall explain in its interconnection procedures the process  
for conducting system impact studies on DERs when there is an affected  
system issue.  
(2) For DERs being studied as part of a batch, an electric utility may request  
reasonable additional data from the applicant during the system impact  
study. The electric utility and the applicant shall work together to resolve  
the additional data request so that the electric utility will be able to  
complete the batch study within the 1-year timeframe specified in R  
460.956. An electric utility may not be found in violation of these rules  
when 1 or more applicants impede the batch study process through  
applicant delays, demands, complaints, litigation, objections, or other  
similar actions.  
(3) For DERs being studied individually, all of the following shall apply:  
(a) The electric utility shall complete the system impact study and the system  
impact study report. If necessary, the electric utility shall transmit a  
35  
facilities study agreement to the applicant within 60 business days of  
receipt of the signed system impact study agreement, payment of all  
applicable fees, and any necessary technical data.  
(b) An electric utility may request reasonable additional data from the applicant  
within 20 business days of beginning the system impact study. The electric  
utility and the applicant shall work together to resolve the additional data  
request so that the electric utility will be able to complete the system  
impact study within 60 business days as specified in subrule (3)(a) of this  
rule.  
(c) Within 15 business days of receiving the system impact study report, the  
applicant shall notify the electric utility that it plans to pursue a system  
impact study review meeting, proceed to a facilities study pursuant to R  
460.962, or withdraw the application. If the applicant fails to notify the  
electric utility within 15 business days, the electric utility may consider the  
application to be withdrawn.  
(d) Upon request by the applicant pursuant to subrule (3)(c) of this rule, the  
electric utility and the applicant shall schedule a system impact study  
review meeting between the electric utility and the applicant to review  
system impact study results and determine what further steps are needed to  
permit the DER to be connected safely and reliably to the distribution  
system. The system impact study review meeting must take place within 25  
business days of the electric utility receiving notification that the applicant  
plans to attend a system impact study review meeting.  
(e) At the system impact study review meeting, the electric utility shall offer the  
applicant all of the following options:  
(i) Proceed to a facilities study pursuant to R 460.962.  
(ii) Proceed directly to R 460.964 for an interconnection agreement.  
(iii) Withdraw the interconnection application.  
(f) Following the meeting, the applicant has not more than 45 business days to  
decide on a course of action. If an applicant fails to notify the electric  
utility within 45 business days, the electric utility may consider the  
application to be withdrawn.  
(g) The system impact study review meeting may occur in-person or via  
telecommunications.  
R 460.962 Facilities study agreement, scope, procedure; review meeting.  
Rule 62. (1) For DERs being studied individually or as part of a batch, all of the  
following apply:  
(a) If construction of facilities is required to provide interconnection and  
interoperability of the DER with the electric utility’s distribution system,  
the electric utility shall provide the applicant a facilities study agreement  
and the results of the applicant’s system impact study pursuant to R  
460.960, if applicable. If no system impact study was performed, the  
36  
electric utility shall provide a facilities study agreement within 10 business  
days of proceeding to this rule.  
(b) The facilities study agreement must include the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee.  
(iii) A timeline for completion of the facilities study.  
(iv) A list of the information that will be provided to the applicant in the  
facilities study report.  
(c) The applicant shall return the signed facilities study agreement and pay the  
required facilities study fee within 20 business days. The electric utility  
may withdraw the application if the facilities study agreement and payment  
are not returned within 20 business days.  
(d) A facilities study must specify and estimate the cost of the required  
equipment, engineering, procurement, and construction work, including  
overheads, needed to interconnect the DER, and an estimated timeline for  
the completion of construction. The electric utility shall provide cost  
estimates that are detailed and itemized.  
(e) The electric utility shall explain in its interconnection procedures the process  
for conducting facilities studies on DERs while there is an affected system  
issue.  
(2) For DERs being studied individually, all of the following are required:  
(a) The electric utility shall complete the facilities study and transmit a facilities  
study report to the applicant within 80 business days of the receipt of the  
signed facilities study agreement and payment of the facilities study fee.  
(b) Within 10 business days of receiving a facilities study report from the electric  
utility, the applicant shall select 1 option from the following options:  
(i) Request a facilities study review meeting with the electric utility.  
(ii) Proceed to an interconnection agreement pursuant to R 460.964.  
(iii) Withdraw the interconnection application.  
If the applicant fails to inform the electric utility within 10 business days of its  
chosen course of action, the electric utility may consider the application  
withdrawn.  
(c) Upon request by the applicant pursuant to subrule (2)(b)(i) of this rule, the  
electric utility and the applicant shall schedule a facilities study review to  
review the facilities study results and determine what further steps are  
needed to permit the DER to be connected safely and reliably to the  
distribution system. The facilities study review meeting must take place  
within 25 business days of the electric utility receiving notification that the  
applicant will attend a facilities study review meeting.  
(d) At the facilities study review meeting, the electric utility shall offer both of  
the following options:  
(i) Proceed to an interconnection agreement pursuant to R 460.964.  
(ii) Withdraw the interconnection application.  
(e) Following the meeting, the applicant has no more than 20 business days to  
decide on a course of action and notify the electric utility of this course of  
37  
action. If the applicant fails to notify the electric utility within 20 business  
days, the electric utility may withdraw the application.  
(f) The facilities study review meeting may be conducted in-person or via  
telecommunications.  
R 460.964 Interconnection agreement.  
Rule 64. (1) For level 1, 2, or 3 interconnection applications, where no  
construction of interconnection facilities or distribution upgrades is  
required, an electric utility shall provide its standard level 1, 2, and 3  
interconnection agreement to an applicant within 3 business days of  
reaching this stage.  
(2) For level 1, 2, or 3 interconnection applications, where construction of  
interconnection facilities or distribution upgrades is required, an electric  
utility shall provide its standard level 1, 2, and 3 interconnection agreement  
with modifications to address required construction activities, construction  
milestone timing, and cost to an applicant within 5 business days of  
reaching this stage. The applicant and electric utility shall mutually agree  
on the timing of construction milestones.  
(3) For an applicant with level 1, 2, or 3 interconnection applications, the  
applicant shall sign and return the standard level 1, 2, and 3 interconnection  
agreement with payment, if applicable, within 20 business days of  
receiving the agreement.  
(a) If the applicant did not sign and return the standard level 1, 2, and 3  
interconnection agreement and payment, if applicable, within 20 business  
days, the electric utility shall notify the applicant of the missed deadline  
and grant an extension of 15 business days. If the electric utility did not  
receive the signed standard level 1, 2, and 3 interconnection agreement and  
any applicable payment during the 15-business-day extension, the electric  
utility may consider the interconnection application withdrawn subject to  
subrule 3(b) of this rule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904,  
the formal mediation pursuant to R 460.906, or the complaint process  
pursuant to R 792.10439 to R 792.10446 within the 20 business days, the  
outcome of that process must establish a time frame for the applicant to  
return the signed interconnection agreement and any applicable payment.  
(4) For level 1, 2, or 3 projects, the electric utility shall countersign and provide a  
completed copy of the standard level 1, 2, and 3 interconnection agreement  
within 10 business days of the applicant returning the signed standard level  
1, 2, and 3 interconnection agreement.  
(5) For level 4 or 5 projects, the electric utility shall provide its level 4 and 5  
interconnection agreement within 10 business days of reaching this stage.  
When construction of interconnection facilities or distribution upgrades is  
necessary, the level 4 and 5 interconnection agreement must contain either  
timelines for completion of activities and estimates of construction costs or  
38  
a timetable when these requirements can be determined. The  
interconnection agreement must include a payment schedule that  
corresponds to the milestones established and must require the electric  
utility to refund any unspent and unobligated funds if the agreement is  
terminated.  
(6) For an applicant with level 4 or 5 DERs, the applicant shall sign and return  
with payment, if applicable, a level 4 and 5 interconnection agreement  
within 30 business days.  
(a) If the applicant does not sign and return the level 4 and 5 interconnection  
agreement with payment within 30 business days, an electric utility shall  
notify the applicant of the missed deadline and grant an extension of 15  
business days. If the electric utility does not receive the signed level 4 and  
5 interconnection agreement and payment, if applicable, during the  
15-business-day extension, the electric utility may consider the  
interconnection application withdrawn, subject to subrule (6)(b) of this  
rule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904,  
formal mediation pursuant to R 460.906, or the complaint process pursuant  
to R 792.10439 to R 792.10446 within 30 business days, the outcome of  
that process must establish a time frame for the applicant to return the  
signed interconnection agreement and applicable payment. There is a  
rebuttable presumption in the complaint proceeding that the electric  
utility’s standard construction, procurement, installation, design, and cost  
practices are lawful, reasonable, and prudent.  
(i) For study track interconnection applications filed with an electric utility  
conducting batch studies, if either informal mediation pursuant to R  
460.904, formal mediation pursuant to R 460.906, or the complaint process  
pursuant to R 792.10439 to R 792.10446 does not result in the applicant  
returning a signed interconnection agreement with any applicable payment  
prior to the electric utility beginning the study phase of the next batch study  
pursuant to R 460.956, the electric utility may not include the  
interconnection application in the system baseline for conducting the next  
batch study. If the interconnection application is electrically coincident with  
other interconnection applications in the next batch study, the electric utility  
may require the withdrawal of the interconnection application.  
(ii) For study track interconnection applications filed with an electric utility  
conducting individual studies, electrically coincident applications filed after  
the interconnection application must be placed on hold for not more than 60  
business days. If either informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446 does not result in the applicant returning a  
signed interconnection agreement with any applicable payment within 60  
business days and there are electrically coincident interconnection  
applications in progress behind this application, the electric utility may  
require the withdrawal of the interconnection application.  
39  
(7) For level 4 or 5 projects, an electric utility shall countersign and provide a  
completed copy of the level 4 and 5 interconnection agreement within 10  
business days of the applicant returning a mutually agreed-upon and signed  
level 4 and 5 interconnection agreement.  
(8) An applicant shall pay the actual cost of the interconnection facilities and  
distribution upgrades. The cost to the applicant for interconnection facilities  
and distribution upgrades may not exceed 110% of the estimate without an  
itemized summary and explanation of cost increases being provided to the  
applicant prior to being incurred. The cost may not exceed 125% of the  
estimate without the consent of the applicant prior to the costs being  
incurred.  
(9) A party’s obligations under the interconnection agreement may be extended  
by agreement. If a party anticipates that it will be unable to meet a  
milestone for any reason other than an unforeseen event, the party shall do  
all of the following:  
(a) Immediately notify the other party of the reason or reasons for not meeting  
the milestone.  
(b) Propose the earliest alternate date when it can attain this and future  
milestones.  
(c) Request amendments to the interconnection agreement, if needed to address  
the changed milestones.  
(10) The party affected by the failure to meet a milestone shall not withhold  
agreement to any amendments proposed in subrule (9)(c) of this rule unless  
1 of the following applies:  
(a) The party affected will suffer significant uncompensated economic or  
operational harm from the amendment or amendments.  
(b) The milestone under question has been previously delayed.  
(c) The affected party has reason to believe that the delay in meeting the  
milestone is intentional or unwarranted notwithstanding the circumstances  
explained by the party proposing the amendment.  
(11) If the party affected by the failure to meet a milestone disputes the proposed  
extension, the affected party may pursue either informal mediation pursuant  
to R 460.904, formal mediation pursuant to R 460.906, or the complaint  
process pursuant to R 792.10439 to R 792.10446.  
(12) The electric utility shall provide the applicant with a final accounting report  
of any difference between costs charged to the applicant and previous  
payments to the electric utility for interconnection facilities or distribution  
upgrades.  
(a) If the costs charged to the applicant exceed its previous aggregate payments,  
the electric utility shall bill the applicant for the amount due and the  
applicant shall make a payment to the electric utility within 20 business  
days of the final accounting report. The applicant may dispute the invoice  
pursuant to either informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446. If there is a dispute, the applicant shall make  
40  
payment within 30 business days of final resolution of the dispute. Failure  
by the applicant to pay its costs is cause for disconnection of the applicant’s  
DER.  
(b) If the applicant’s previous aggregate payments exceed its costs under the  
construction agreement, the electric utility shall refund to the applicant an  
amount equal to the difference within 20 business days of the final  
accounting report.  
(13) The electric utility is responsible for specifying requirements in  
interconnection agreements to support independent system operator  
regulations or regional transmission operator regulations.  
(14) The electric utility may propose to the commission that a signed  
interconnection agreement be modified to require compliance with changes  
to an independent system operator, a regional transmission operator, or the  
state’s regulations, provided that these modifications do not alter the rights  
or obligations of the interconnection customer.  
R 460.966 Inspection, testing, and commissioning.  
Rule 66. (1) If the interconnection application requires  
telecommunications, cybersecurity, data exchange or  
remote controls operation, successful testing and  
certification of these items must be completed prior to or  
during testing. The electric utility’s interconnection  
procedures must describe the technical requirements of  
these items.  
(2) An applicant shall notify the electric utility when installation of a  
DER and any required local code inspection and  
approval is complete. The applicant shall provide any  
test reports or configuration documents as defined in the  
standard level 1, 2, and 3 interconnection agreement or  
level 4 and 5 interconnection agreement.  
(3) The electric utility shall review the applicant’s inspection, test  
reports, or configuration documents, and communicate  
its intent to perform a witness or commissioning test, or  
waive its right to perform a witness test and  
commissioning test within 10 business days.  
(4) If the electric utility intends to witness or perform commissioning  
tests required to comply with the interconnection  
agreement or the interconnection procedures and inspect  
the DER, the electric utility shall witness or perform the  
commissioning tests and inspect the DER within either  
of the following:  
(a) Ten business days of receiving the notification from the applicant  
pursuant to subrule (2) of this rule, for level 1, 2, and 3  
applications.  
41  
(b) A mutually-agreed upon timeframe after receiving the notification  
from the applicant pursuant to subrule (2) of this rule for  
level 4 and 5 applications.  
(5) The electric utility may waive its right to visit the site and inspect  
the DER or perform the commissioning tests.  
(a) If the electric utility waives this right, it shall provide a written  
waiver to the applicant within 10 business days from  
receiving the notification from the applicant pursuant to  
subrule (2) of this rule.  
(b) The applicant shall provide the electric utility with the completed  
commissioning test report within 20 business days of  
receipt of the electric utility’s written waiver.  
(6) If the electric utility attempts to conduct the inspection and testing  
pursuant to subrule (4) of this rule at the arranged time  
and is unable to access the DER or complete the testing,  
the DER must remain disconnected until the applicant  
and the electric utility can complete the inspection and  
testing.  
(7) If the electric utility witnessed or performed commissioning tests  
and inspected the DER pursuant to subrule (4) of this  
rule, within 5 business days of the receipt of the  
completed commissioning test report, the electric utility  
shall notify the applicant whether it has accepted or  
rejected the commissioning test report and found the site  
to be satisfactory or unsatisfactory.  
(a) If the commissioning test report is accepted and the site was found  
satisfactory, the electric utility shall provide the  
notification of acceptance in writing, and the  
interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report or did  
not find the site satisfactory, the electric utility shall  
provide its reasons for doing so in writing and the  
applicant has not less than 20 business days to  
implement corrections. The applicant, after taking  
corrective action, shall request the electric utility to  
reconsider its findings. The applicant may be billed the  
actual cost of any re-inspections.  
(8) If the electric utility waived its right to witness or perform  
commissioning tests and inspect the DER pursuant to  
subrule (5) of this rule, within 5 business days of the  
receipt of the completed commissioning test report, the  
electric utility shall notify the applicant whether it has  
accepted or rejected the commissioning test report.  
42  
(a) If the commissioning test report is accepted, the electric utility  
shall provide notification of acceptance, and the  
interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report, the  
electric utility shall provide its reasons for doing so in  
writing and the applicant has not less than 20 business  
days to implement corrections. The applicant, after  
taking corrective action, may then request the electric  
utility to reconsider its findings.  
(9) The cost of testing and inspection for applicants participating in an  
electric utility’s distributed generation program, as  
described in part 3 of these rules, R 460.1001 to R  
460.1026, are considered a cost of operating a  
distributed generation program and must be recovered  
pursuant to section 175(1) of the clean and renewable  
energy and energy waste reduction act, 2008 PA 295,  
MCL 460.1175.  
(10) If the applicant does not notify the electric utility that the DER is  
installed and ready to test pursuant to subrule (2) of this  
rule, the electric utility may, in writing, query the status  
of the interconnection. If the applicant does not provide  
a written response within 10 business days or no  
progress is evident, the electric utility may consider the  
interconnection application withdrawn.  
R 460.968 Authorization required prior to parallel operation.  
Rule 68. (1) The electric utility shall provide to the applicant written authorization to operate in  
parallel with the electric utility within 5 business days of all of the following conditions  
being met:  
(a) The electric utility notified the interconnection applicant that the commissioning test and  
inspection, where applicable, are accepted.  
(b) The applicant complied with all applicable parallel operation requirements as set forth in  
the electric utility’s interconnection procedures and applicable interconnection  
agreement.  
(c) The applicant complied with all applicable local, state, and federal requirements.  
(d) The electric utility received full payments for all outstanding bills.  
(2) With the written authorization, interconnection of the DER is considered approved for  
parallel operation, the DER may begin operating, and the applicant is considered an  
interconnection customer.  
(3) The applicant shall not operate its DER in parallel with the electric utility’s distribution  
system without prior written permission to operate from the electric utility.  
(4) Subject to reasonable timing and other conditions, including completion of conditions in the  
interconnection agreement or interconnection procedures, the electric utility shall allow  
for reasonable but limited testing before written authorization has occurred.  
43  
R 460.970 Cost allocation of interconnection facilities and distribution upgrades.  
Rule 70. Costs for interconnection facilities and distribution upgrades must be  
classified into 1 of the following categories:  
(a) Site-specific costs, which include, but are not limited to, costs of  
interconnection facilities and distribution upgrades that are caused by 1  
DER, whether that DER is electrically co-incident with other DERs. These  
costs must be assigned to the cost-causing applicant.  
(b) Shared interconnection facilities costs, which are costs caused by DERs which  
together necessitate the construction of interconnection facilities. The  
interconnection facilities costs that should be shared must be allocated to  
each applicant based on a methodology described in the electric utility’s  
interconnection procedures.  
(c) Shared distribution upgrade costs, which are costs caused by electrically  
co-incident DERs that together necessitate a distribution upgrade. The  
distribution upgrade costs that should be shared must be allocated to each  
applicant based on a methodology described in the electric utility’s  
interconnection procedures.  
R 460.974 Interconnection metering and communications.  
Rule 74. (1) Any metering and communications requirements necessitated by use of the  
DER must be installed at the applicant’s expense. The electric utility may furnish this  
equipment at the applicant’s expense.  
(2) The electric utility may charge the interconnection customer reasonable ongoing fees  
to maintain the metering and communications equipment. These fees must be listed in the  
interconnection agreement.  
R 460.976 Post commissioning remedy.  
Rule 76. (1) If the electric utility finds that the DER is operating outside the terms of the  
interconnection agreement but does not find immediate disconnection pursuant to R  
460.978(1)(f) and (g) warranted, the electric utility shall promptly inform the  
interconnection customer or its agent of this finding. The interconnection customer is  
responsible for bringing the DER into compliance within 30 business days or a mutually  
agreed-upon time period. The electric utility may perform an inspection of the DER after  
a remedy is applied.  
(2) If the DER is not brought into compliance within 30 business days or the mutually  
agreed-upon time period, the electric utility may apply a remedy and bill the  
interconnection customer. The interconnection customer shall pay this bill within 5  
business days.  
R 460.978 Disconnection.  
44  
Rule 78. (1) An electric utility may refuse to connect or may disconnect a project from  
the distribution system if any of the following conditions apply:  
(a) Failure of the interconnection customer to bring a DER into compliance pursuant to  
R 460.976(1).  
(b) Failure of the interconnection customer to pay costs of remedy pursuant to R  
460.976(2).  
(c) Termination of interconnection by mutual agreement.  
(d) Distribution system emergency, but only for the time necessary to resolve the  
emergency.  
(e) Routine maintenance, repairs, and modifications performed in a reasonable time and  
with prior notice to the interconnection customer.  
(f) Noncompliance with technical or contractual requirements in the interconnection  
agreement that could lead to degradation of distribution system reliability, electric utility  
equipment, and electric customers’ equipment.  
(g) Noncompliance with technical or contractual requirements in the interconnection  
agreement that presents a safety hazard.  
(h) Other material noncompliance with the interconnection agreement.  
(i) Operating in parallel without prior written authorization from the electric utility as  
provided for in R 460.968.  
(2) An electric utility may disconnect electric service, where applicable, pursuant to R  
460.136.  
R 460.980 Capacity of the DER.  
Rule 80. (1) If the interconnection application requests an increase in capacity for an existing  
DER, the electric utility shall evaluate the application based on the new nameplate  
capacity of the DER. The maximum capacity of a DER is the aggregate nameplate  
capacity or may be limited as described in the electric utility’s interconnection  
procedures.  
(2) An interconnection application for a DER that includes single or multiple types of DERs at  
a site for which the applicant seeks a single point of common coupling must be evaluated  
as described in the electric utility’s interconnection procedures.  
(3) The electric utility’s interconnection procedures must describe acceptable methods for  
power limited export DER including, but not limited to, reverse power protection and  
utilizing inverters or control systems so that the DER capacity considered by the electric  
utility for reviewing the interconnection application is only the amount capable of being  
exported.  
R 460.982 Modification of the interconnection application.  
Rule 82. (1) At any point after an interconnection application is considered accepted  
but before the signing of an interconnection agreement, the applicant, the electric utility,  
or the affected system owner may propose modifications to the interconnection  
application that may improve the costs and benefits of the interconnection, or that  
improve the ability of the electric utility to accommodate the interconnection. The  
45  
applicant shall submit to the electric utility, in writing, all proposed modifications to any  
information provided in the interconnection application and the electric utility shall  
perform a cursory evaluation to determine whether the proposed modification is a  
material modification and provide the results to the applicant within 10 business day.  
(2) The electric utility shall not be required to accept or implement a modification to the  
electric utility’s distribution system or generation assets that is proposed by an applicant  
or affected system operator.  
(3) Neither the electric utility nor the affected system operator may unilaterally modify  
an accepted interconnection application. If the electric utility evaluates DERs using  
individual studies, the timelines specific to that interconnection application must be  
placed on hold while the proposed modification is being evaluated by the electric utility.  
(4) For a proposed modification which the electric utility has determined is a material  
modification, the applicant may request a material modification review to determine  
whether the material modification is an acceptable material modification or an  
unacceptable material modification. The electric utility shall complete the material  
modification review and determine which of the following options are available to the  
applicant:  
(a) If the modification is an unacceptable material modification, the applicant may  
withdraw the modification or withdraw the application.  
(b) If the modification is an acceptable material modification and requires minimal or  
no restudy, the application study activities will resume with the modification and no  
change to the timing.  
(c) If the modification is an acceptable material modification but requires restudy, the  
electric utility shall expedite the restudy. The applicant shall pay any required fee for the  
expedited restudy.  
(5) The applicant may request a 1-hour consultation to discuss the results of the material  
modification review.  
(6) The applicant shall notify the electric utility of its selection pursuant to subrule (4) of this  
rule within 10 business days of receiving the electric utility notification of the results or  
the modification may be considered withdrawn.  
(7) If the proposed modification is determined not to be a material modification or is  
determined to be an acceptable material modification, the electric utility shall notify the  
applicant that the proposed modification has been accepted.  
(8) If the modification is considered an unacceptable material modification, the applicant shall  
withdraw the proposed modification, or initiate mediation pursuant to R 460.904 or R  
460.906, or file a complaint pursuant to R 792.10439 to R 792.10446 within 10 business  
days of receipt of the decision, or proceed with a new interconnection application for this  
modification. If the applicant does not provide its determination within the 10 business  
days, the electric utility may consider the interconnection application withdrawn.  
(9) Any modification to the interconnection application or to the DER that could affect  
the operation of the distribution system, including but not limited to, changes to machine  
data, equipment configuration, or the interconnection site of the DER, not agreed to in  
writing by the electric utility and the applicant may be treated by the electric utility as a  
withdrawal of the interconnection application requiring submission of a new  
interconnection application.  
46  
(10) At any point prior to the execution of an interconnection agreement, changes to  
ownership will cause the interconnection application to be put on hold until the new  
owner signs all necessary agreements and documents. An electric utility may not be  
found in violation of these rules related to the processing of the interconnection  
application during such a transfer of ownership.  
(11) Replacing a component with another component that has near-identical  
characteristics does not constitute a material modification.  
(12) The electric utility’s interconnection procedures must provide examples of  
modification that are not material modifications, acceptable material modifications, and  
unacceptable material modifications.  
(13) The electric utility’s interconnection procedures must provide a procedure for  
performing a material modification review.  
R 460.984 Modifications to the DER.  
Rule 84. After the execution of the interconnection agreement, the applicant shall notify  
the electric utility of any plans to modify the DER. The electric utility shall review the  
proposed modification to determine if the modification is considered a material  
modification. If the electric utility determines that the modification is a material  
modification, the electric utility shall notify the applicant, in writing of its determination  
and the applicant shall submit a new application and application fee along with all  
supporting materials that are reasonably requested by the electric utility. The applicant  
may not begin any material modification to the DER until the electric utility has accepted  
the new interconnection application and completed at least one of the following:  
(a) An initial review.  
(b) A supplemental review.  
(c) A system impact study.  
(d) A facilities study.  
R 460.986 Insurance.  
Rule 86. (1) An applicant interconnecting a level 1 or 2 project to the distribution  
system of an electric utility may not be required by the electric utility to obtain any  
additional liability insurance.  
(2) An electric utility shall not require an applicant interconnecting a level 1 or 2 project  
to name the electric utility as an additional insured party.  
(3) For a level 3 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $1,000,000.  
(4) For a level 4 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $2,000,000.  
(5) For a level 5 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $3,000,000.  
R 460.988 Easements and rights-of-way.  
47  
Rule 88. If an electric utility line extension is required to accommodate an  
interconnection, the applicant is responsible for procurement and the cost of providing  
and obtaining easements or rights-of-way.  
R 460.990 Interconnection penalties.  
Rule 90. Pursuant to section 10e of 1939 PA 3, MCL 460.10e, an electric utility shall  
take all necessary steps to ensure that DERs are connected to the distribution systems  
within their operational control. If the commission finds, after notice and hearing, that an  
electric utility has prevented or unduly delayed the ability of a DER greater than 100 kW  
to connect to the distribution system of the electric utility, the commission may order  
remedies designed to make whole the applicant proposing the DER, including, but not  
limited to, reasonable attorney fees. If the electric utility violates this rule, the  
commission may order fines of not more than $50,000 per day, commensurate with the  
demonstrated impact of the violation.  
R 460.991 Catastrophic conditions.  
Rule 91. An electric utility shall notify the commission and all applicants that have  
in-process applications when timelines are being extended due to catastrophic conditions  
as defined in R 460.702(f). The electric utility shall also notify the commission and all  
applicants that have in-process applications when application processing resumes.  
R 460.992 Electric utility annual reports.  
Rule 92. An electric utility shall file an annual interconnection report on a date and in a  
format determined by the commission.  
PART 3. DISTRIBUTED GENERATION PROGRAM STANDARDS  
R 460.1001 Application process.  
Rule 101. (1) An electric utility shall file initial distributed generation program tariff  
sheets in the first rate case filed after June 1, 2018.  
(2) Within 30 days of a commission order approving an electric utility’s initial  
distributed generation tariff, or within 30 days of the effective date of these rules,  
whichever is later, an alternative electric supplier serving customers in that electric  
utility’s service territory shall file an updated distributed generation program plan  
applicable to its customers in the affected electric utility’s service territory.  
(3) An electric utility and an alternative electric supplier shall annually file a legacy net  
metering program report and, if applicable, a distributed generation program report not  
later than March 31 of each year.  
(4) An electric utility and an alternative electric supplier shall maintain records of all  
applications and up-to-date records of all eligible electric generators participating in the  
legacy net metering program and distribution generation program.  
48  
(5) Selection of customers for participation in the legacy net metering program or  
distributed generation program must be based on the order in which the applications are  
received.  
(6) An electric utility or alternative electric supplier shall not refuse to provide or  
discontinue electric service to a customer solely because the customer participates in the  
legacy net metering program or distributed generation program.  
(7) The legacy net metering program and distributed generation program provided by  
electric utilities and alternative electric suppliers must be designed for a period of not less  
than 10 years and limit each applicant to generation capacity designed to meet up to  
100% of the customer’s electricity consumption for the previous 12 months.  
(a) The generation capacity must be determined by an estimate of the expected annual  
kWh output of the generator or generators as determined in an electric utility’s  
interconnection procedures and specified on an electric utility's legacy net metering  
program or distributed generation program tariff sheet or in the alternative electric  
supplier’s legacy net metering program or distributed generation program plan. For  
projects in which energy export controls are implemented pursuant to section R 460.980  
and utilized to limit the export to 100% of the customer’s electricity consumption for the  
previous 12 months, an electric utility shall not add the storage capacity to generation  
capacity for the purpose of the study. If a customer has multiple inverters capable of  
exporting to the distribution grid, the inverters must be configured in a way that prevents  
the cumulative maximum export at any given time to exceed the approved amount in the  
customer’s application.  
(b) A customer’s electric consumption must be determined by 1 of the following  
methods:  
(i) The customer’s annual energy consumption, measured in kWh, during the previous  
12-month period.  
(ii) If there is no data, incomplete data, or incorrect data for the customer’s energy  
consumption or the customer is making changes on-site that will affect total consumption,  
the electric utility or alternative electric supplier and the customer shall mutually agree on  
a method to determine the customer’s electric consumption.  
(c) A net metering or distributed generation customer using an energy storage device in  
conjunction with an eligible electric generator shall not design or operate the energy  
storage device in a manner that results in the customer’s electrical output exceeding  
100% of the customer’s electricity consumption for the previous 12 months. Energy  
storage devices must be configured to prevent export of stored electricity to the  
distribution system. The addition of an energy storage device to an existing approved  
legacy net metering program system or distributed generation program system is  
considered a material modification. The electric utility interconnection procedures must  
include details describing how energy storage equipment may be integrated into an  
existing legacy net metering program system without impacting the 10-year  
grandfathering period.  
(8) An applicant shall notify the electric utility of plans for any material modification to  
the project. An applicant shall re-apply for interconnection pursuant to part 2 of these  
rules, R 460.911 to R 460.992, and submit revised legacy net metering program or  
distributed generation program application forms and associated fees. An applicant may  
49  
be eligible to continue participation in the legacy net metering program or distributed  
generation program when a material modification is made to a customer’s previously  
approved system and it does not violate the requirements of subrule (7) of this rule. An  
applicant shall not begin any material modification to the project until the electric utility  
has approved the revised application, including any necessary system impact study or  
facilities study. The application must be processed pursuant to part 2 of these rules, R  
460.911 to R 460.992.  
R 460.1004 Legacy net metering program application and fees.  
Rule 104. (1) An electric utility or alternative electric supplier may use an online legacy  
net metering program application process. An electric utility or alternative electric  
supplier not using an online application process, may utilize a uniform legacy net  
metering program application form which must be approved by the commission. An  
electric utility’s legacy net metering program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the legacy net metering program shall concurrently submit a completed  
legacy net metering program application and interconnection application or indicate on  
the legacy net metering program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968.  
(a) Where a legacy net metering program application is accompanied by an associated  
interconnection application, an electric utility shall complete its review of the legacy net  
metering program application in parallel with processing the interconnection application  
pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, the electric utility shall notify the customer whether  
the legacy net metering program application is accepted, and provide an opportunity for  
the customer to resolve any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application, or the electric utility may consider the legacy  
net metering program application withdrawn without refund of the application fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.940 simplified track or R 460.946 fast track initial review, the electric  
utility shall determine whether the appropriate meter or meters, is installed for the legacy  
net metering program.  
(b) When a legacy net metering program application is filed with an already in-progress  
interconnection application, the utility may process the legacy net metering application in  
parallel with the interconnection application pursuant to part 2 of these rules, R 460.911  
to R 460.992, and subrule (2)(a) of this rule, if practicable, or adopt the review process  
pursuant to subrule (2)(c) of this rule.  
(c) When a legacy net metering program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the legacy net metering program application in parallel with the interconnection  
application, or when the legacy net metering application is filed subsequent to the  
50  
customer receiving authorization to operate its eligible generator in parallel pursuant to R  
460.968, the electric utility shall process the legacy net metering program application  
pursuant to both of the following:  
(i) The electric utility shall review the legacy net metering program application and  
determine whether to accept the application pursuant to the timelines in R 460.936(6) and  
(7) within 10 business days. The timelines in R 460.936(7)(a) apply to electric utility  
notifications. The electric utility shall provide the customer an opportunity to resolve any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
deficiency within the timelines pursuant to R. 460.936(7)(b), the electric utility may  
consider the legacy net metering application withdrawn without refund of the application  
fees.  
(ii) Within 10 business days of notifying the customer that the legacy net metering  
application has been accepted, the electric utility shall determine whether the appropriate  
meter is installed for the legacy net metering program.  
(d) If a customer approved for participation in the legacy net metering program requires  
a new or additional meter or meters, the electric utility shall arrange with the customer to  
install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit the  
distributed generation program credit to be applied to the account no more than 10  
business days after the necessary meter is installed and all necessary steps in R 460.966  
are completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed legacy net metering program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The electric utility shall process the legacy net metering program application  
according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit the legacy net  
metering program credit to be applied to the account.  
(4) If a legacy net metering program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the deficiency  
within the timelines pursuant to R. 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the legacy net metering application withdrawn without  
refund of the application fees.  
(5) If a customer’s application for the legacy net metering program is approved, the  
customer shall have a completed and approved installation within 6 months from the date  
the customer’s application is considered complete, or the electric utility or alternative  
51  
electric supplier may terminate the application without refund and shall have no further  
responsibility with respect to the application.  
(6) Customers participating in a legacy net metering program approved by the  
commission before the commission establishes a tariff pursuant to section 6a(14) of 1939  
PA 3, MCL 460.6a, may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment.  
(7) The legacy net metering program application fee for electric utilities and alternative  
electric suppliers may not exceed $50. The fee must be specified on the electric utility’s  
legacy net metering tariff sheet or in the alternative electric supplier's legacy net metering  
program plan.  
R 460.1006 Distributed generation program application and fees.  
Rule 106. (1) An electric utility or alternative electric supplier may use an online  
distributed generation program application process. An electric utility or alternative  
electric supplier not using an online application process may utilize a uniform distributed  
generation program application form that must be approved by the commission. An  
electric utility’s distributed generation program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the distributed generation program shall concurrently submit a completed  
distributed generation program application and interconnection application or indicate on  
the distributed generation program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968.  
(a) When a distributed generation program application is accompanied by an associated  
interconnection application, an electric utility shall complete its review of the distributed  
generation program application in parallel with processing the interconnection application  
pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, an electric utility shall notify the customer whether  
the distributed generation program application is accepted, and provide an opportunity for  
the customer to remedy any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the electric utility may consider the  
distributed generation program application withdrawn without refund of the application  
fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.940 simplified track or R 460.946 fast track initial review, the electric  
utility shall determine whether the appropriate meter is installed for the distributed  
generation program.  
(b) If a distributed generation program application is filed with an already in-progress  
interconnection application, the electric utility may process the distributed generation  
program application in parallel with the interconnection application pursuant to part 2 of  
52  
these rules, R 460.911 to R 460.992, and subrule (2)(a) of this rule, if practicable, or  
adopt the review process pursuant to subrule (2)(c) of this rule.  
(c) If a distributed generation program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the distributed generation program application in parallel with the  
interconnection application or the distributed generation application is filed subsequent to  
the customer receiving authorization to operate its eligible generator in parallel pursuant  
to R 460.968, the electric utility shall process the distributed generation program  
application pursuant to all of the following:  
(i) The electric utility has 10 business days to review the distributed generation  
program application and determine whether to accept the application pursuant to the  
timelines in R 460.936(6) and (7). The timelines in R 460.936(7)(a) apply to utility  
notifications. The electric utility shall provide the customer an opportunity to remedy any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
application deficiencies within the timelines in R 460.936(7)(b), the electric utility may  
consider the distributed generation program application withdrawn without refund of the  
application fees.  
(ii) Within 10 business days of providing notification to the customer that the  
distributed generation program application has been accepted, the electric utility shall  
determine whether the appropriate meter, or meters, is installed for the distributed  
generation program.  
(d) If a customer approved for participation in the distributed generation program  
requires a new or additional meter or meters, the electric utility shall arrange with the  
customer to install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit  
distributed generation program credit to be applied to the account no more than 10  
business days after the necessary meter is installed and all necessary steps in R 460.966  
are completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed distributed generation program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The alternative electric supplier shall process the distributed generation program  
application according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit distributed generation  
program credit to be applied to the account.  
(4) If a distributed generation program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
53  
deficiencies within the timelines in R 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the distributed generation program application withdrawn  
without refund of the application fees.  
(5) If a customer’s distributed generation program application is approved, the customer  
shall have a completed and approved installation within 6 months from the date the  
customer’s application is considered complete, or the electric utility or alternative electric  
supplier may consider the application withdrawn without refund and shall have no further  
responsibility with respect to the application.  
(6) The distributed generation program application fee for electric utilities and  
alternative electric suppliers shall not exceed $50. The electric utility shall specify the fee  
on the electric utility’s distributed generation program tariff sheet or in the alternative  
electric supplier’s distributed generation program plan.  
(7) The customer shall pay all interconnection costs pursuant to part 2 of these rules, R  
460.911 to R 460.992, which include all electric utility costs associated with the  
customer’s interconnection that are not a distributed generation program application fee,  
excluding meter costs as described in R 460.1012 and R 460.1014.  
R 460.1008 Legacy net metering program and distributed generation program size.  
Rule 108. (1) If an electric utility or alternative electric supplier reaches the program  
sizes as defined in section 173(3) of the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1173, as determined by combining both the  
distributed generation program and the legacy net metering program customer  
enrollments, the electric utility or alternative electric supplier shall notify the  
commission.  
(2) The electric utility or alternative electric supplier shall notify the commission of its  
plans to either close the program to new applicants or expand the program.  
(3) The electric utility shall file corresponding revised legacy net metering program or  
distributed generation program tariff sheets.  
(4) The alternative electric supplier shall file a revised legacy net metering program plan  
or distributed generation program plan.  
R 460.1010 Generation and legacy net metering program or distributed generation  
program equipment.  
Rule 110. New legacy net metering program or distributed generation program  
equipment and its installation must meet all current local and state electric and  
construction code requirements, and other standards as specified in part 2 of these rules,  
R 460.911 to R 460.992.  
R 460.1012 Meters for legacy net metering program.  
Rule 112. (1) For a customer with a generation system capable of generating 20 kWac or  
less, an electric utility may determine the customer’s net usage using the customer’s  
existing meter if it is capable of reverse registration or may install a single meter with  
54  
separate registers measuring power flow in each direction. If the electric utility uses the  
customer’s existing meter, the electric utility shall test and calibrate the meter to assure  
accuracy in both directions. If the customer’s meter is not capable of reverse registration  
and if meter upgrades or modifications are required, the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to the legacy net metering program customer. The cost of the meter or  
meter modification is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for the meter provided by the electric utility  
to similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter, if requested by the customer, at  
cost.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, the electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide this functionality, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a legacy net metering program customer. The cost of the meter or  
meters is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for meters provided by the electric utility to  
similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter is  
considered a cost of operating the legacy net metering program.  
(3) For a customer with a generation system capable of generating more than 150 kWac,  
the electric utility shall utilize a meter or meters capable of measuring the flow of energy  
in both directions and the generator output. If meter upgrades are necessary to provide  
this functionality, the customer shall pay the cost of providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a legacy net metering program participant or the legacy net  
metering program.  
R 460.1014 Meters for distributed generation program.  
Rule 114. (1) For a customer with a generation system capable of generating 20 kWac or  
less, an electric utility shall determine the customer’s power flow in each direction using  
the customer's existing meter if it is capable of measuring and recording power flow in  
each direction. If the customer’s meter is not capable of measuring and recording the  
customer’s power flow in each direction and if meter upgrades or modifications are  
required, all of the following apply:  
55  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring and recording the customer’s power flow in each  
direction at no additional charge to the distributed generation program customer. The cost  
of the meter or meter modification is considered a cost of operating the distributed  
generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring and recording the power flow in each direction to  
customers at cost. Only the incremental cost above the cost for the meter provided by the  
electric utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter at cost, if requested by the  
customer.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring and recording power flow in each direction and the generator output. If the  
customer’s meter is not capable of measuring and recording the customer’s power flow in  
each direction along with the generator output, and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a distributed generation program customer. If the electric utility  
provides the upgraded meter at no additional charge to the customer, the cost of the meter  
is considered a cost of operating the distributed generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above the cost for the meter provided by the electric  
utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter shall be  
considered a cost of operating the distributed generation program.  
(3) For a customer with a methane digester generation system capable of generating  
more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide such functionality, the customer shall pay the cost of  
providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a distributed generation program customer or the distributed  
generation program.  
R 460.1016 Billing and credit for legacy net metering program customers taking service  
under true net metering.  
Rule 116. (1) Legacy net metering program customers with a system capable of  
generating 20 kWac or less qualify for true net metering. For customers qualifying for  
true net metering, the net of the bidirectional flow of kWh across the customer  
56  
interconnection with the electric utility distribution system during the billing period or  
during each time-of-use pricing period within the billing period, including excess  
generation, shall be credited at the full retail rate.  
(2) The credit for excess generation, if any, shall appear on the next bill. Any excess  
credit not used to offset current charges must be carried forward for use in subsequent  
billing periods.  
R 460.1018 Billing and credit for legacy net metering program customers taking service  
under modified net metering.  
Rule 118. (1) Legacy net metering program customers with a system capable of  
generating more than 20 kWac qualify for modified net metering. A negative net metered  
quantity during the billing period or during each time-of-use pricing period within the  
billing period reflects net excess generation for which the customer is entitled to receive  
credit. Standby charges for customers on an energy rate schedule must equal the retail  
distribution charge applied to the imputed customer usage during the billing period. The  
imputed customer usage is calculated as the sum of the metered on-site generation and  
the net of the bidirectional flow of power across the customer interconnection during the  
billing period. The commission shall establish standby charges for customers on  
demand-based rate schedules that provide an equivalent contribution to electric utility  
system costs. Standby charges may not be applied to customers with systems capable of  
generating 150 kWac or less.  
(2) The credit for excess generation must appear on the next bill. Any excess kWh not  
used to offset current charges must be carried forward for use in subsequent billing  
periods.  
(3) A customer qualifying for modified net metering shall not have legacy net metering  
program credits applied to distribution charges.  
(4) The credit per kWh for kWh delivered into the electric utility’s distribution system  
must be either of the following as determined by the commission:  
(a) The monthly average real-time locational marginal price for energy at the  
commercial pricing node within the electric utility’s distribution service territory or for a  
legacy net metering program customer on a time-based rate schedule, the monthly  
average real time locational marginal price for energy at the commercial pricing node  
within the electric utility’s distribution service territory during the time-of-use pricing  
period.  
(b) The electric utility’s or alternative electric supplier’s power supply component,  
excluding transmission charges, of the full retail rate during the billing period or  
time-of-use pricing period.  
R 460.1020 Billing and credit for distributed generation program customers.  
Rule 120. As part of an electric utility’s rate case filed after June 1, 2018, the  
commission shall approve a tariff for a distributed generation program under the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to  
460.1211. A tariff established under this rule does not apply to customers participating in  
57  
a legacy net metering program under the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1001 to 460.1211, before the date that the  
commission establishes a tariff under this rule, who continue to participate in the program  
at their current site or facility.  
R 460.1022 Renewable energy credits.  
Rule 122. (1) An eligible electric generator shall own any renewable energy credits  
granted for electricity generated under the legacy net metering program and distributed  
generation program.  
(2) An electric utility may purchase or trade renewable energy credits from a legacy net  
metering program or distributed generation program customer if agreed to by the  
customer.  
(3) The commission may develop a program for aggregating renewable energy credits  
from legacy net metering program and distributed generation program customers.  
R 460.1024 Penalties.  
Rule 124. Upon a complaint or on the commission’s own motion, if the commission  
finds after notice and hearing that an electric utility has not complied with a provision or  
order issued under part 5 of the clean and renewable energy and energy waste reduction  
act, 2008 PA 295, MCL 460.1171 to 460.1185, the commission shall order remedies and  
penalties as necessary to make whole a customer or other person who has suffered  
damages as a result of the violation.  
R 460.1026 Legacy net metering grandfathering clause.  
Rule 126. A customer participating in a legacy net metering program approved by the  
commission before the commission establishes the initial distributed generation program  
tariff pursuant to R 460.1020 may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment. “Initial  
enrollment,” as used in this rule, means the date a customer or site initially enrolled in a  
legacy net metering program as described in the electric utility’s tariff. A customer  
participating in a legacy net metering program who increases the nameplate capacity of  
its generation system after the effective date of an electric utility’s distributed generation  
program tariff is no longer eligible to participate in the legacy net metering program.  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
* * * * *  
In the matter, on the Commission’s own motion, to  
)
)
)
)
promulgate rules governing electric interconnection  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
Case No. U-20890  
____________________________________________)  
COMMENTS OF THE  
ASSOCIATION OF BUSINESSES ADVOCATING TARIFF EQUITY  
I.  
INTRODUCTION  
The Association of Businesses Advocating Tariff Equity (“ABATE”), by its attorneys,  
Clark Hill PLC, hereby provides comments regarding the proposed administrative rules filed in  
this docket.  
II.  
COMMENTS  
A.  
Mich Admin Code, R 460.970 (Cost allocation of interconnection facilities  
and distribution upgrades).  
The section that pertains to the allocation of costs for interconnection facilities and  
distribution upgrades (Mich Admin Code, R 460.970) is important to ensure subsidies between  
customers are not created. It is not clear from the proposed rules, however, if they apply to both  
the installation costs and the ongoing operation and maintenance (“O&M”) of interconnection  
facilities and distribution upgrades. This section should be amended to ensure that all costs,  
including ongoing O&M, are paid by the cost-causing applicants. This is consistent with cost  
causation principles as well as the statutory requirement that the Commission establish cost of  
service rates. MCL 460.11(1).  
ClarkHill\09999\09998-3007\264412075.v1-10/20/21  
B.  
Mich Admin Code, R 460.650 and 460.652 (Billing and credit for  
true/modified net metering customers).  
The deletion of a sentence in these rescinded rules is concerning. The sentence that was  
deleted read, “If a customer leaves the electric utility’s distribution system or service is terminated  
for any reason, an electric utility or alternative electric supplier shall refund to the customer the  
remaining credit amount.” While this issue should be addressed in tariffs, it should also be  
addressed in the rules. As earned credits belong to the customer, this sentence should be added  
back to the proposed rules. Without including this requirement in the rules, it is not guaranteed to  
be adequately addressed elsewhere.  
Respectfully submitted,  
CLARK HILL PLC  
Stephen A. Campbell  
By: ____________________________________  
Digitally signed by: Stephen A. Campbell  
DN: CN = Stephen A. Campbell email =  
scampbell@clarkhill.com C = US O = Clark Hill PLC  
Date: 2021.11.01 11:20:17 -04'00'  
Michael J. Pattwell (P72419)  
Stephen A. Campbell (P76684)  
Attorneys for Association of Businesses  
Advocating Tariff Equity  
212 East César E. Chávez Avenue  
Lansing, MI 48906  
Office: 517-318-3100  
mpattwell@clarkhill.com  
scampbell@clarkhill.com  
Date: November 1, 2021  
ClarkHill\09999\09998-3007\264412075.v1-10/20/21  
DTE Electric Company  
One Energy Plaza, 1635 WCB  
Detroit, MI 48226-1279  
Jon P. Christinidis  
(313) 235-7706  
jon.christinidis@dteenergy.com  
November 1, 2021  
Ms. Lisa Felice  
Executive Secretary  
Michigan Public Service Commission  
7109 West Saginaw Highway  
Lansing, MI 48917  
RE: In the matter, on the Commission’s own motion, to promulgate rules governing  
electric interconnection and distributed generation, and rescind legacy  
interconnection and net metering rules.  
MPSC Case No. U-20890  
Dear Ms. Felice:  
Attached for electronic filing in the above-captioned matter is DTE Electric Company’s  
Comments pursuant to the Michigan Public Service Commission’s September 9, 2021 Order in Case  
No. U-20890.  
Very truly yours,  
Jon P. Christinidis  
JPC/erb  
Attachments  
cc:  
Service List  
S T A T E O F M I C H I G A N  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
* * * * *  
In the matter, on the Commission’s own motion, to )  
promulgate rules governing electric interconnection )  
reconciliation of its power supply cost recovery  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
)
)
)
)
Case No. U-20890  
COMMENTS OF DTE ELECTRIC COMPANY  
Introduction  
The Michigan Public Service Commission’s (“Commission” or “MPSC”) September 9,  
2021 Order in Case No. U-20890 (the “Order”) invited “comments, suggestions, data, views,  
questions, argument, and modifications concerning the issues” from interested stakeholders  
regarding the promulgation of the Interconnection and Distributed Generation Standards and the  
recission of the Electric Interconnection and Net Metering Standards. The order instructed that  
comments must be received no later than 5:00 p.m. (Eastern time) on November 1, 2021.  
DTE ElectricCompany (hereinafter “DTE Electric” or “Company”) appreciates the  
opportunity to provide comments regarding the proposed Interconnection and Distributed  
Generation Standards which the Commission describes as the “MIXDG rules” (hereinafter the  
“newly proposed rules”) and proposed recission of the Electric Interconnection and Net Metering  
Standards (hereinafter the “existing rules”). (Order p. 3) In light of the limited time frame to  
provide comments and the voluminous and complex nature of the newly proposed rules, various  
higher level procedural, legal and technical “comments,” “suggestions,” “views” and  
“modifications” are set forth below. Failure to address each and every issue or provision of the  
newly proposed rules should not necessarily be construed as agreement by the Company.  
Procedural Issues  
First, the Company notes that the Commission nearly one (1) year earlier, prior to  
providing this opportunity to comment, made separate Requests for Rulemaking, Regulatory  
Impact Statements (RIS), etc. and submitted both the newly proposed rules and existing rules for  
various approvals at other government agencies. Thus, it is unclear what effect, if any, might arise  
from this comment opportunity. The Company remains hopeful that its continuing concerns will  
be addressed but emphasizes that DTE Electric has Due Process rights under the Fourteenth  
Amendment to the United States Constitution. Michigan’s Constitution similarly provides DTE  
Electric with the right to fair and just treatment in MPSC proceedings: “No person shall be  
compelled in any criminal case to be a witness against himself, nor be deprived of life, liberty or  
property, without due process of law. The right of all individuals, firms, corporations and  
voluntary associations to fair and just treatment in the course of legislative and executive  
investigations and hearings shall not be infringed.” Michigan Const 1963, art 1, § 17.  
Second, the Commission identified several “stakeholder meetings” addressing a variety of  
topics and two (2) opportunities to comment on “two draft versions of the rules” – the last  
opportunity occurring in February 2020, more than 1 ½ years ago. (Order p. 3) Those efforts and  
opportunities, while not unappreciated, should also not be mistaken for something approaching  
consensus. For example, while some portions of the newly proposed rules are helpful in requiring  
interconnection applicants to maintain reasonable progress in pursuing their project, the newly  
proposed rules also impose unnecessarily complex and prescriptive processes likely to result in  
confusion, errors, misunderstandings and disagreement.  
In addition, the Company notes that the existing rules comprise seventeen (17) pages. The  
newly proposed rules, at fifty-three (53) pages, are more than three times as long and the  
2
Commission has acknowledged “the complexity of this rulemaking effort.” (Order p. 3) However,  
in many respects, that complexity is unnecessary and the rationale for promulgating new rules is  
not well explained or supported by meaningful facts or data. (See by way of example and not  
limitation, Order p. 2; Accord RIS p. 6 “…the process to interconnect customer or developer  
projects to the utility system can be untimely…”). Furthermore, by way of example and not  
limitation, the Regulatory Impact Statement’s conclusions that the newly proposed rules are  
“expected to streamline the interconnection process,” “do not impose a regulatory burden on  
Commission-regulated electric utilities that is excessive or overly burdensome,” and “do not  
extend beyond what is necessary” are unpersuasive and unsupported by data. (RIS pp. 6, 7, 8) The  
vast majority of interconnections to the DTE Electric distribution system are accomplished without  
significant issue. In fact, the Company has successfully interconnected over 6,000 small generators  
to its distribution system since the enactment of 2008 PA 295.  
Legal Considerations  
Several significant legal considerations are implicated by the newly proposed rules. The  
Administrative Procedures Act provides that:  
“A rule must not exceed the rulemaking delegation contained in the statute  
authorizing the rulemaking.” (MCL 24.232(7))  
The only specific grants of authority identified by the Commission with respect to the newly  
proposed rules include MCL 460.10e (addressing generally “merchant plants”)1 and MCL  
1
Most relevant to the instant rulemaking, MCL 460.10e provides: “The commission shall  
establish standards for the interconnection of merchant plants with the transmission and  
distribution systems of electric utilities. The standards shall not require an electric utility to  
interconnect with generating facilities with a capacity of less than 100 kilowatts for parallel  
operations. The standards shall be consistent with generally accepted industry practices and  
guidelines and shall be established to ensure the reliability of electric service and the safety of  
customers, utility employees, and the general public. The merchant plant will be responsible for  
all costs associated with the interconnection unless the commission has otherwise allocated the  
costs and provided for cost recovery.” (MCL 460.10e(3); emphasis added)  
3
460.1173 (addressing generally “distributed generation programs”)2. MCL 460.10e was enacted  
more than 20 years ago. Much of what is now MCL 460.1173 has been in place since 2008,  
although modified in some respects in 2016.  
In Consumers Power Co v Public Service Comm, 460 Mich 148, 155-56; 596 NW2d 126  
(1999), our Supreme Court explained:  
“The Public Service Commission has no common-law powers. It possesses only  
that authority granted by the Legislature. Union Carbide v Public Service Comm,  
431 Mich 135, at 146, 428 N.W.2d 322. Moreover, this Court strictly construes the  
statutes which confer power on the PSC. As this Court explained in Union Carbide,  
supra at 151, 428 N.W.2d 322, quoting Mason Co. Civic Research Council v Mason  
Co, 343 Mich 313, 326–327, 72 NW2d 292 (1955):  
“The power and authority to be exercised by boards or commissions must be  
conferred by clear and unmistakable language, since a doubtful power does not  
exist.”  
Noncompliance with the APA is reversible error. In re Public Service Commission Guidelines  
for Transactions Between Affiliates, 252 Mich App 254, 267; 652 NW2d 1 (2002) provided:  
“Invoking the public interest and the need for policy that is responsive to a  
changing industry, the PSC eschewed the procedural mandates of the APA in favor  
of its own course of action . . . While we do not doubt the PSC’s legitimate concerns  
. . . the process utilized by the PSC constituted a rather heavy-handed rebuke of  
established APA procedures, and, accordingly, we are compelled to invalidate that  
process” (252 Mich App at 267-68).  
2 As it relates specifically to rulemaking, MCL 460.1173 provides: “The commission shall establish  
a distributed generation program by order issued not later than 90 days after the effective date of  
the 2016 act that amended this section. The commission may promulgate rules the commission  
considers necessary to implement this program. Any rules adopted regarding time limits for  
approval of parallel operation shall recognize reliability and safety complications including those  
arising from equipment saturation, use of multiple technologies, and proximity to synchronous  
motor loads…If necessary to promote reliability or safety, the commission may promulgate rules  
that require the use of inverters that perform specific automated grid-balancing functions to  
integrate distributed generation onto the electric grid. (MCL 460.1173(1)(5)(b); emphasis added)  
4
The Commission cannot re-write the Legislature’s language to include new or different provisions.  
Hanson v Mecosta Co Rd Comm, 465 Mich 492, 501-503; 638 NW2d 396 (2002). If a Commission  
order conflicts with a statute, the order is void. Manufacturers Nat’l Bank v DNR, 420 Mich 128,  
146; 362 NW2d 572 (1984). Our Supreme Court recently reaffirmed that “agencies cannot  
exercise legislative power by creating law or changing the laws enacted by the Legislature.” In re  
Complaint of Rovas Against SBC Michigan, 482 Mich 90, 98; 754 NW2d 259 (2008) (Emphasis  
added).  
In light of the thousands of successful interconnections to DTE Electric’s and other  
Michigan electric utilities’ distribution systems, relatively static law, and limited “clear and  
unmistakable” direction to promulgate rules there are several instances where it is evident that the  
newly proposed ruleshave exceeded the Commission’s legislative directives.  
One example, includes the retroactive application of the newly proposed rules, which are  
implicated, for example, in newly proposed rules R 460.911, R 460.914, R 460.916 and R 460.918.  
The first of these newly proposed rules makes this intention clear:  
“These rules apply to all interconnection applications filed on or after the effective  
date of these rules and interconnection applications filed prior to the effective  
date of these rules that do not have an executed construction or interconnection  
agreement.” (R 460.911 Applicability)(emphasis added)  
However, there is no “clear and unmistakable” statutory authority to promulgate  
retroactively applicable administrative rules for interconnection or distributed generation.3  
Furthermore, there is a strong presumption against retroactive application of changes in the law  
3
There is also a longstanding prohibition against retroactive ratemaking that confirms the Commission has  
no such authority with respect to electric utility charges: “[T]he essential principal of the rule against  
retroactive ratemaking is that when the estimates prove inaccurate and costs are higher or lower than  
predicted, the previously set rates cannot be changed to correct for the error; the only step that the MPSC  
can take is to prospectively revise rates in an effort to set more appropriate ones.” The Detroit Edison Co  
v Public Service Comm, 416 Mich 510, 523; 331 NW2d 159 (1982) (opinion by Fitzgerald, C.J.).  
5
based on fundamental principles of fairness and predictability. The United States Supreme Court  
explained, for example:  
“As Justice SCALIA has demonstrated, the presumption against retroactive  
legislation is deeply rooted in our jurisprudence and embodies a legal doctrine  
centuries older than our Republic. Elementary considerations of fairness dictate  
that individuals should have an opportunity to know what the law is and  
conform their conduct accordingly; settled expectations should not be lightly  
disrupted. For this reason, the ‘principle that the legal effect of conduct should  
ordinarily be assessed under the law that existed when the conduct took place  
has timeless and universal appeal.’ [Kaiser Aluminum & Chemical Corp v  
Bonjorno, 494 US 827, 855; 110 S Ct 1570; 108 L Ed 2d 842 (1990)] (SCALIA,  
J., concurring). In a free, dynamic society, creativity in both commercial and artistic  
endeavors is fostered by a rule of law that gives people confidence about the legal  
consequences of their actions” (Landgraf v USI Film Products, 511 US 244, 265-  
66; 114 S Ct 1483; 128 L Ed 2d 229). (1994) (Emphasis added; footnotes omitted).  
Michigan Courts have followed Landgraf, recognizing that it would be improper to impose  
new burdens based on past circumstances, since the affected parties could not avoid the burdens  
because they already acted (or did nothing) based on the past circumstances. See for example,  
Frank W. Lynch & Co v Flex Technologies, Inc, 463 Mich 578, 585-87; 624 NW2d 180 (2001);  
Davis v State Employees’ Retirement Bd, 272 Mich App 151, 158; 725 NW2d 56 (2006) (noting  
Due Process concerns and that: “A statute may not be applied retroactively if it abrogates or  
impairs vested rights, creates new obligations, or attaches new disabilities concerning  
transactions or considerations occurring in the past”).  
Another example includes application of the newly proposed rules to limit electric utilities’  
management authority and use of their own property for their own business purposes – including  
electric utility-owned generation and distribution systems. Newly proposed rules R 460.901(a)(g)  
and (tt) as well as R 460.936(8) and (9) relevantly provide:  
(g) “Applicant” means the person or entity submitting an interconnection  
application, a legacy net metering program application, or a distributed generation  
program application. An applicant is not required to be an existing customer of an  
electric utility. An electric utility is considered an applicant when it submits an  
6
interconnection application for a DER that is not a temporary DER. (R  
460.901(a)(g); emphasis added)  
“(tt) ‘Interconnection customer’ means the person or entity, which may include  
the electric utility, responsible for ensuring a DER is operated and maintained in  
compliance with all local, state, and federal laws, as well as with all rules,  
standards, and interconnection procedures.” (R 460.901(a)(tt); emphasis added)  
“ (8) An electric utility shall comply with part 2 of these rules, R 460.911 to R  
460.992, and its interconnection procedures when interconnecting DERs that it  
owns and operates onto its distribution system, with the exception of temporary  
DERs.” (R 460.901(8); emphasis added)  
“(9) An electric utility shall use the same process when processing and studying  
interconnection applications from all applicants, whether the DER is owned or  
operated by the electric utility, its subsidiaries or affiliates, or others, with the  
exception of temporary DERs.” (R 460.936(9); emphasis added)  
The bounds of regulation are aptly described in Union Carbide v. Public Service Comm.,  
431 Mich 135; 428 NW2d 322 (1988)  
“The power to fix and regulate rates, however, does not carry with it, either  
explicitly or by necessary implication, the power to make management decisions.  
‘It must never be forgotten that while the State may regulate with a view to  
enforcing reasonable rates, it is not the owner of the property of public utility  
companies and is not clothed with the general power of management incident to  
ownership.’ [citations omitted]”.  
It is clear that the Commission is an economic regulator and not the operator of DTE Electric or  
its various facilities and there is no relevant administrative rulemaking authority to the contrary.  
Ford Motor Co. v. Public Service Comm, 221 Mich App 370, 385, 387-388; 562 NW2d 224 (1997)  
(“The PSC here exceeded its ratemaking authority by, in effect, requiring Detroit Edison’s  
management to adopt the DSM program the PSC thought best.”); Consumers Power Co, Public  
Service Comm, 189 Mich App 151, 180; 472 NW2d 77 (1991) (“To the extent that the PSC  
7
actually ordered Consumers to enter, or not enter, into any particular contract, it exceeded its  
authority”).4  
A third concern involves the newly proposed rules determination to utilize “fee caps” for  
actions and studies required by the rules (See, for example, R 460.920, R460.292, and R 460.928)  
as well as requirements to disclose through, inter alia a “Pre-application report”, various  
proprietary and commercially valuable electric utility system information to 3rd parties for only a  
nominal fee ($300) and despite the possibility it could be sensitive Critical Electric Infrastructure  
Information (CEII) (See, for example, R460.926 and R 460.932). The Company cannot be required  
to provide services without full compensation nor relinquish its property rights in proprietary  
business information (including but not limited to electrical system information) without just  
compensation. While the newly proposed rules permit “waiver” requests for “an electric utility  
that expects to incur costs greater than the initial fee caps” (See R 460.926(4)) the best potential  
outcome (assuming for the sake of discussion that appropriate relief from the Commission is  
eventually received) will be initial underpayment by developers with electric utilities left to seek  
collection of the actual costs from those developers. Furthermore, these mandated disclosures in  
no way address the market value of the information itself, which the newly proposed rules  
command be disclosed to other businesses with no compensation whatsoever for the commercial  
4
Consistent with Consumers, neither is there any apparent authority to require “standard level 1, 2, and 3  
interconnection agreements”. (See, for example R 460.901b(kk) and R 460.964) The Commission is an  
“administrative body created by statute and the warrant for the exercise of all its power and authority must be found  
in statutory enactments.” Union Carbide v Public Service Comm, 431 Mich 135, 146; 428 NW2d 322 (1988); Sparta  
Foundry Co v Public Utilities Comm, 275 Mich 562, 564; 267 NW 736 (1936). The Commission’s authority must be  
conferred by clear and unmistakable statutory language, and a doubtful power does not exist. Mason Co Civil Research  
Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955). The Commission cannot expand its jurisdiction  
through its own acts or assumption of authority. Ram Broadcasting v Public Service Comm, 113 Mich App 79, 92;  
317 NW2d 295 (1982). The Commission cannot re-write the Legislature’s language to include new or different  
provisions.4 Hanson v Mecosta Co Rd Comm, 465 Mich 492, 501-503; 638 NW2d 396 (2002). If a Commission order  
conflicts with a statute, the order is void. Manufacturers Nat’l Bank v DNR, 420 Mich 128, 146; 362 NW2d 572  
(1984)  
8
value of that information. At a minimum, these “fee caps” and mandated proprietary and  
commercially valuable electric utility information disclosures risk violation of the requirement that  
“[t]he merchant plant will be responsible for all costs associated with the interconnection unless  
the commission has otherwise allocated the costs and provided for cost recovery.” (MCL  
460.10e(3); Accord MCL 460.1175(1) “The customer shall pay all interconnection costs.”)  
However, in addition, DTE Electric has constitutional protections against “takings” and  
confiscatory rates under the Fifth Amendment to the US Constitution, which is applicable to the  
states through the Fourteenth Amendment. Similarly, the Michigan Constitution of 1963, art 10, §  
2 provides in part, “Private property shall not be taken for public use without just compensation  
therefore being first made or secured in a manner prescribed by law.”5  
Yet another overarching Due Process concern involves the complex dispute resolution  
procedures set forth in the newly proposed rules which provide for “Informal Mediation”, “Formal  
Mediation”, “Appointment of Experts”, “Contested Cases” and “Complaints.” (See generally R  
460.904, R 460.906, and R 460.908) Informal Mediation places Commission Staff in what appears  
to be the role of mediator. (See R 460.904(3)) Subsequent to any Informal Mediation, Formal  
5 These constitutional protections have been recognized and applied to public utility rates in well-established case law.  
See generally, Missouri ex rel Southwestern Bell Telephone Co v Public Service Comm of Missouri, 262 US 276; 43  
S Ct 544; 67 L Ed 981 (1923); Federal Power Comm v Natural Gas Pipeline, 315 US 575; 62 S Ct 736; 86 L Ed 1037  
(1942); Duquesne Light Co v Barasch, 488 US 299; 109 S Ct 609; 102 L Ed 2d 646 (1989). See also, Northern  
Michigan Water Co v Public Service Comm, 381 Mich 340; 161 NW2d 584 (1968); Consumers Power Co v Public  
Service Comm, 415 Mich 134; 327 NW2d 875 (1982); ABATE v Public Service Comm, 430 Mich 33; 420 NW2d 81  
(1988).Furthermore, as a matter of fundamental ratemaking law, DTE Electric and other electric utilities are entitled  
to a commensurate return of and on their investment in providing utility service. See, Bluefield Waterworks  
Improvement Co v Public Service Commission of West Virginia, 262 US 679, 690-694; 43 S Ct 675; 67 L Ed 1176  
(1923); Federal Power Comm v Hope Natural Gas Co, 320 US 591, 603; 64 S Ct 281; 88 L Ed 333 (1944). See also,  
Permian Basin Area Rate Cases, 390 US 747, 769-70; 88 S Ct 1344; 20 L Ed 2d 312 (1968); FPC v Memphis Light,  
Gas and Water Division, 411 US 458; 43 S Ct 1723; 36 L Ed 2d 426 (1973); General Telephone Co v Public Service  
Comm, 341 Mich 620; 67 NW2d 882 (1954); Michigan Consolidated Gas Co v Public Service Comm, 389 Mich 624;  
209 NW2d 210 (1973).  
9
Mediation appears to be required.6 Formal Mediation requires multiple submissions to the  
Commission and involves an Administrative Law Judge (ALJ) as mediator with “assistance from  
commission staff.” (R 460.906(1)(a)-(f)) And the newly proposed rules also appear to preserve the  
potential filing of a “contested case proceeding” pursuant to the Rules of Practice and Procedure  
Before the Commission (See generally, R 792.10401 et. seq.; See specific reference in newly  
proposed rule R 460.906(1)(f) to R 792.10415 “General Provisions” addressing a “contested case  
proceeding”). The newly proposed rules, however, also appear to preserve the right to file a  
complaint (addressed generally in R 792.10439 – R792.10446 of the Rules of Practice and  
Procedure Before the Commission) and when a complaint is filed the Commission may engage  
experts at the expense of the utility7 to “investigate the complaint and report findings to the  
Commission” and “[t]he reports of the experts must be received in evidence and the experts made  
available for cross examination by the parties.” (See R 460.908) It is unclear on whose behalf  
these experts would testify and how, procedurally, cross examination might work to ensure Due  
Process. It is also worthy of note that Staff has historically participated in contested cases and  
complaints8 as a party, so it is unclear under the newly proposed rules how Staff would reconcile  
its roles as mediator, provider of “assistance” to an ALJ mediator, and potential contested case  
party. Thus, the newly proposed rules contemplate the potential for at least four (4) forms of  
addressing disputes that are not mutually exclusive, lack clear adherence to the Administrative  
Procedures Act MCL 24.201 et. seq., and otherwise do not clearly ensure adequate Due Process.  
6 “(1) If the parties have been unable to resolve a dispute through the informal mediation process under R 460.904,  
the parties shall then attempt to resolve the dispute in the following manner:…” (R 460.906(1))(emphasis added)  
7 Here again, there is no provision in the newly proposed rules for an electric utility to recover the cost of providing  
such experts. See generally MCL 460.10e(3), Michigan Constitution of 1963, art 10, § 2, and the line of cases  
following Missouri ex rel Southwestern Bell Telephone Co v Public Service Comm of Missouri cited supra.  
8 A “complaint” is also a “contested case” but a “contested case” may not also be a “complaint.”  
10  
DTE Electric and others have Due Process rights under the Fourteenth Amendment to the  
United States Constitution. Michigan’s Constitution similarly provides DTE Electric with the right  
to fair and just treatment in MPSC proceedings: “No person shall be compelled in any criminal  
case to be a witness against himself, nor be deprived of life, liberty or property, without due  
process of law. The right of all individuals, firms, corporations and voluntary associations to fair  
and just treatment in the course of legislative and executive investigations and hearings shall not  
be infringed.” Michigan Const 1963, art 1, § 17. In addition, In re Public Service Commission  
Guidelines for Transactions Between Affiliates, 252 Mich App 254, 267; 652 NW2d 1 (2002)  
confirms that adherence to the Administrative Procedures Act is critical:  
“Invoking the public interest and the need for policy that is responsive to a  
changing industry, the PSC eschewed the procedural mandates of the APA in favor  
of its own course of action . . . While we do not doubt the PSC’s legitimate concerns  
. . . the process utilized by the PSC constituted a rather heavy-handed rebuke of  
established APA procedures, and, accordingly, we are compelled to invalidate that  
process” (252 Mich App at 267-68).  
At bottom, there are several significant overarching legal considerations (in addition to  
more specific concerns found throughout the details of the 53-pages of newly proposed rules) that  
must be addressed and remediated prior to formal adoption of a final rule on these topics.  
Technical Comments and Modifications  
In light of the complexity of the newly proposed rules and the limited time available to  
comment, the Company also wishes to highlight certain technical issues it has identified in the  
newly proposed rules which is accomplished in attached comments to the newly proposed rules  
submitted with these narrative comments (Attachment A).  
Respectfully Submitted,  
DTE ELECTRIC COMPANY  
11  
Attachment A  
DEPARTMENT OF LICENSING AND REGULATORY AFFAIRS  
PUBLIC SERVICE COMMISSION  
INTERCONNECTION AND DISTRIBUTED GENERATION STANDARDS  
Filed with the secretary of state on  
These rules take effect immediately upon filing with the secretary of state unless adopted  
under section 33, 44, or 45a(9) of the administrative procedures act of 1969, 1969 PA  
306, MCL 24.233, 24.244, or 24.245a. Rules adopted under these sections become  
effective 7 days after filing with the secretary of state.  
(By authority conferred on the public service commission by section 7 of 1909 PA 106,  
MCL 460.557, section 5 of 1919 PA 419, MCL 460.55, sections 4, 6, and 10e of 1939 PA  
3, MCL 460.4, 460.6, and 460.10e, and section 173 of the clean and renewable energy  
and energy waste reduction act, 2008 PA 295, MCL 460.1173)  
R 460.901a, R 460.901b, R 460.902, R 460.904, R 460.906, R 460.908, R 460.910, R  
460.911, R 460.914, R 460.916, R 460.918, R 460.920, R 460.922, R 460.924, R  
460.926, R 460.928, R 460.930, R 460.932, R 460.934, R 460.936, R 460.938, R  
460.940, R 460.942, R 460.944, R 460.946, R 460.948, R 460.950, R 460.952, R  
460.954, R 460.956, R 460.958, R 460.960, R 460.962, R 460.964, R 460.966, R  
460.968, R 460.970, R 460.974, R 460.976, R 460.978, R 460.980, R 460.982, R  
460.984, R 460.986, R 460.988, R 460.990, R 460.991, R 460.992, R 460.1001, R  
460.1004, R 460.1006, R 460.1008, R 460.1010, R 460.1012, R 460.1014, R 460.1016, R  
460.1018, R 460.1020, R 460.1022, R 460.1024, and R 460.1026 are added to the  
Michigan Administrative Code, as follows:  
PART 1. GENERAL PROVISIONS  
R 460.901a Definitions; A-I.  
Rule 1a. As used in these rules:  
(a) “AC” means alternating current at 60 Hertz.  
(b) “Affected system” means another electric utility’s distribution system, a municipal  
electric utility’s distribution system, the transmission system, or transmission system-  
connected generation which may be affected by the proposed interconnection.  
(c) “Affiliate” means that term as defined in R 460.10102(1)(a).  
(d) “Alternative electric supplier” means that term as defined in section 10g of 1939 PA  
3, MCL 460.10g.  
(e) “Alternative electric supplier distributed generation program plan” means a  
document supplied by an alternative electric supplier that provides detailed information to  
an applicant about the alternative electric supplier's distributed generation program.  
July 12, 2021  
2
(f) “Alternative electric supplier legacy net metering program plan” means a document  
supplied by an alternative electric supplier that provides detailed information to an  
applicant about the alternative electric supplier's legacy net metering program.  
(g) “Applicant” means the person or entity submitting an interconnection application, a  
legacy net metering program application, or a distributed generation program application.  
An applicant is not required to be an existing customer of an electric utility. An electric  
utility is considered an applicant when it submits an interconnection application for a  
DER that is not a temporary DER.  
(h) “Application” means an interconnection application, a legacy net metering program  
application, or a distributed generation program application.  
(i) “Area network” means a location on the distribution system served by multiple  
transformers interconnected in an electrical network circuit.  
(j) “Business day” means Monday through Friday, starting at 12:00:00 a.m. and ending  
at 11:59:59 p.m., excluding the following holidays: New Year’s Day, Martin Luther King  
Jr. Day, Presidents Day, Memorial Day, Independence Day, Labor Day, Veterans Day,  
Thanksgiving Day, Christmas Eve, Christmas Day, and New Year’s Eve. Election Day,  
the day after Thanksgiving, and any day that meets the criteria of catastrophic conditions  
as defined in R 460.702(f) may also be excluded.  
(k) “Certified” means an inverter-based system has met acceptable safety and reliability  
standards by a nationally recognized testing laboratory in conformance with IEEE  
1547.1-2020 and the UL 1741 2020 edition except that prior to January 1, 2022, inverter-  
based systems which conform to the UL 1741 January 28, 2010 edition are acceptable.  
(l) “Commission” means the Michigan public service commission.  
Commented [DTEE1]: This list does not include some  
utility holidays where planned work is not conducted. These  
rules should include such days in “business days” and the  
utility should clearly define the list of business day  
exclusions in procedures.  
Commented [DTEE2]: These rules should make clear that  
the utility’s highest priority should always be providing  
ordinary electric service to its customers.  
(m) “Commissioning test” means the test and verification procedure that is performed  
on a device or combination of devices forming a system to confirm that the device or  
system, as designed, delivered, and installed, meets the interconnection and  
interoperability requirements of IEEE 1547-2018. A commissioning test must include  
visual inspections and may include, as applicable, an operability and functional  
performance test and functional tests to verify interoperability of a combination of  
devices forming a system.  
(n) “Conforming” means the information in an interconnection application is consistent  
with the general principles of distribution system operation and DER characteristics.  
(o) “Construction agreement” means an agreement, pursuant to the interconnection  
standards superseded by R 460.901a to R 460.992, between an interconnection customer  
and an electric utility that contains timelines and cost estimates for construction of  
facilities and distribution upgrades to interconnect a DER into the distribution system,  
and identifies design, procurement, installation, and construction requirements associated  
with installation of the DER.  
(p) “Customer” means a person or entity who receives electric service from an electric  
utility’s distribution system or a person who participates in a legacy net metering or  
distributed generation program through an alternative electric supplier or electric utility.  
(q) “DC” means “direct current.”  
(r) “Distributed energy resource” or “DER” means a source of electric power and its  
associated facilities that is connected to a distribution system. DER includes both  
generators and energy storage devices capable of exporting active power to a distribution  
system.  
3
(s) “Distributed generation program” means the distributed generation program  
approved by the commission and included in an electric utility’s tariff pursuant to section  
6a(14) of 1939 PA 3, MCL 460.6a, or established in an alternative electric supplier  
distributed generation program plan.  
(t) “Distribution system” means the structures, equipment, and facilities owned and  
operated by an electric utility to deliver electricity to end users, not including  
transmission and generation facilities that are subject to the jurisdiction of the federal  
energy regulatory commission.  
(u) “Distribution system study” means a study, conducted under the interconnection  
standards superseded by R 460.901a to R 460.992, that determined whether a distribution  
system upgrade was needed to accommodate the proposed project and the cost of a  
distribution upgrade if required.  
(v) “Distribution upgrades” mean the additions, modifications, or improvements to the  
distribution system necessary to accommodate a DER’s connection to the distribution  
system.  
(w) “Electric utility” means any person or entity whose rates are regulated by the  
commission for selling electricity to retail customers in this state. For purposes of R  
460.901a through R 460.992 only, “electric utility” includes cooperative electric utilities  
that are member regulated as provided in section 4 of the electric cooperative member-  
regulation act, 2008 PA 167, MCL 460.34.  
(x) “Electrically coincident” means that 2 or more proposed DERs associated with  
pending interconnection applications have operating characteristics and nameplate  
capacities which require that distribution upgrades will be necessary if the DERs are  
installed in electrical proximity with each other on a distribution system.  
(y) “Electrically remote” means a proposed DER is not electrically coincident with a  
DER that is associated with a pending interconnection application.  
Commented [DTEE3]: There could be both distribution or  
DER site upgrades that may be required.  
(z) “Eligible electric generator” means a methane digester or renewable energy system  
with a generation capacity limited to a customer’s electric need and that does not exceed  
either of the following:  
(i) 150 kWac of aggregate generation at a single site for a renewable energy system.  
(ii) 550 kWac of aggregate generation at a single site for a methane digester.  
(aa) “Energy storage device” means a device that captures energy produced at one time,  
stores that energy for a period of time, and delivers that energy as electricity for use at a  
future time. For purposes of these rules, an energy storage device may be considered a  
DER.  
(bb) “Engineering review” means a study, conducted under the interconnection  
standards superseded by R 460.901a to R 460.992, that determined the suitability of the  
interconnection equipment including any safety and reliability complications arising from  
equipment saturation, multiple technologies, and proximity to synchronous motor loads.  
(cc) “Facilities study” means a study to specify and estimate the cost of the equipment,  
engineering, procurement, and construction work if distribution upgrades or  
interconnection facilities are required.  
(dd) “Fast track” means the procedure used for evaluating a proposed interconnection  
that makes use of screening processes, as described in R 460.944 to R 460.950.  
(ee) “Force majeure event” means an act of God; labor disturbance; act of the public  
enemy; war; insurrection; riot; fire, storm, or flood; explosion, breakage, or accident to  
4
machinery or equipment; an emergency order, regulation or restriction imposed by  
governmental, military, or lawfully established civilian authorities; or another cause  
beyond a party’s control. A force majeure event does not include an act of negligence or  
intentional wrongdoing.  
(ff) “Full retail rate” means the power supply and distribution components of the cost of  
electric service. Full retail rate does not include a system access charge, service charge,  
or other charge that is assessed on a per meter, premise, or customer basis.  
(gg) “Good standing” means an applicant has paid in full all undisputed bills rendered  
by the interconnecting electric utility and any alternative electric supplier in a timely  
manner and none of these bills are in arrears.  
Commented [DTEE4]: Customers should be required to  
pay all bills in a timely fashion, subject to refund.  
(hh) “Governmental authority” means any federal, state, local, or other governmental  
regulatory or administrative agency, court, commission, department, board, or other  
governmental subdivision, legislature, rulemaking board, tribunal, or other governmental  
authority having jurisdiction over the parties, their respective facilities, or the respective  
services they provide, and exercising or entitled to exercise any administrative, executive,  
police, or taxing authority or power; provided, however, that this term does not include  
the applicant, interconnection customer, electric utility, or any affiliate thereof.  
(ii) “GPS” means global positioning system.  
(jj) “Grid network” means a configuration of a distribution system or an area of a  
distribution system in which each customer is supplied electric energy at the secondary  
voltage by more than 1 transformer.  
(kk) “High voltage distribution” means those parts of a distribution system that operate  
within a voltage range specified in the electric utility’s interconnection procedures. For  
purposes of these rules, the term “subtransmission” means the same as high voltage  
distribution.  
(ll) “IEEE” means institute of electrical and electronics engineers.  
(mm) “IEEE 1547-2018” means “IEEE Standard for Interconnection and  
Interoperability of Distributed Energy Resources with Associated Electric Power Systems  
Interfaces,” as adopted by reference in R 460.902.  
(nn) “IEEE 1547.1-2020” means IEEE “Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces,” as adopted by reference in R 460.902.  
(oo) “Independent system operator” means an independent, federally-regulated entity  
established to coordinate regional transmission in a non-discriminatory manner and to  
ensure the safety and reliability of the transmission and distribution systems.  
(pp) “Initial review” means the fast track initial review screens described in R 460.946.  
(qq) “Interconnection” means the process undertaken by an electric utility to construct  
the electrical facilities necessary to connect a DER with a distribution system so that  
parallel operation can occur.  
(rr) “Interconnection agreement” means an agreement containing the terms and  
conditions governing the electrical interconnection between the electric utility and the  
applicant or interconnection customer. Where construction of interconnection facilities or  
distribution upgrades are necessary, the agreement shall specify timelines, cost estimates,  
and payment milestones for construction of facilities and distribution upgrades to  
interconnect a DER into the distribution system, and shall identify design, procurement,  
installation, and construction requirements associated with installation of the DER.  
5
Standard level 1, 2, and 3 interconnection agreements and level 4 and 5 interconnection  
agreements are types of interconnection agreements.  
(ss) “Interconnection coordinator” means a person or persons designated by the electric  
utility who shall serve as the point of contact from which general information on the  
application process and on the affected system or systems can be obtained through  
informal request by the applicant or interconnection customer.  
(tt) “Interconnection customer” means the person or entity, which may include the  
electric utility, responsible for ensuring a DER is operated and maintained in compliance  
with all local, state, and federal laws, as well as with all rules, standards, and  
interconnection procedures.  
(uu) “Interconnection facilities” mean any equipment required for the sole purpose of  
connecting a DER with a distribution system.  
(vv) “Interconnection procedures” mean the requirements that govern project  
interconnection adopted by each electric utility and approved by the commission.  
R 460.901b Definitions; J-Z.  
Rule 1b. As used in these rules:  
(a) “kW” means kilowatt.  
(b) “kWac” means the electric power, in kilowatts, associated with the alternating  
current output of a DER at unity power factor.  
(c) “kWh” means kilowatt-hours.  
(d) “Legacy net metering program” means the true net metering or modified net  
metering programs in place prior to commission approval of a distributed generation  
program tariff pursuant to section 6a(14) of 1939 PA 3, MCL 460.6a, and prior to the  
establishment of an alternative electric supplier distributed generation plan.  
(e) “Level 1” means a certified project of 20 kWac or less.  
(f) “Level 2” means a certified project of greater than 20 kWac and not more than 150  
kWac.  
(g) “Level 3” means a project of 150 kWac or less that is not certified, or a project  
greater than 150 kWac and not more than 550 kWac.  
(h) “Level 4” means a project of greater than 550 kWac and not more than 1 MWac.  
(i) “Level 5” means a project of greater than 1 MWac.  
(j) “Level 4 and 5 interconnection agreement” means an interconnection agreement  
applicable to level 4 and 5 interconnection applications.  
(k) “Low voltage distribution” means those parts of a distribution system that operate  
with a voltage range specified in the electric utility’s interconnection procedures.  
(l) “Mainline” means a conductor that serves as the three-phase backbone of a low  
voltage distribution circuit.  
(m) “Material modification” means a modification to the DER nameplate rating,  
electrical size of components, bill of materials, machine data, equipment configuration, or  
the interconnection site of the DER at any time after receiving notification by the electric  
utility of a complete interconnection application. For the proposed modification to be  
considered material, it shall have been reviewed and been determined to have or  
anticipated to have a material impact on 1 or more of the following:  
6
(i) The cost, timing, or design of any equipment located between the point of common  
coupling and the DER.  
(ii) The cost, timing, or design of any other application.  
(iii) The electric utility’s distribution system or an affected system.  
(iv) The safety or reliability of the distribution system.  
(n) “Methane digester” means a renewable energy system that uses animal or  
agricultural waste for the production of fuel gas that can be burned for the generation of  
electricity or steam.  
(o) “Modified net metering” means an electric utility billing method that applies the  
power supply component of the full retail rate to the net of the bidirectional flow of kWh  
across the customer interconnection with the electric utility’s distribution system during a  
billing period or time-of-use pricing period.  
(p) “MW” means megawatt.  
(q) “MWac” means the electric power, in megawatts, associated with the alternating  
current output of a DER at unity power factor.  
(r) “Nameplate capacity” means the maximum active power, in kWac or MWac, at  
which a DER is capable of sustained operation.  
(s) “Nameplate rating” means all of the following at which a DER is capable of  
sustained operation:  
(i) Nominal voltage (V).  
(ii) Current (A).  
(iii) Maximum active power (kWac).  
(iv) Apparent power (kVA).  
(v) Reactive power (kvar).  
(t) “Nationally recognized testing laboratory” means any testing laboratory recognized  
by the accreditation program of the United States Department of Labor Occupational  
Safety and Health Administration.  
(u) “Network protector” means those devices associated with a secondary network used  
to automatically disconnect a transformer when reverse power flow occurs.  
(v) “Non-export track” means the procedure for evaluating a proposed interconnection  
that will not inject electric energy into an electric utility’s distribution system, as  
described in R 460.942.  
(w) “Parallel operation” means the operation, for longer than 100 milliseconds, of a  
DER while connected to the energized distribution system.  
(x) “Party” or “parties” means an electric utility, applicant, or interconnection customer.  
(y) “Point of common coupling” means the point where the DER connects with the  
electric utility’s distribution system.  
(z) “Radial supply” means a configuration of a distribution system or an area of a  
distribution system in which each customer can only be supplied electric energy by 1  
substation transformer and distribution line at a time.  
(aa) “Readily available” means no creation of data is required, and little or no  
computation or analysis of data is required.  
(bb) “Reasonable efforts” mean, with respect to an action required to be attempted or  
taken by a party under these interconnection rules, efforts that are as timely as possible  
and consistent with those a party would take to protect its own interests.  
7
(cc) “Regional transmission operator” means a voluntary organization of electric  
transmission owners, transmission users, and other entities approved by the federal  
energy regulatory commission to efficiently coordinate electric transmission planning,  
expansion, operation, and use on a regional and interregional basis.  
(dd) “Renewable energy credit” means a credit granted pursuant to the commission's  
renewable energy credit certification and tracking program in section 41 of the clean and  
renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1041.  
(ee) “Renewable energy resource” means that term as defined in section 11(i) of the  
clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL  
460.1011.  
(ff) “Renewable energy system” means that term as defined in section 11(k) of the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1011.  
(gg) “Secondary network” means those areas of a distribution system that operate at a  
secondary voltage level and are networked.  
(hh) “Simplified track” means the procedure for evaluating a level 1 or level 2 proposed  
interconnection, as described in R 460.940.  
(ii) “Site” means a contiguous site, regardless of the number of meters at that site. A  
site that would be contiguous but for the presence of a street, road, or highway is  
considered to be contiguous for the purposes of these rules.  
(jj) “Spot network” means a location on the distribution system that uses 2 or more  
inter-tied transformers to supply an electrical network circuit, such as a network circuit in  
a large building.  
(kk) “Standard level 1, 2, and 3 interconnection agreement” means the statewide  
interconnection agreement approved by the commission and applicable to levels 1, 2 and  
3 interconnection applications.  
(ll) “Study track” means the procedure used for evaluating a proposed interconnection  
as described in R 460.952 to R 460.962.  
(mm) “Supplemental review” means the fast track supplemental review screens  
described in R 460.950.  
(nn) “System impact study” means a study to identify and describe the impacts to the  
electric utility’s distribution system that would occur if the proposed DER were  
interconnected exactly as proposed and without any modifications to the electric utility’s  
distribution system. A system impact study also identifies affected systems.  
(oo) “Temporary DER” means a DER that is installed on the distribution system by the  
electric utility with the intention of not operating at the site permanently.  
(pp) “Transition batch” means the group of interconnection applications processed  
pursuant to R 460.918.  
(qq) “True net metering” means an electric utility billing method that applies the full  
retail rate to the net of the bidirectional flow of kWh across the customer interconnection  
with the electric utility’s distribution system, during a billing period or time-of-use  
pricing period.  
(rr) “UL” means underwriters laboratory.  
(ss) “UL 1741” means the August 3, 2020 revision of “Standard for Inverters,  
Converters, Controllers and Interconnection System Equipment for Use With Distributed  
Energy Resources,” as adopted by reference in R 460.902.  
Commented [DTEE5]: Revision has been superseded to  
align with 1547.1-2020 and CA rule 21 requirements.  
8
R 460.902 Adoption of standards by reference.  
Rule 2. (1) The standards specified in these rules are adopted by reference as follows:  
(a) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, August 3, 2020 revision,  
is available from Underwriters Laboratories at the internet website:  
https://standardscatalog.ul.com/Catalog.aspx at a cost of $395.00 at the time of  
adoption of these rules.  
Commented [DTEE6]: Revision has been superseded to  
align with 1547.1-2020 and CA rule 21 requirements.  
(b) ANSI C84.1 – 2016 Electric Power Systems and Equipment – Voltage Ratings (60  
Hz), June 9, 2016, is available from the American National Standards Institute, Inc. at the  
internet website https://webstore.ansi.org/ at a cost of $111.24 at the time of adoption of  
these rules.  
(c) The following standards adopted by reference are available from IEEE at the  
internet website https://standards.ieee.org at the time of adoption of these rules.  
(i) The IEEE 1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating  
Installations on Power Systems, October 30, 2015, is available at a cost of $99.00 -  
$147.00 at the time of adoption of these rules.  
(ii) The IEEE 1547 - 2018, IEEE Standard for Interconnection and Interoperability of  
Distributed Energy Resources with Associated Electric Power System Interfaces, April 6,  
2018, is available at a cost of $149.00 - $224.00 at the time of adoption of these rules.  
(iii) The IEEE 1547.1-2020 IEEE Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces, May 21, 2020, is available at a cost of $197.00 - $296.00 at the  
time of adoption of these rules.  
(iv) The IEEE 519-2014 IEEE Recommended Practice and Requirements for  
Harmonic Control in Electric Power Systems, June 11, 2014, is available at a cost of  
$52.00 - $66.00 at the time of adoption of these rules.  
(2) The commission has copies of the standards specified in subrule (1) of this rule  
available for review at its offices located at 7109 W. Saginaw Hwy., Lansing, Michigan  
48917-1120. The mailing address is Michigan Public Service Commission, P.O. Box  
30221, Lansing, Michigan 48909-0221.  
R 460.904 Informal mediation.  
Rule 4. (1) The parties shall attempt to resolve all disputes arising out of the  
interconnection process, as defined by R 460.901a through R 460.992, according to the  
provisions of this rule.  
(2) Prior to formal mediation under R 460.906, the parties shall attempt to resolve any  
conflict without commission intervention through direct discussion and informal  
negotiation.  
(3) In the event that parties are unable to resolve the dispute privately, the parties may,  
by mutual agreement, make a written request for informal mediation to the commission  
staff. The informal mediation shall be conducted by an interconnection ombudsperson  
who shall be a member of the commission staff and designated by the commission. Both  
parties may choose to have attorneys or appropriate representation present.  
9
(4) During informal mediation, the parties shall discuss relevant facts pertaining to the  
dispute and the relief being sought. The interconnection ombudsperson and relevant  
commission staff shall be present to facilitate the discussion and provide guidance among  
the parties. Parties shall operate in good faith and use best efforts to resolve the dispute.  
(5) If a resolution is reached by the end of the meeting or meetings, the parties may draft  
a resolution of the dispute.  
(6) If the parties reach impasse and are unable to resolve the dispute, the parties shall  
proceed to the formal mediation process described in R 460.906.  
R 460.906 Formal mediation.  
Rule 6. (1) If the parties have been unable to resolve a dispute through the informal  
mediation process under R 460.904, the parties shall then attempt to resolve the dispute in  
the following manner:  
(a) The complaining party shall file a written notice of dispute with the commission.  
The notice of dispute must state the specific grounds for the dispute, sufficient facts to  
support the allegations, the relief requested, and must contain all information, testimony,  
exhibits, or other documents and information within the party’s possession on which the  
party intends to rely to support the party’s position.  
(b) The complaining party shall give notice that it is invoking the procedures in this  
rule. The complaining party shall send the notice to the non-complaining party’s email  
address and file the notice with the commission.  
(c) The non-complaining party shall acknowledge the notice of dispute within 10  
business days of its receipt and identify a representative with the authority to make  
decisions on its behalf with respect to the dispute.  
(d) An administrative law judge shall serve as the mediator in these proceedings. The  
administrative law judge may request and receive assistance from commission staff.  
(e) Within 60 business days from the date the non-complaining party acknowledges the  
dispute, the mediator shall issue a recommended settlement.  
(f) Within 5 business days after the date the recommended settlement is issued, each  
party shall file with the commission a written acceptance or rejection of the  
recommended settlement. If the parties accept the recommendation, then the  
recommendation shall become an order. If a party rejects or fails to respond within 5  
business days to the recommended settlement, then the dispute may proceed to a  
contested case hearing before the commission as provided in R 792.10415.  
(2) Nothing in these rules precludes a disputing party from filing a formal complaint  
with the commission, either instead of or after pursuing informal mediation or formal  
mediation pursuant to these rules.  
(3) The initiation of any form of dispute resolution by a party tolls any applicable  
deadlines under these rules until the dispute is resolved.  
R 460.908 Appointment of experts.  
Rule 8. (1) If a complaint is filed against an electric utility regarding a technical issue,  
the commission may, at its discretion, appoint 1 to 3 independent experts to investigate  
the complaint and report findings to the commission.  
10  
(2) The experts shall submit a report to the commission with the results and conclusions  
of their inquiry and may suggest corrective measures for resolving the complaint. The  
reports of the experts must be received in evidence and the experts made available for  
cross examination by the parties at any hearing.  
(3) The reasonable expenses of experts appointed pursuant to subrule (1) of this rule,  
including a reasonable hourly fee or fee determined by the commission, must be  
submitted by these experts to the commission for approval and, if approved, must be  
funded under subrule (4) of this rule.  
(4) An electric utility or alternative electric supplier shall reimburse the experts  
appointed by the commission for the reasonable expenses incurred in the course of  
investigating the complaint.  
R 460.910 Waivers.  
Rule 10. An electric utility, customer, alternative electric supplier, applicant, or  
interconnection customer may apply to the commission for a waiver from 1 or more  
provisions of these rules and may request expeditious processing. The commission may  
grant a waiver upon a showing of good cause and a finding that the waiver is in the public  
interest.  
PART 2. INTERCONNECTION STANDARDS  
R 460.911 Applicability.  
Rule 11. These rules apply to all interconnection applications filed on or after the  
effective date of these rules and interconnection applications filed prior to the effective  
date of these rules that do not have an executed construction or interconnection  
agreement. Interconnection applications with a construction agreement or  
interconnection agreement executed prior to the effective date of these rules are governed  
by their construction or interconnection agreement.  
R 460.914 Transition non-study group.  
Rule 14. (1) Interconnection applications that were filed before the effective date of  
these rules and that do not meet the eligibility criteria for transition batch study must be  
placed into the transition non-study group.  
(2) An electric utility shall determine whether an interconnection application in the  
transition non-study group is eligible to go through the simplified track, non-export track,  
or fast track within 30 business days of the effective date of these rules. Within 30  
business days of making the eligibility determination, an electric utility shall commence  
processing the interconnection application according to the applicable timelines in these  
rules.  
(3) An electric utility shall process incomplete or non-conforming interconnection  
applications according to R 460.936(7)(a) and (b).  
R 460.916 Legacy applications.  
11  
Rule 16. (1) For applicants with interconnection applications that have complete  
distribution system studies and that have entered into a construction or interconnection  
agreement with an electric utility as of the effective date of these rules, the  
interconnection must be completed according to existing contractual arrangements.  
(2) For applicants that have distribution system studies which were completed by an  
electric utility within the 6 months prior to the effective date of these rules, but have not  
entered into a construction or interconnection agreement with an electric utility as of the  
effective date of these rules, the interconnection application must proceed to an  
interconnection agreement under R 460.964.  
(3) For applicants that have distribution system studies that were conducted and  
completed more than 6 months before the effective date of these rules, the electric utility  
may require a facilities study within the transition batch upon a showing that a new study  
is necessary based on changed circumstances affecting the location of interconnection.  
R 460.918 Transition batch study process.  
Rule 18. (1) An electric utility shall begin its transition batch 80 business days after the  
effective date of these rules.  
(2) Interconnection applications are eligible to join the transition batch if all of the  
following requirements are met:  
(a) The application does not qualify for simplified track, non-export track, or fast track.  
(b) The application was accepted at any time prior to the start of the transition batch,  
including prior to the effective date of these rules.  
(c) A distribution study on the interconnection application was not completed at any  
time prior to the effective date of these rules, or a distribution study was completed more  
than 6 months before the effective date of these rules and an electric utility decided a  
facilities study was necessary pursuant to R 460.916(3).  
(3) An applicant with an eligible interconnection application pursuant to subrule (2) of  
this rule may join the transition batch by signing a transition batch agreement and paying  
any required fees before the start of the transition batch.  
(4) Pre-application reports may not be required for interconnection applications  
accepted before the effective date of these rules.  
(5) If an applicant with an interconnection application that is pending as of the effective  
date of these rules and that is otherwise eligible to join the transition batch has not  
submitted a complete and conforming application, an electric utility shall process the  
incomplete or non-conforming interconnection application according to R 460.936(7)(a)  
and (b). If the interconnection application is not deemed complete and conforming prior  
to an electric utility beginning its interconnection studies, the electric utility shall  
determine whether the interconnection application may be included in the transition batch  
study.  
(6) The interconnection applications in the transition batch must be studied as a group  
by an electric utility. DERs in the transition batch that are electrically remote may be  
studied on an expedited schedule, generally in the order the interconnection applications  
were deemed complete, but this expedited scheduling may not cause unreasonable delays  
in the evaluation of the other DERs in the transition batch.  
12  
(7) An electric utility shall process the transition batch and provide facilities study  
results to interconnection applicants within 1 year of the start date. The start date for the  
transition batch must be specified in an electric utility’s draft interconnection procedures  
and published on an electric utility’s public website.  
(8) An electric utility shall offer to hold a scoping meeting, either in-person or via  
telecommunications, with every applicant in the transition batch. The scoping meetings  
must meet the following requirements:  
(a) All meetings must, to the extent feasible, take place within the first 30 days of the  
transition batch.  
(b) An electric utility shall not begin studies within the transition batch until it has held  
a scoping meeting with every applicant that had agreed to participate in a meeting. An  
electric utility may begin the batch study if 1 or more applicants is unreasonably delaying  
a meeting.  
(c) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting. An electric utility may meet with  
multiple applicants in the same meeting if agreed to by the electric utility and all the  
applicants that will attend the meeting.  
(d) During the scoping meeting, an electric utility shall identify and communicate to  
each applicant the studies it plans to perform and provide the cost of the transition batch  
study using either fees that comply with R 460.926, or, if interconnection procedures  
have been approved by the commission, fees that comply with the interconnection  
procedures. The cost estimate must assume that all applicants will stay in the transition  
batch throughout the batch study.  
(9) The transition batch process must include a system impact study and a facilities  
study. An electric utility may specify additional studies it may perform on the transition  
batch in its interconnection procedures.  
(10) Electrically coincident DERs within the transition batch are considered to have  
equal priority with each other.  
(11) An electric utility shall comply with R 460.960(1) and (2) when conducting a  
system impact study. However, applicants with interconnection applications that have  
had an engineering review completed within the 6 months prior to the effective date of  
these rules may not be required to pay for a new system impact study.  
(12) An electric utility shall comply with R 460.962(1) when conducting a facilities  
study.  
(13) An electric utility shall provide written study results to each applicant at the  
completion of each study during the transition batch. An electric utility shall offer to  
hold at least 1 conference call with each transition batch applicant at the completion of  
each study. An electric utility may choose to group the consultation regarding multiple  
projects by 1 applicant and its affiliates into the same conference call. This conference  
call must provide a summary of outcomes and respond to questions from applicants.  
Where possible, conferences regarding the study results should be held within 30  
business days following completion of the study.  
(14) Within 40 business days following completion of the study, an applicant shall  
choose either to continue in the transition batch or withdraw. The fee for the next study  
in the transition batch is due by the end of the 40 business day period, unless extended by  
13  
the electric utility. Applicants that withdraw from the transition batch may reapply with a  
new interconnection application.  
(15) Applicants may reduce the capacity of the DER by up to 20% during the decision  
period between studies, including up to and through the conclusion of the system impact  
study. If an applicant wants to increase the capacity of the DER by any amount or  
decrease the capacity of the DER by more than 20%, an electric utility may require the  
applicant to submit a new interconnection application and pay the appropriate fees.  
(16) Within 45 days of receiving the final transition batch study report, an applicant  
shall notify the electric utility whether it intends to proceed to an interconnection  
agreement pursuant to R 460.964 or withdraw. Failure to notify an electric utility within  
the required time period shall result in the interconnection application being withdrawn.  
(17) Under circumstances where an interconnection application is delayed due to an  
affected system issue, informal mediation pursuant to R 460.904, formal mediation  
pursuant to R 460.906, or a complaint, other interconnection applications in the transition  
batch must continue to progress. If feasible, due to the status of the transition batch  
study, the delayed interconnection application may rejoin the transition batch study after  
the affected system issue is resolved. An interconnection application that is the subject of  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint, may also rejoin the batch study at a later date, if feasible, due to the status of  
the batch study.  
(18) A transition batch study is considered complete 45 business days after all transition  
batch applicants, except those applicants whose DERs are still causing unresolved  
affected system issues, pursuing informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or a complaint, have withdrawn, or have received a  
final transition batch study report.  
R 460.920 Electric utility interconnection procedures.  
Rule 20. (1) An electric utility shall file applications for approval of interconnection  
procedures and forms within 30 business days of the effective date of these rules.  
(2) The commission shall issue its order approving, rejecting, or modifying the proposed  
interconnection procedures and forms within 360 days of the effective date of these rules.  
If the commission finds the procedures and forms proposed by the electric utility to be  
inadequate or unacceptable, the commission may either adopt procedures and forms  
proposed by another party in the proceeding or modify and accept the procedures and  
forms proposed by the electric utility.  
(3) Until the commission accepts, rejects, or modifies an electric utility’s  
interconnection procedures and forms, the electric utility may use the proposed  
interconnection procedures and forms when processing interconnection applications with  
the exception of fixed fees and fee caps. An electric utility shall only charge fees that  
comply with the requirements of R 460.926 until the commission accepts, rejects, or  
modifies the proposed interconnection procedures and forms.  
(4) Two or more electric utilities may file a joint application proposing interconnection  
procedures for use by the joint applicants. The proposed interconnection procedures must  
ensure compliance with these rules.  
14  
(5) The proposed interconnection procedures must, at a minimum, include all of the  
following:  
(a) All necessary applications, forms, and relevant template agreements.  
(b) A schedule of all applicable fixed fees and fee caps.  
(c) Voltage ranges for high voltage distribution and low voltage distribution.  
(d) Required initial review screens.  
(e) Required supplemental review screens.  
(f) The process for conducting system impact studies and facilities studies on DERs  
when there is an affected system issue.  
(g) Testing and certification requirements of DER telecommunications, cybersecurity,  
data exchange, and remote control operation.  
(h) Parallel operation requirements.  
(i) A method to estimate the expected annual kWh output of the generator or  
generators.  
(j) Acceptable methods or standards for power-limited export DERs.  
(k) A cost allocation methodology for study track DERs.  
(l) An evaluation of an interconnection application for a project that includes single or  
multiple types of DERs at a site for which the applicant seeks a single point of common  
coupling.  
(m) Details describing how an energy storage device may be integrated into an existing  
legacy net metering program system without impacting the 10-year grandfathering  
period.  
(n) For electric utilities that are member-regulated electric cooperatives, a procedure for  
fairly processing applications in instances in which the number of applications exceed the  
capacity of the electric cooperative to timely meet the deadlines in these rules.  
(o) Examples of modifications that are not material modifications, acceptable material  
modifications, and unacceptable material modifications.  
(p) The procedure for performing a material modification review.  
(6) An electric utility shall obtain commission approval to revise its interconnection  
procedures.  
R 460.922 Online applications and electronic submission.  
Rule 22. (1) An electric utility shall allow pre-application report requests,  
interconnection applications, and interconnection agreements to be submitted  
electronically, such as, through the electric utility’s website or via email.  
(2) An electric utility shall dedicate a page on its website or direct customers to a linked  
website with information on these rules. The relevant information available to an  
applicant or interconnection customer via a website must include all of the following:  
(a) These rules and interconnection procedures in an electronically searchable format.  
(b) The electric utility’s applications and all associated forms in a format that allows for  
electronic entry of data.  
(c) Sample documents including, at a minimum, a 1-line diagram with required labels.  
(d) Contact information for the electric utility’s DER interconnection coordinator,  
including an email address and a phone number.  
(e) Directions for the submission of applications.  
15  
R 460.924 Communications.  
Rule 24. (1) An electric utility shall designate 1 or more interconnection coordinators.  
The telephone number and e-mail address of the interconnection coordinator or  
coordinators must be made available on the electric utility’s website. The interconnection  
coordinator or coordinators must be available to provide reasonable assistance to the  
applicant or interconnection customer but is not responsible to directly answer or resolve  
all of the issues that may arise in the interconnection process.  
(2) An applicant may designate an application agent. An application agent may serve as  
the single point of contact for the applicant and may coordinate with the electric utility on  
the applicant’s behalf. Designation of an application agent does not absolve the applicant  
from signing interconnection documents or from complying with the requirements in  
these rules and the interconnection agreement.  
(3) An electric utility must be indemnified by the applicant and its application agent  
with respect to assistance provided by an interconnection coordinator or coordinators.  
R 460.926 Initial fees.  
Rule 26. (1) After the effective date of these rules, fees for the pre-application report,  
the simplified track, the non-export track, the fast track, and the study track may not  
exceed the initial fee caps listed in subrule (2) of this rule, and the caps must remain in  
effect until interconnection procedures are approved by the commission under R 460.920.  
(2) The initial fee amounts for all levels of DERs are as follows:  
(a) The pre-application report fee may not exceed $300.  
(b) The simplified track fee and any applicable legacy net metering program application  
fee pursuant to R 460.1004(7) or distributed generation program application fee pursuant  
to R 460.1006(6), together, may not exceed a total of $50.  
(c) The non-export track fee may not exceed $100 + $1/kWac for certified DERs and  
$100 + $2/kWac for non-certified DERs.  
(d) The fast track initial review fee is $100 + $1/kWac for certified DERs and $100 +  
$2/kWac for non-certified DERs.  
(e) The transition batch fee for interconnection application review and the scoping  
meeting may not exceed $300.  
(f) The fee for a fast track supplemental review including all review screens may not  
exceed $5,000.  
(g) The study track fee for interconnection application review and the scoping meeting  
may not exceed $300.  
(h) The system impact study fee may not exceed $30,000.  
(i) The facilities study fee may not exceed $30,000.  
(3) The initial fees caps listed in subrule (2) of this rule, and any fixed fees subject to the  
initial fee caps charged by the electric utility, must be displayed prominently on the  
electric utility’s interconnection website.  
(4) An electric utility that expects to incur costs greater than the initial fee caps listed in  
subrule (2) of this rule in the evaluation of an interconnection application may file a  
request for a waiver pursuant to R 460.910.  
16  
R 460.928 Fee and fee cap modifications.  
Rule 28. (1) An electric utility shall include in its proposed interconnection procedures  
fixed fees to replace the initial fee caps specified in R 460.926(2)(a), (b), (c), (d), (e), and  
(g), and any other fixed fees the electric utility considers necessary.  
(2) An electric utility shall include in its proposed interconnection procedures adjusted  
fee caps to replace the initial fee caps specified in R 460.926(2)(f), (h), and (i), and any  
other fee caps the electric utility considers necessary. An electric utility may charge  
actual costs up to the fee caps.  
(3) The fixed fees must be specific to level size and be based on estimates of reasonable  
costs to perform the applicable service or study. The fee caps must be specific to level  
size and be based on a reasonable range of costs for performing the applicable study.  
(4) The most recently approved fixed fees and fee caps must be listed in the electric  
utility’s interconnection procedures and displayed prominently on the electric utility’s  
interconnection website.  
(5) The fixed fees and fee caps that are approved for inclusion in the electric utility’s  
interconnection procedures by the commission may be reviewed at any time by the  
electric utility and adjusted, if necessary, subject to commission review and approval.  
(6) Any modification of fees may not be applicable to fees already paid.  
(7) An electric utility that expects to incur costs greater than its prevailing fee caps in  
the evaluation of an interconnection application may file a request for a waiver pursuant  
to R 460.910.  
R 460.930 Pre-application report request form.  
Rule 30. (1) An applicant shall submit a completed pre-application report request form  
and the required fee for a pre-application report on a proposed level 4 or level 5 DER.  
(2) The pre-application report request form must include all of the following  
information:  
(a) Project contact information, including name, address, phone number, and email  
address.  
(b) Project location, as accurately as can be identified, which may be given by any of  
the following:  
(i) Street address with nearby cross streets and town.  
(ii) An aerial map with location clearly marked.  
(iii) GPS coordinates.  
(c) Account number, meter number, structure number, or other equivalent information  
identifying the proposed point of common coupling, if available.  
(d) Whether the DER is any of the following:  
(i) Solar.  
(ii) Wind.  
Commented [DTEE7]: Should specify if the proposed  
equipment will be certified or non-certified to help determine  
interconnection level.  
(iii) Cogeneration.  
(iv) Storage.  
(v) Solar with storage.  
(vi) Other type of DER.  
17  
(e) Nameplate capacity of the DER types in alternating current kW.  
(f) Whether the DER configuration is single or 3-phase.  
Commented [DTEE8]: KVA, DC KW and KWH of  
storage if applicable to the proposed project.  
(g) Whether the DER will be a stand-alone generator, meaning no onsite load other than  
station service.  
(h) Whether new service is requested. If there is existing service, the customer account  
number and site minimum and maximum current or proposed electric loads in kW, if  
available, must be included, and how the load is expected to change must be specified.  
(i) Whether the location is new construction.  
R 460.932 Pre-application report.  
Rule 32. (1) Using the information provided in the pre-application report request form  
described in R 460.930, an electric utility shall identify the substation bus, bank, or  
circuit most likely to serve the point of common coupling. This identification by the  
electric utility does not necessarily indicate that this would be the circuit to which the  
project ultimately connects.  
(2) An applicant may request additional pre-application reports if information about  
multiple points of common coupling is requested. No more than 10 pre-application  
report requests may be submitted by an applicant and its affiliates during a 1-week  
period. An electric utility may reject additional pre-application report requests.  
(3) The pre-application report must include all of the following information:  
(a) Total capacity, in MW, of substation bus, bank, or circuit based on normal or  
operating ratings likely to serve the proposed point of common coupling.  
(b) Existing aggregate generation capacity, in MW, interconnected to a substation bus,  
bank, or circuit likely to serve the proposed point of common coupling.  
(c) Aggregate capacity, in MW, of generation not yet built but found in previously  
accepted interconnection applications, for a substation bus, bank, or circuit likely to serve  
the proposed point of common coupling.  
(d) Available capacity, in MW, of substation bus, bank, or circuit likely to serve the  
proposed point of common coupling.  
(e) Substation nominal distribution voltage.  
(f) Nominal distribution circuit voltage at the proposed point of common coupling.  
(g) Label, name, or identifier of the distribution circuit on which the proposed point of  
common coupling is located.  
(h) Approximate circuit distance between the proposed point of common coupling and  
the substation.  
(i) The actual or estimated peak load and minimum load data at any relevant line  
section or sections, including daytime minimum load and absolute minimum load, when  
available. If not readily available, the report must indicate whether the generator is  
expected to exceed minimum load on the circuit.  
(j) Whether the point of common coupling is located behind a line voltage regulator and  
whether the substation has a load tap changer.  
(k) Limiting conductor ratings from the proposed point of common coupling to the  
distribution substation.  
(l) Number of phases available at the primary voltage level at the proposed point of  
common coupling, and, if a single phase, distance from the 3-phase circuit.  
18  
(m) Whether the point of common coupling is located on a spot network, area network,  
grid network, radial supply, or secondary network.  
(n) Based on the proposed point of common coupling, the report must indicate whether  
power quality issues may be present on the circuit.  
(o) Whether or not the area has been identified as having a prior affected system.  
(p) Whether or not the site will require a system impact study for high voltage  
distribution based on size, location, and existing system configuration.  
(4) The pre-application report may include only existing and readily available data. A  
request for a pre-application report does not obligate an electric utility to conduct a study  
or other analysis of the proposed DER if data is not readily available. The pre-  
application report must also indicate any information listed in subrule (3) of this rule that  
is not readily available. An electric utility may, at its discretion, return any portion of the  
pre-application report fee because some or all information does not exist.  
(5) Pre-application report requests must be processed in the order in which an electric  
utility received the requests.  
(6) An electric utility shall provide the data required in the pre-application report to the  
applicant within 25 business days of receipt of the completed request form and payment  
of the fee. The pre-application report produced by the electric utility is non-binding and  
does not confer any rights on the applicant.  
R 460.934 Site control.  
Rule 34. (1) Documentation of site control must be submitted with the application by  
the applicant.  
(2) For level 3, 4, or 5 DERs, site control may be demonstrated by providing  
documentation that shows any of the following:  
(a) Ownership of, a leasehold interest in, or a right to develop a site for the purpose of  
constructing and operating the DER.  
(b) An enforceable option to purchase or acquire a leasehold site for this purpose.  
(c) A legally binding agreement transferring a present real property right to specified  
real property along with the right to construct and operate a DER on the specified real  
property for a period of time not less than 5 years.  
(3) For level 1 or 2 DERs, proof of site control may be demonstrated by the site owner’s  
signature on the application.  
(4) An applicant may redact commercially sensitive information from site control  
documents.  
Commented [DTEE9]: Most applications are filled by  
installer and not customer, so the documentation should  
include Site owner printed name, Phone number, and email  
address.  
R 460.936 Interconnection applications.  
Rule 36. (1) An electric utility shall provide an interconnection application for an  
applicant to complete, including for those applicants whose DERs will be configured to  
be non-exporting.  
(2) All documents required for a complete interconnection application must be listed on  
the interconnection application. For level 4 and 5 interconnection applications, the list of  
required documents must include a completed pre-application report.  
19  
(3) For interconnection applications with proposed DERs that fall into level 1, an  
applicant shall provide a 1-line diagram and a site diagram.  
(4) For interconnection applications with proposed DERs that fall into levels 2 and 3, an  
applicant shall provide a 1-line diagram that is either sealed by a professional engineer  
licensed in this state or signed by an electrical contractor who is licensed in this state with  
the electrical contractor’s license number noted on the diagram. An applicant shall also  
provide a site diagram.  
(5) For interconnection applications with proposed DERs that fall into levels 4 and  
above, an applicant shall provide a 1-line diagram that is sealed by a professional  
engineer who is licensed in this state. An applicant shall also provide a site diagram.  
(6) Applications shall be reviewed to assess whether they are complete and conforming  
in the order in which they were received. An application is considered received when an  
electric utility receives the application, the application’s attachments, and the application  
fee. The application must be date-stamped for the first business day when the electric  
utility has received the interconnection application, the application attachments, and  
payment of the application fee. An electric utility shall notify the applicant of receipt of  
the application by the end of the third business day following the date of the date stamp.  
(7) The electric utility shall notify the applicant that the interconnection application is  
either complete and conforming, or incomplete, or non-conforming, within 10 business  
days of the date stamp.  
(a) If an interconnection application is determined to be complete and conforming by the  
electric utility, the applicant must be notified that the interconnection application is  
accepted. The electric utility shall also indicate whether the interconnection application  
will be processed using the simplified track, non-export track, fast track, or study track.  
(b) If the application is incomplete or non-conforming, the electric utility shall provide  
to the applicant a written list of all deficiencies with the notification. The applicant shall  
have 60 business days from the date of electric utility notification to submit the necessary  
information and may provide up to 2 submissions during this time period. After each  
submission of information, the electric utility shall have 10 business days to notify the  
applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this rule,  
the utility may withdraw the application.  
(8) An electric utility shall comply with part 2 of these rules, R 460.911 to R 460.992,  
and its interconnection procedures when interconnecting DERs that it owns and operates  
onto its distribution system, with the exception of temporary DERs.  
(9) An electric utility shall use the same process when processing and studying  
interconnection applications from all applicants, whether the DER is owned or operated  
by the electric utility, its subsidiaries or affiliates, or others, with the exception of  
temporary DERs.  
(10) An electric utility shall review and update interconnection applications periodically  
to reflect new information required to properly review DERs, subject to commission  
review and approval.  
R 460.938 Public interconnection list.  
20  
Rule 38. (1) An electric utility shall maintain a public interconnection list, which is  
available in a sortable spreadsheet format, and provide it to the public upon request. An  
electric utility that has received not less than 100 complete interconnection applications  
in a year shall publish this list on the electric utility’s website. The public  
interconnection list must be updated monthly unless no changes to the spreadsheet have  
occurred in that month. The date of the most recent update must be clearly indicated.  
(2) The public interconnection list must include all of the following:  
(a) An application identifier.  
(b) The date that the electric utility received the application.  
(c) The date that the electric utility considered the application to be complete and  
conforming.  
(d) Whether the application is on the simplified track, non-export track, fast track, or  
study track.  
(e) The proposed DER nameplate capacity.  
(f) The proposed DER interconnection size level.  
(g) The DER technology type.  
(h) The county and township in which the proposed point of common coupling will be  
located.  
(i) The current status of the application’s progress in the interconnection process.  
(j) The labels, names, or identifiers of the distribution circuit and substation.  
R 460.940 Simplified track review.  
Rule 40. (1) Level 1 and 2 applications, including applications that include an energy  
storage device so the export of power meets the requirements of level 1 or level 2, must  
be processed using the simplified track.  
(2) Within 10 business days after notifying an applicant that the application had been  
accepted, an electric utility shall perform a review by using up to all of the initial review  
screens specified in the electric utility’s interconnection procedures and notify the  
applicant if any interconnection facilities, distribution upgrades, further study, or  
application modifications are required for safe and reliable interconnection to the electric  
utility’s distribution system or for tariff compliance. If an electric utility chooses to  
perform a review by using a subset of the initial review screens, the exclusion of 1 or  
more screens may not be the only basis for the electric utility to require application  
modification or further study.  
(3) If the utility review notification indicates that no further study or application  
modifications are required, the applicant shall proceed under R 460.964 to an  
interconnection agreement.  
(4) If application modification is offered by the electric utility, the applicant shall either  
withdraw the interconnection application or provide a modified application within 60  
business days from the date of electric utility notification, with up to 2 resubmissions  
during this time period to provide a modified application. After each submission of  
information, the electric utility shall notify the applicant within 10 business days that the  
interconnection application is either accepted or rejected due to continuing deficiencies.  
If the applicant does not meet the timelines required by this subrule, the electric utility  
21  
may withdraw the application. When the applicant provides a modified application, the  
electric utility shall follow the procedure specified in subrule (2) of this rule.  
(5) If further study is required, the electric utility and the applicant shall decide whether  
to proceed to a supplemental review under R 460.950 or the study track under R 460.952,  
or to withdraw the application. The applicant shall have 20 business days to decide on a  
course of action and to notify the electric utility. In the absence of this notification, the  
electric utility may withdraw the application.  
R 460.942 Non-export track review.  
Rule 42. (1) Interconnection applications for DERs that will not inject electric energy  
into an electric utility’s distribution system are eligible for evaluation under the non-  
export track. Non-export eligibility requires an existing electrical service at the  
applicant’s premise.  
Commented [DTEE10]: Non-export track available based  
on agreement to install utility approved controls.  
(2) Subject to review and approval by the commission, an electric utility may limit the  
eligibility of the non-export track in its interconnection procedures based on the  
characteristics of its distribution system.  
(3) Before submitting an interconnection application, a non-export track applicant may  
contact the electric utility for assistance in determining whether a non-export track review  
will be sufficient or the study track is necessary. The electric utility shall provide the  
applicant assistance based on available information. If the applicant chooses to proceed,  
an interconnection application shall be submitted pursuant to R 460.936.  
(4) Within 20 business days after being notified that the application was accepted, the  
electric utility shall perform an initial review by using some or all of the initial review  
screens specified in the electric utility’s interconnection procedures and notify the  
applicant of the results. If an electric utility chooses to perform a review using a subset  
of the initial review screens, the exclusion of 1 or more screens may not be the only basis  
for the electric utility to require interconnection facilities, distribution upgrades, further  
study, or application modifications.  
(a) If the notification indicates that no interconnection facilities, distribution upgrades,  
further study, or application modifications are required, the electric utility shall provide  
specifications for any equipment the applicant will be required to install within 10  
business days of the applicant being notified. Within 10 business days of receiving the  
equipment specifications, the applicant shall notify the electric utility whether it will  
proceed under R 460.964 to an interconnection agreement or will withdraw the  
application. The applicant’s failure to notify the electric utility within the required time  
period shall result in the interconnection application being withdrawn by the electric  
utility.  
Commented [DTEE11]: This may require site walkdowns  
to identify appropriate locations for disconnects, metering  
and other equipment for tariff compliance in the customer  
facility. Should be an option for a mutually agreed schedule  
to determine the specifics of what is needed to proceed.  
(b) If application modification is offered by the electric utility, the applicant shall either  
withdraw the interconnection application or provide a modified application within 60  
business days from the date of electric utility notification, with up to 2 resubmissions  
during this time period to provide a modified application. After each submission of  
information, the electric utility shall notify the applicant within 10 business day that the  
interconnection application is either accepted or rejected due to continuing deficiencies.  
If the applicant does not meet the timelines required by this subrule, the electric utility  
22  
may withdraw the application. When the applicant provides a modified application, the  
electric utility shall follow the procedure specified in this subrule.  
(5) If further study is required, the electric utility shall present options and the applicant  
shall decide whether to proceed to a supplemental review under R 460.950, or to the  
study track under R 460.952, or to withdraw the application. The applicant shall have 20  
business days to decide on a course of action and notify the electric utility. In the  
absence of this notification, the electric utility may withdraw the application within the  
required time period.  
(6) When an applicant changes from a non-exporting system to an exporting system, the  
applicant shall submit a new interconnection application. ꢀ  
Commented [DTEE12]: Additionally, the customer desire  
to change rates may bring about tariff specific metering and  
monitoring requirements for their facility interconnection.  
R 460.944 Fast track applicability.  
Rule 44. (1) Level 3 and level 4 applications in which the DER is not proposing to  
interconnect with the electric utility’s high voltage distribution system are eligible for the  
fast track. These level 3 and level 4 applications may include applications that provide for  
the use of an energy storage device so the export of power meets the requirements of  
level 3 or level 4.  
(2) An applicant that is eligible for the fast track may forgo the fast track and proceed  
directly to the study track.  
(3) An applicant with an application that is outside the limitations specified in subrule  
(1) of this rule may petition the electric utility to have its application evaluated under fast  
track. The electric utility may approve or reject this request at its discretion.  
(4) In determining fast track eligibility, an electric utility may aggregate all proposed  
new generation on a site regardless of the existence of a shared point of common  
coupling or multiple points of common coupling.  
R 460.946 Fast track; initial review.  
Rule 46. (1) An electric utility shall list in its interconnection procedures the initial  
review screens specified in subrule (5) of this rule. An electric utility may add additional  
details to each of these screens in the interconnection procedures.  
(2) An electric utility may include additional initial review screens in its  
interconnection procedures. In its application requesting approval of interconnection  
procedures, an electric utility shall provide a detailed technical rationale for including  
each additional screen. If an additional screen conflicts with or undermines any of the  
initial review screens specified in subrule (5) of this rule, the rationale must include an  
explanation of how it does so.  
(3) The electric utility may waive application of 1, some, or all of the initial review  
screens.  
(4) Within 20 business days after an electric utility receives a complete and conforming  
application and associated payment, the electric utility shall perform an initial review and  
notify the applicant of the results. The initial review must consist of applying the initial  
review screens selected by the electric utility pursuant to subrule (3) of this rule to the  
proposed DER. The electric utility shall not require a supplemental review or a system  
impact study if the DER passes the applied initial review screens.  
23  
(5) The initial review screens are all of the following:  
(a) The entire proposed DER, including all aggregated site generation and point or  
points of interconnection, must be located within the electric utility’s service territory.  
(b) For interconnection of a proposed DER to a radial distribution circuit, the  
aggregated generation, including the proposed DER, on the circuit may not exceed 15%  
of the line section annual peak load as most recently measured or calculated if measured  
data is not available. A line section is that portion of an electric utility’s distribution  
system connected to a customer bounded by automatic sectionalizing devices or the end  
of the distribution line. The electric utility may consider 100% of applicable loading, if  
available, instead of 15% of line section peak load.  
(c) For interconnection of a proposed DER to the load side of network protectors, the  
proposed DER must utilize an inverter-based equipment package and, together with the  
aggregated other inverter-based DERs, may not exceed the smaller of 5% of a network’s  
maximum load or 50 kWac.  
(d) The proposed DER, in aggregation with other DERs on the distribution circuit, may  
not contribute more than 10% to the distribution circuit’s maximum fault current at the  
point on the primary voltage nearest the proposed point of common coupling.  
(e) The proposed DER, in aggregate with other DERs on the distribution circuit, may  
not cause any distribution protective devices and equipment or interconnection customer  
equipment on the system to exceed 87.5% of the short circuit interrupting capability. An  
interconnection may not be proposed for a circuit that already exceeds 87.5% of the short  
circuit interrupting capability. Distribution protective devices and equipment include, but  
are not limited to, substation breakers, fuse cutouts, and line reclosers.  
Commented [DTEE13]: Or implement a non-sell back  
protection scheme to not exceed the customer load.  
(f) The initial review screen determines the type of interconnection to a primary  
distribution line for the proposed DER, according to the requirements specified in the  
table in this subdivision. This screen includes a review of the type of electrical service  
provided to the applicant, including line configuration and the transformer connection to  
limit the potential for creating over-voltages on the electric utility’s distribution system  
due to a loss of ground during the operating time of any anti-islanding function.  
Primary Distribution Line  
Type  
Type of Interconnection to  
Primary Distribution Line  
3-phase or single phase,  
phase-to-phase  
Effectively-grounded 3- phase  
or single-phase, line-to-neutral  
Result  
3-phase, 3 wire  
Pass screen  
Pass screen  
3-phase, 4 wire  
(g) If the proposed DER is to be interconnected on single-phase shared secondary, the  
aggregate generation capacity on the shared secondary, including the proposed DER, may  
not exceed 20 kWac or 65% of the transformer nameplate rating.  
(h) If the proposed DER is single-phase and is to be interconnected on a center tap  
neutral of a 240 volt service, its addition may not create an imbalance between the 2 sides  
of the 240 volt service of more than 20% of the nameplate rating of the service  
transformer.  
(i) If the proposed DER is single-phase and is to be interconnected to a 3-phase service,  
its nameplate rating may not exceed 10% of the service transformer nameplate rating.  
24  
(j) If the proposed DER’s point of common coupling is behind a line voltage regulator,  
the DER’s nameplate rating must be less than 250 kWac. This screen does not include  
substation voltage regulators.  
(6) If the proposed interconnection passes the initial review screens, or if the proposed  
interconnection fails the screens but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant. If a facilities study is not required, the interconnection  
application must proceed under R 460.964 to an interconnection agreement. If a facilities  
study is required, the interconnection agreement must proceed under R 460.962.  
(7) If the proposed interconnection fails any of the initial review screens, and the electric  
utility does not or cannot determine that the DER may be interconnected consistent with  
safety, reliability, and power quality standards, the electric utility shall notify the  
applicant, provide the applicant with the results of the application of the initial review  
screens, and offer all of the following options:  
(a) Attend a customer options meeting, as described in R 460.948.  
(b) Proceed to supplemental review under R 460.950.  
(c) Submit within 60 business days from the date of the electric utility notification, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility. The application modifications must mitigate or eliminate the factors  
that caused the interconnection application to fail 1 or more of the initial review screens.  
After each submission of information, the electric utility has 10 business days to notify  
the applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this  
subrule, the electric utility may withdraw the application. After the electric utility  
determines the application is accepted, the revised interconnection application must  
proceed under subrule (4) of this rule.  
(d) Withdraw the interconnection application.  
(8) If the applicant does not select a course of action under subrule (7) of this rule within  
10 business days of notice from the electric utility, the electric utility shall withdraw the  
interconnection application.  
R 460.948 Fast track; customer options meeting.  
Rule 48. (1) Upon an applicant’s request, the electric utility and the applicant shall  
schedule a customer options meeting between the electric utility and the applicant to  
review possible facility modifications, screen analysis, and related results to determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The customer options meeting must take place within 30 business  
days of the date of notification pursuant to R 460.946(7).  
(2) At the customer options meeting, the electric utility shall offer all of the following  
options:  
(a) Proceed to a supplemental review pursuant to R 460.950.  
(b) Continue evaluating the interconnection application under the study track pursuant  
to R 460.952.  
25  
(c) Submit within 60 business days from the date of the customer options meeting, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility, which mitigates or eliminates the factors that caused the  
interconnection application to fail 1 or more of the initial review screens. After each  
submission of information, the electric utility has 10 business days to notify the applicant  
that the interconnection application is either accepted or rejected due to continuing  
deficiencies. If the applicant does not meet the timelines required by this subrule, the  
electric utility may withdraw the application. After the electric utility accepts the revised  
interconnection application, it must proceed under R 460.946(4).  
(d) Withdraw the interconnection application.  
(3) Following the customer options meeting, the applicant has up to 20 business days to  
decide on a course of action and notify the electric utility. In the absence of this  
notification within the required time, the electric utility shall withdraw the application.  
(4) The customer options meeting may take place in person or via telecommunications.  
R 460.950 Fast track; supplemental review.  
Rule 50. (1) An electric utility shall list in its interconnection procedures the  
supplemental review screens specified in subrule (6) of this rule. An electric utility may  
add additional details to each of these screens in the interconnection procedures.  
(2) An electric utility may include additional supplemental review screens in its  
interconnection procedures. In its application requesting approval of interconnection  
procedures, the electric utility shall provide a detailed technical rationale for the inclusion  
of each supplemental review screen. If an additional screen negates or undermines any of  
the supplemental review screens specified in subrule (6) of this rule, the rationale must  
include an explanation of the technical justification for the additional screen.  
(3) An electric utility may waive application of 1, some, or all of the supplemental  
review screens.  
(4) To receive a supplemental review, an applicant shall submit payment of the  
supplemental review fee within 20 business days of agreeing to a supplemental review. If  
payment of the fee has not been received by the electric utility within 25 business days,  
the electric utility shall withdraw the interconnection application.  
(5) Within 30 business days after the applicant pays the applicable supplemental review  
fee or fees, an electric utility shall perform a supplemental review and notify the applicant  
of the results. The supplemental review must consist of applying the initial review  
screens selected by the electric utility pursuant to subrule (2) of this rule to the proposed  
DER. The electric utility shall not require a system impact study if the DER passes the  
applied supplemental review screens.  
(6) The supplemental review screens must include all of the following:  
(a) Minimum load screen. Where 12 months of line section minimum load data,  
including onsite load but not station service load served by the proposed DER, are  
available, can be calculated, can be estimated from existing data, or can be determined  
from a power flow model, the aggregate DER capacity on the line section must be less  
than 100% of the minimum load for all line sections bounded by automatic sectionalizing  
devices upstream of the proposed DER. If minimum load data are not available, or cannot  
26  
be calculated, estimated, or determined, an electric utility shall include the reason or  
reasons that it is unable to calculate, estimate, or determine minimum load in its  
supplemental review results notification under subrules (7) and (8) of this rule. All of the  
following must be applied by the electric utility:  
(i) The type of generation used by the proposed DER will be considered when  
calculating, estimating, or determining circuit or line section minimum load relevant for  
the application of the minimum load screen specified in this subdivision. Solar  
photovoltaic generation systems with no battery storage must use daytime minimum load.  
All other generation must use absolute minimum load unless an operating schedule is  
provided.  
(ii) When this screen is being applied to a DER that serves some station service load,  
only the net injection of electric energy into the electric utility’s distribution system may  
be considered as part of the aggregate generation.  
(iii) The electric utility shall not consider as part of the aggregate generation, for  
purposes of this supplemental screen, DER capacity known to be already reflected in the  
minimum load data.  
(b) Voltage and power quality screen. In aggregate with existing generation on the line  
section, all of the following conditions must be met:  
(i) The voltage regulation on the line section can be maintained in compliance with  
relevant requirements under all system conditions.  
(ii) The voltage fluctuation is within acceptable limits as defined by the IEEE Standard  
1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating Installations on  
Power Systems.  
(c) Safety and reliability screen. The location of the proposed DER and the aggregate  
generation capacity on the line section may not create impacts to safety or reliability that  
require application of the study track to address. An electric utility shall consider all of  
the following when determining potential impacts to safety and reliability in applying this  
screen:  
(i) Whether the line section has significant minimum loading levels dominated by a  
small number of customers, such as several large commercial customers.  
(ii) Whether the loading along the line section is uniform.  
(iii) Whether the proposed DER is located less than 0.5 electrical circuit miles for less  
than 5 kV or less than 2.5 electrical circuit miles for greater than 5 kV from the  
substation. In addition, whether the line section from the substation to the point of  
common coupling is a mainline rated for normal and emergency ampacity.  
(iv) Whether the proposed DER incorporates a time delay function to prevent  
reconnection of the DER to the distribution system until distribution system voltage and  
frequency are within normal limits for a prescribed time.  
Commented [DTEE14]: Emergency ampacity is reserved  
for limited duration system security.  
(v) Whether operational flexibility is reduced by the proposed DER, such that transfer  
of the line section or sections of the DER to a neighboring distribution circuit or  
substation may trigger overloads, power quality issues, or voltage issues.  
(vi) Whether the proposed DER employs equipment or systems certified by a  
recognized standards organization to address technical issues including, but not limited  
to, islanding, reverse power flow, or voltage quality.  
(7) If the proposed interconnection passes the supplemental review, or if the proposed  
interconnection fails the review but the electric utility determines that the DER may be  
27  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant and the interconnection application must proceed  
pursuant to both of the following:  
(a) If the proposed interconnection requires a facilities study, the interconnection  
application must proceed under R 460.962.  
(b) If the proposed interconnection does not require further study, the interconnection  
application must proceed under R 460.964 to an interconnection agreement.  
(8) If the proposed interconnection fails any of the supplemental review screens or the  
electrical utility is unable to perform a supplemental review screen, and the electric utility  
does not or cannot determine that the DER may be interconnected consistent with safety,  
reliability, and power quality standards, the electric utility shall notify the applicant,  
provide the applicant with the results of the application of the supplemental review  
screens, and offer both of the following options:  
(a) Stop the supplemental review and continue evaluating the proposed interconnection  
under the study track under R 460.952.  
(b) Withdraw the interconnection application.  
(9) For subrules (7) and (8) of this rule, if an applicant does not select a course of action  
within 10 business days of notice from the electric utility, the electric utility shall  
withdraw the interconnection application.  
R 460.952 Study track.  
Rule 52. (1) An electric utility shall use the study track to evaluate an interconnection  
application that has been accepted under R 460.936 if 1 or more of the following  
conditions is met:  
(a) The DER is not eligible for the simplified track, the non-export track, or fast track.  
(b) The DER did not pass the initial review screens as part of the fast track and the  
applicant selected the study track option in the customer options meeting.  
(c) The DER did not pass 1 or more supplemental review screens.  
(d) The DER was evaluated under the simplified track or the non-export track and  
further study is required.  
(e) The DER is eligible for the fast track, but the applicant elected the study track.  
(2) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(a) of this rule, within 10 business days after the electric  
utility notifies the applicant that the interconnection application has been accepted  
pursuant to R 460.936, the electric utility shall provide an individual study agreement or a  
batch study agreement to the applicant, whichever is applicable under subrule (4) of this  
rule.  
(3) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(b), (c), (d), or (e) of this rule, within 10 business days  
after the applicant has notified the electric utility to proceed to the study track, the electric  
utility shall provide an individual study agreement or a batch study agreement to the  
applicant, whichever is applicable under subrule (4) of this rule.  
(4) An electric utility shall study all interconnection applications that qualify for study  
track either individually or in a batch study process. An electric utility shall not study 1 or  
28  
more applications individually and at the same time study 1 or more different applications  
as part of a batch.  
(5) An electric utility’s interconnection procedures may include a provision for  
determining appropriate milestone payments to include with the system impact study fee  
and facilities impact study fee.  
R 460.954 Individual study.  
Rule 54. (1) An electric utility that is evaluating DERs in the study track individually  
shall process the interconnection applications in the order in which the applications were  
placed into the study track, taking into account withdrawn interconnection applications  
and electrically remote DERs. An electrically remote DER in an individual study may be  
studied on an expedited schedule relative to electrically coincident DERs. Electrically  
remote DERs must be studied in the order the interconnection applications were  
considered complete.  
(2) When an interconnection application is delayed due to an affected system issue,  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint pursuant to R 792.10439 to R 792.10446, other interconnection applications  
that were placed into the study track on a later date may progress in the order in which  
the interconnection applications were placed into the study track.  
(3) An individual study process must consist of a system impact study pursuant to R  
460.960 and a facilities study pursuant to R 460.962. An electric utility may waive 1 or  
both studies for a particular interconnection application. An electric utility may specify  
additional studies it may perform on an interconnection application in its interconnection  
procedures, provided the electric utility is able to meet all applicable timelines associated  
with an individual study process.  
(4) Interconnection applications that meet all of the following requirements must be  
admitted into an individual study:  
(a) An electric utility has elected to study all interconnection applications that qualify  
for study track individually.  
(b) An electric utility determined the application to be complete and conforming.  
(c) An application qualifies for study track pursuant to R 460.952.  
(d) An interconnection application has a pre-application report, when required by R  
460.936(2).  
(e) An applicant has paid all required fees.  
(f) An applicant has signed and returned an individual study agreement.  
(5) If an electric utility anticipated that it would use a batch study process but received  
only 1 interconnection application that qualified for the study track, the electric utility  
shall consider the first day of what would have been the batch study process to be the day  
the application was determined to be complete and conforming and shall use the  
individual study process to evaluate the application with all applicable timelines.  
R 460.956 Batch study process.  
Rule 56. (1) This rule applies only to those electric utilities that have elected to study  
DERs that qualify for study track in a batch process.  
29  
(2) A batch consists of 2 or more interconnection applications that will be studied as a  
group by the electric utility. One or more DERs in the batch that are electrically remote  
may be studied on an expedited schedule, but expedited scheduling of 1 or more DERs  
may not cause unreasonable delays in the evaluation of the other DERs in the same batch.  
(3) An electric utility shall process at least 1 batch per year. The start and end dates for  
each batch study must be published on the electric utility’s public website not less than 60  
days prior to the start of the batch.  
(4) Interconnection applications that meet all of the following requirements must be  
admitted into a batch study:  
(a) The electric utility elected to study all interconnection applications that qualify for  
study track in a batch study process.  
(b) The electric utility considered the application complete and conforming within a 1-  
year period immediately before the batch study commences.  
(c) The accepted application qualifies for study track pursuant to R 460.952.  
(d) The interconnection application has a pre-application report when required by R  
460.930(2).  
(e) The applicant has paid all required fees including any milestone payments as  
described in the electric utility’s interconnection procedures.  
(f) The applicant has signed a batch study agreement.  
(5) An electric utility shall offer to hold a scoping meeting, either in-person or via  
telecommunications, with every applicant in a batch. The scoping meetings and the  
electric utility must meet all of the following requirements:  
(a) All meetings must, to the extent feasible, take place within 30 days of the batch start  
date.  
(b) An electric utility shall not begin studies within a batch until it has held a scoping  
meeting with every applicant who agreed to participate in a meeting. An electric utility  
may begin the batch study if an applicant is unreasonably delaying a meeting.  
(c) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting. An electric utility may meet with  
multiple applicants in the same meeting if agreed to by the electric utility and all the  
applicants that will attend the meeting.  
(d) During the scoping meeting, the electric utility shall identify and communicate to  
each applicant the studies it plans to perform and estimate the cost of the batch study,  
using either the fees that comply with R 460.926, or, if interconnection procedures have  
been approved by the commission, fees that comply with the interconnection procedures.  
The cost estimate must assume that all applicants will stay in the batch throughout the  
batch study.  
(6) The batch process must consist of a system impact study pursuant to R 460.960 and  
a facilities study pursuant to R 460.962. The electric utility may specify additional studies  
it may perform on a batch study in its interconnection procedures.  
(7) Interconnection applications within a batch must be considered to have equal priority  
with each other.  
(8) An electric utility shall follow R 460.960(1) and (2) when conducting a system  
impact study.  
(9) An electric utility shall follow R 460.962(1) when conducting a facilities study.  
30  
(10) An electric utility shall provide written study results to each applicant at the  
completion of each study during the batch study. An electric utility shall offer to hold a  
conference call with each batch applicant at the completion of each study phase, with the  
electric utility making reasonable efforts to accommodate applicants’ availability when  
scheduling the call. An electric utility may choose to group the consultation of multiple  
projects by the applicant and its affiliates into the same conference call. The conference  
call must provide a summary of outcomes and answer questions from applicant. All  
conferences regarding the study results should be held within 30 business days following  
completion of each study phase.  
(11) Within 45 business days following the completion of each study phase, the  
applicant shall choose to either continue to the next study phase of the batch study or  
withdraw. The fee for the next study phase in the batch study is due by the end of the 45  
business days, unless extended by the electric utility. An applicant that withdraws from  
the study may reapply with a new interconnection application.  
(12) Applicants may reduce the capacity of the DER by up to 20% during the decision  
period between study phases until the conclusion of the system impact study. If the  
applicant wants to increase the capacity of the DER, the electric utility may require the  
applicant to submit a new interconnection application and pay the appropriate fees.  
(13) Within 45 business days of the applicant receiving the final batch study report from  
the electric utility, the applicant shall notify the electric utility of its plan to proceed to R  
460.964 for an interconnection agreement or withdraw its interconnection application. If  
the applicant fails to notify the electric utility within 45 business days, the electric utility  
may withdraw the interconnection application.  
(14) If an interconnection application is delayed due to an affected system issue,  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint pursuant to R 792.10439 to R 792.10446, the other interconnection  
applications in the batch must continue to progress through the batch study process. If  
feasible, considering the status of the batch study, the delayed interconnection application  
may rejoin the batch study after the affected system issue is resolved. An interconnection  
application that is the subject of informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or a complaint pursuant to R 792.10439 to R  
792.10446, may rejoin the batch study at a later date, if feasible, considering the status of  
the batch study.  
(15) A batch study is considered complete 45 business days after all batch applicants,  
except those applicants whose DERs are either causing unresolved affected system  
issues, pursuing informal mediation pursuant to R 460.904, pursuing formal mediation  
under R 460.906, or pursuing a complaint under R 792.10439 to R 792.10446, have  
withdrawn, voluntarily or otherwise, or have received the final study results from the  
electric utility.  
R 460.958 Scoping meeting for interconnection applications that are to be studied  
individually.  
Rule 58. (1) This rule applies only to those electric utilities that have elected to  
individually study DERs that qualify for study track.  
31  
(2) Upon request of the applicant, the electric utility and the applicant shall schedule a  
scoping meeting between the electric utility and the applicant to discuss the  
interconnection application and review existing fast track results, if any. The scoping  
meeting must take place within 20 business days after the interconnection application is  
considered complete by the electric utility or, if applicable, the fast track has been  
completed and the applicant has elected to continue with the system impact study or  
facilities study.  
(3) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting.  
(4) The scoping meeting may occur in-person or via telecommunications.  
(5) During the scoping meeting, the electric utility shall identify and communicate to the  
applicant whether the applicant must proceed to a system impact study, a facilities study,  
or an interconnection agreement and the basis for that decision, and 1 of the following  
must occur:  
(a) If a system impact study must be performed, the interconnection application  
proceeds to R 460.960.  
(b) If a facilities study must be performed, the interconnection application proceeds to  
R 460.962.  
(c) The interconnection application must proceed to R 460.964 for an interconnection  
agreement.  
R 460.960 System impact study agreement, scope, procedure, and review meeting.  
Rule 60. (1) For all DERs being studied individually or as part of a batch, all of the  
following apply:  
(a) An electric utility shall provide the applicant a system impact study agreement  
within 5 business days of proceeding to this rule.  
(b) A system impact study agreement must include all of the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee.  
(iii) If necessary, a list of any additional and reasonable technical data needed from the  
applicant to perform the system impact study.  
(iv) A timeline for completion of the system impact study.  
(v) A list of the information that must be provided to the applicant in the system impact  
study report.  
(c) An applicant who has requested a system impact study shall return the completed  
system impact study agreement, provide any additional technical data requested by the  
electric utility, and pay the required fee within 20 business days. An electric utility may  
consider the application withdrawn if the system impact study agreement, payment, and  
required technical data are not returned within 20 business days.  
(d) A system impact study must identify and describe the electric system impacts that  
would result if the proposed DER was interconnected without electric system  
modifications. A system impact study must provide a non-binding good faith list of  
facilities that are required as a result of the application and non-binding estimates of costs  
and time to construct these facilities.  
32  
(e) An electric utility shall explain in its interconnection procedures the process for  
conducting system impact studies on DERs when there is an affected system issue.  
(2) For DERs being studied as part of a batch, an electric utility may request reasonable  
additional data from the applicant during the system impact study. The electric utility and  
the applicant shall work together to resolve the additional data request so that the electric  
utility will be able to complete the batch study within the 1-year timeframe specified in R  
460.956. An electric utility may not be found in violation of these rules when 1 or more  
applicants impede the batch study process through applicant delays, demands,  
complaints, litigation, objections, or other similar actions.  
(3) For DERs being studied individually, all of the following shall apply:  
(a) The electric utility shall complete the system impact study and the system impact  
study report. If necessary, the electric utility shall transmit a facilities study agreement to  
the applicant within 60 business days of receipt of the signed system impact study  
agreement, payment of all applicable fees, and any necessary technical data.  
(b) An electric utility may request reasonable additional data from the applicant within  
20 business days of beginning the system impact study. The electric utility and the  
applicant shall work together to resolve the additional data request so that the electric  
utility will be able to complete the system impact study within 60 business days as  
specified in subdivision (a) of this subrule.  
(c) Within 15 business days of receiving the system impact study report, the applicant  
shall notify the electric utility that it plans to pursue a system impact study review  
meeting, proceed to a facilities study pursuant to R 460.962, or withdraw the application.  
If the applicant fails to notify the electric utility within 15 business days, the electric  
utility may consider the application to be withdrawn.  
(d) Upon request by the applicant pursuant to subdivision (c) of this subrule, the electric  
utility and the applicant shall schedule a system impact study review meeting between the  
electric utility and the applicant to review system impact study results and determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The system impact study review meeting must take place within 25  
business days of the electric utility receiving notification that the applicant plans to attend  
a system impact study review meeting.  
(e) At the system impact study review meeting, the electric utility shall offer the  
applicant all of the following options:  
(i) Proceed to a facilities study pursuant to R 460.962.  
(ii) Proceed directly to R 460.964 for an interconnection agreement.  
(iii) Withdraw the interconnection application.  
(f) Following the meeting, the applicant has not more than 45 business days to decide  
on a course of action. If an applicant fails to notify the electric utility within 45 business  
days, the electric utility may consider the application to be withdrawn.  
(g) The system impact study review meeting may occur in-person or via  
telecommunications.  
R 460.962 Facilities study agreement, scope, procedure; review meeting.  
Rule 62. (1) For DERs being studied individually or as part of a batch, all of the  
following apply:  
33  
(a) If construction of facilities is required to provide interconnection and  
interoperability of the DER with the electric utility’s distribution system, the electric  
utility shall provide the applicant a facilities study agreement and the results of the  
applicant’s system impact study pursuant to R 460.960, if applicable. If no system impact  
study was performed, the electric utility shall provide a facilities study agreement within  
10 business days of proceeding to this rule.  
(b) The facilities study agreement must include the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee.  
(iii) A timeline for completion of the facilities study.  
(iv) A list of the information that will be provided to the applicant in the facilities study  
report.  
(c) The applicant shall return the signed facilities study agreement and pay the required  
facilities study fee within 20 business days. The electric utility may withdraw the  
application if the facilities study agreement and payment are not returned within 20  
business days.  
(d) A facilities study must specify and estimate the cost of the required equipment,  
engineering, procurement, and construction work, including overheads, needed to  
interconnect the DER, and an estimated timeline for the completion of construction. The  
electric utility shall provide cost estimates that are detailed and itemized.  
(e) The electric utility shall explain in its interconnection procedures the process for  
conducting facilities studies on DERs while there is an affected system issue.  
(2) For DERs being studied individually, all of the following are required:  
(a) The electric utility shall complete the facilities study and transmit a facilities study  
report to the applicant within 80 business days of the receipt of the signed facilities study  
agreement and payment of the facilities study fee.  
(b) Within 10 business days of receiving a facilities study report from the electric  
utility, the applicant shall select 1 option from the following options:  
(i) Request a facilities study review meeting with the electric utility.  
(ii) Proceed to an interconnection agreement pursuant to R 460.964.  
(iii) Withdraw the interconnection application.  
If the applicant fails to inform the electric utility within 10 business days of its chosen  
course of action, the electric utility may consider the application withdrawn.  
(c) Upon request by the applicant pursuant to subdivision (b)(i) of this subrule, the  
electric utility and the applicant shall schedule a facilities study review to review the  
facilities study results and determine what further steps are needed to permit the DER to  
be connected safely and reliably to the distribution system. The facilities study review  
meeting must take place within 25 business days of the electric utility receiving  
notification that the applicant will attend a facilities study review meeting.  
(d) At the facilities study review meeting, the electric utility shall offer both of the  
following options:  
(i) Proceed to an interconnection agreement pursuant to R 460.964.  
(ii) Withdraw the interconnection application.  
(e) Following the meeting, the applicant has no more than 20 business days to decide on  
a course of action and notify the electric utility of this course of action. If the applicant  
34  
fails to notify the electric utility within 20 business days, the electric utility may withdraw  
the application.  
(f) The facilities study review meeting may be conducted in-person or via  
telecommunications.  
R 460.964 Interconnection agreement.  
Rule 64. (1) For level 1, 2, or 3 interconnection applications, where no construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
provide its standard level 1, 2, and 3 interconnection agreement to an applicant within 3  
business days of reaching this stage.  
(2) For level 1, 2, or 3 interconnection applications, where construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
provide its standard level 1, 2, and 3 interconnection agreement with modifications to  
address required construction activities, construction milestone timing, and cost to an  
applicant within 5 business days of reaching this stage. The applicant and electric utility  
shall mutually agree on the timing of construction milestones.  
(3) For an applicant with level 1, 2, or 3 interconnection applications, the applicant shall  
sign and return the standard level 1, 2, and 3 interconnection agreement with payment, if  
applicable, within 20 business days of receiving the agreement.  
(a) If the applicant did not sign and return the standard level 1, 2, and 3 interconnection  
agreement and payment, if applicable, within 20 business days, the electric utility shall  
notify the applicant of the missed deadline and grant an extension of 15 business days. If  
the electric utility did not receive the signed standard level 1, 2, and 3 interconnection  
agreement and any applicable payment during the 15-business-day extension, the electric  
utility may consider the interconnection application withdrawn subject to subdivision (b)  
of this subrule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, the  
formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446 within the 20 business days, the outcome of that process must  
establish a time frame for the applicant to return the signed interconnection agreement  
and any applicable payment.  
(4) For level 1, 2, or 3 projects, the electric utility shall countersign and provide a  
completed copy of the standard level 1, 2, and 3 interconnection agreement within 10  
business days of the applicant returning the signed standard level 1, 2, and 3  
interconnection agreement.  
(5) For level 4 or 5 projects, the electric utility shall provide its level 4 and 5  
interconnection agreement within 10 business days of reaching this stage. When  
construction of interconnection facilities or distribution upgrades is necessary, the level 4  
and 5 interconnection agreement must contain either timelines for completion of activities  
and estimates of construction costs or a timetable when these requirements can be  
determined. The interconnection agreement must include a payment schedule that  
corresponds to the milestones established and must require the electric utility to refund  
any unspent and unobligated funds if the agreement is terminated.  
35  
(6) For an applicant with level 4 or 5 DERs, the applicant shall sign and return with  
payment, if applicable, a level 4 and 5 interconnection agreement within 30 business  
days.  
(a) If the applicant does not sign and return the level 4 and 5 interconnection agreement  
with payment within 30 business days, an electric utility shall notify the applicant of the  
missed deadline and grant an extension of 15 business days. If the electric utility does not  
receive the signed level 4 and 5 interconnection agreement and payment, if applicable,  
during the 15-business-day extension, the electric utility may consider the interconnection  
application withdrawn, subject to subdivision (b) of this subrule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or the complaint process pursuant to R 792.10439 to R  
792.10446 within 30 business days, the outcome of that process must establish a time  
frame for the applicant to return the signed interconnection agreement and applicable  
payment. There is a rebuttable presumption in the complaint proceeding that the electric  
utility’s standard construction, procurement, installation, design, and cost practices are  
lawful, reasonable, and prudent.  
(i) For study track interconnection applications filed with an electric utility conducting  
batch studies, if either informal mediation pursuant to R 460.904, formal mediation  
pursuant to R 460.906, or the complaint process pursuant to R 792.10439 to R 792.10446  
does not result in the applicant returning a signed interconnection agreement with any  
applicable payment prior to the electric utility beginning the study phase of the next batch  
study pursuant to R 460.956, the electric utility may not include the interconnection  
application in the system baseline for conducting the next batch study. If the  
interconnection application is electrically coincident with other interconnection  
applications in the next batch study, the electric utility may require the withdrawal of the  
interconnection application.  
(ii) For study track interconnection applications filed with an electric utility conducting  
individual studies, electrically coincident applications filed after the interconnection  
application must be placed on hold for not more than 60 business days. If either informal  
mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or the  
complaint process pursuant to R 792.10439 to R 792.10446 does not result in the  
applicant returning a signed interconnection agreement with any applicable payment  
within 60 business days and there are electrically coincident interconnection applications  
in progress behind this application, the electric utility may require the withdrawal of the  
interconnection application.  
(7) For level 4 or 5 projects, an electric utility shall countersign and provide a completed  
copy of the level 4 and 5 interconnection agreement within 10 business days of the  
applicant returning a mutually agreed-upon and signed level 4 and 5 interconnection  
agreement.  
(8) An applicant shall pay the actual cost of the interconnection facilities and  
distribution upgrades. The cost to the applicant for interconnection facilities and  
distribution upgrades may not exceed 110% of the estimate without an itemized summary  
and explanation of cost increases being provided to the applicant prior to being incurred.  
The cost may not exceed 125% of the estimate without the consent of the applicant prior  
to the costs being incurred.  
36  
(9) A party’s obligations under the interconnection agreement may be extended by  
agreement. If a party anticipates that it will be unable to meet a milestone for any reason  
other than an unforeseen event, the party shall do all of the following:  
(a) Immediately notify the other party of the reason or reasons for not meeting the  
milestone.  
(b) Propose the earliest alternate date when it can attain this and future milestones.  
(c) Request amendments to the interconnection agreement, if needed to address the  
changed milestones.  
(10) The party affected by the failure to meet a milestone shall not withhold agreement  
to any amendments proposed in subrule (9)(c) of this rule unless 1 of the following  
applies:  
(a) The party affected will suffer significant uncompensated economic or operational  
harm from the amendment or amendments.  
(b) The milestone under question has been previously delayed.  
(c) The affected party has reason to believe that the delay in meeting the milestone is  
intentional or unwarranted notwithstanding the circumstances explained by the party  
proposing the amendment.  
(11) If the party affected by the failure to meet a milestone disputes the proposed  
extension, the affected party may pursue either informal mediation pursuant to R  
460.904, formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446.  
(12) The electric utility shall provide the applicant with a final accounting report of any  
difference between costs charged to the applicant and previous payments to the electric  
utility for interconnection facilities or distribution upgrades. Both of the following apply  
regarding the final accounting:  
(a) If the costs charged to the applicant exceed its previous aggregate payments, the  
electric utility shall bill the applicant for the amount due and the applicant shall make a  
payment to the electric utility within 20 business days of the final accounting report. The  
applicant may dispute the invoice pursuant to either informal mediation pursuant to R  
460.904, formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446. If there is a dispute, the applicant shall make payment within  
30 business days of final resolution of the dispute. Failure by the applicant to pay its costs  
is cause for disconnection of the applicant’s DER.  
(b) If the applicant’s previous aggregate payments exceed its costs under the  
construction agreement, the electric utility shall refund to the applicant an amount equal  
to the difference within 20 business days of the final accounting report.  
(13) The electric utility is responsible for specifying requirements in interconnection  
agreements to support independent system operator regulations or regional transmission  
operator regulations.  
(14) The electric utility may propose to the commission that a signed interconnection  
agreement be modified to require compliance with changes to an independent system  
operator, a regional transmission operator, or the state’s regulations, provided that these  
modifications do not alter the rights or obligations of the interconnection customer.  
37  
R 460.966 Inspection, testing, and commissioning.  
Commented [DTEE15]: This section is not referenced by  
number or description except in the legacy net metering rules  
and the flow charts. The Interconnection agreement  
construction terms being completed should lead to this  
section.  
Rule 66. (1) If the interconnection application requires telecommunications,  
cybersecurity, data exchange or remote controls operation, successful testing and  
certification of these items must be completed prior to or during testing. The electric  
utility’s interconnection procedures must describe the technical requirements of these  
items.  
(2) An applicant shall notify the electric utility when installation of a DER and any  
required local code inspection and approval is complete. The applicant shall provide any  
test reports or configuration documents as defined in the standard level 1, 2, and 3  
interconnection agreement or level 4 and 5 interconnection agreement.  
(3) The electric utility shall review the applicant’s inspection, test reports, or  
configuration documents, and communicate its intent to perform a witness or  
commissioning test, or waive its right to perform a witness test and commissioning test  
within 10 business days.  
Commented [DTEE16]: Common items can be in the  
procedures, Site specific requirements may be called out in  
the interconnection construction agreement.  
Commented [DTEE17]: What happens if the applicant’s  
documents are incomplete, insufficient or do not meet the  
requirements, should this have similar language to 7b? It will  
be more efficient for both the customer and utility to catch  
deficiencies and resolve them before committing to field  
inspections or final testing.  
(4) If the electric utility intends to witness or perform commissioning tests required to  
comply with the interconnection agreement or the interconnection procedures and inspect  
the DER, the electric utility shall witness or perform the commissioning tests and inspect  
the DER within either of the following:  
(a) Ten business days of receiving the notification from the applicant pursuant to  
subrule (2) of this rule, for level 1, 2, and 3 applications.  
Commented [DTEE18]: 5b allows a customer 20 business  
days to provide information for a desk review, but 4a only  
allows 10 business days to coordinate with the customer and  
physically visit a site?  
(b) A mutually-agreed upon timeframe after receiving the notification from the  
applicant pursuant to subrule (2) of this rule for level 4 and 5 applications.  
(5) The electric utility may waive its right to visit the site and inspect the DER or  
perform the commissioning tests. If the electric utility waives this right, both of the  
following apply:  
(a) It shall provide a written waiver to the applicant within 10 business days from  
receiving the notification from the applicant pursuant to subrule (2) of this rule.  
(b) The applicant shall provide the electric utility with the completed commissioning  
test report within 20 business days of receipt of the electric utility’s written waiver.  
(6) If the electric utility attempts to conduct the inspection and testing pursuant to  
subrule (4) of this rule at the arranged time and is unable to access the DER or complete  
the testing, the DER must remain disconnected until the applicant and the electric utility  
can complete the inspection and testing.  
Also, this only addresses the simplest cases, Level 1,2,3  
projects may (especially in commercial tariffs) have required  
service/metering upgrades or shutdowns, replacement of  
equipment, installation or reconfiguring of relaying etc, or  
consist of multiple phases of development and may require  
mutual agreement as to the specific timing to accommodate  
customer schedules and utility operations. This provision  
should be 20 business days and mutual agreement should be  
an option as well.  
(7) If the electric utility witnessed or performed commissioning tests and inspected the  
DER pursuant to subrule (4) of this rule, within 5 business days of the receipt of the  
completed commissioning test report, the electric utility shall notify the applicant whether  
it has accepted or rejected the commissioning test report and found the site to be  
satisfactory or unsatisfactory.  
(a) If the commissioning test report is accepted and the site was found satisfactory, the  
electric utility shall provide the notification of acceptance in writing, and the  
interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report or did not find the site  
satisfactory, the electric utility shall provide its reasons for doing so in writing and the  
applicant has not less than 20 business days to implement corrections. The applicant, after  
taking corrective action, shall request the electric utility to reconsider its findings. The  
applicant may be billed the actual cost of any re-inspections.  
38  
(8) If the electric utility waived its right to witness or perform commissioning tests and  
inspect the DER pursuant to subrule (5) of this rule, within 5 business days of the receipt  
of the completed commissioning test report, the electric utility shall notify the applicant  
whether it has accepted or rejected the commissioning test report as follows:  
(a) If the commissioning test report is accepted, the electric utility shall provide  
notification of acceptance, and the interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report, the electric utility shall  
provide its reasons for doing so in writing and the applicant has not less than 20 business  
days to implement corrections. The applicant, after taking corrective action, may then  
request the electric utility to reconsider its findings.  
(9) The cost of testing and inspection for applicants participating in an electric utility’s  
distributed generation program, as described in part 3 of these rules, R 460.1001 to R  
460.1026, are considered a cost of operating a distributed generation program and must  
be recovered pursuant to section 175(1) of the clean and renewable energy and energy  
waste reduction act, 2008 PA 295, MCL 460.1175.  
(10) If the applicant does not notify the electric utility that the DER is installed and  
ready to test pursuant to subrule (2) of this rule, the electric utility may, in writing, query  
the status of the interconnection. If the applicant does not provide a written response  
within 10 business days or no progress is evident, the electric utility may consider the  
interconnection application withdrawn.  
R 460.968 Authorization required prior to parallel operation.  
Rule 68. (1) The electric utility shall provide to the applicant written authorization to  
operate in parallel with the electric utility within 5 business days of all of the following  
conditions being met:  
(a) The electric utility notified the interconnection applicant that the commissioning test  
and inspection, where applicable, are accepted.  
(b) The applicant complied with all applicable parallel operation requirements as set  
forth in the electric utility’s interconnection procedures and applicable interconnection  
agreement.  
(c) The applicant complied with all applicable local, state, and federal requirements.  
(d) The electric utility received full payments for all outstanding bills.  
(2) With the written authorization, interconnection of the DER is considered approved  
for parallel operation, the DER may begin operating, and the applicant is considered an  
interconnection customer.  
(3) The applicant shall not operate its DER in parallel with the electric utility’s  
distribution system without prior written permission to operate from the electric utility.  
(4) Subject to reasonable timing and other conditions, including completion of  
conditions in the interconnection agreement or interconnection procedures, the electric  
utility shall allow for reasonable but limited testing before written authorization has  
occurred.  
R 460.970 Cost allocation of interconnection facilities and distribution upgrades.  
39  
Rule 70. Costs for interconnection facilities and distribution upgrades must be  
classified into 1 of the following categories:  
(a) Site-specific costs, which include, but are not limited to, costs of interconnection  
facilities and distribution upgrades that are caused by 1 DER, whether that DER is  
electrically co-incident with other DERs. These costs must be assigned to the cost-  
causing applicant.  
(b) Shared interconnection facilities costs, which are costs caused by DERs which  
together necessitate the construction of interconnection facilities. The interconnection  
facilities costs that should be shared must be allocated to each applicant based on a  
methodology described in the electric utility’s interconnection procedures.  
(c) Shared distribution upgrade costs, which are costs caused by electrically co-incident  
DERs that together necessitate a distribution upgrade. The distribution upgrade costs that  
should be shared must be allocated to each applicant based on a methodology described  
in the electric utility’s interconnection procedures.  
R 460.974 Interconnection metering and communications.  
Rule 74. (1) Any metering and communications requirements necessitated by use of the  
DER must be installed at the applicant’s expense. The electric utility may furnish this  
equipment at the applicant’s expense.  
(2) The electric utility may charge the interconnection customer reasonable ongoing fees  
to maintain the metering and communications equipment. These fees must be listed in the  
interconnection agreement.  
R 460.976 Post commissioning remedy.  
Rule 76. (1) If the electric utility finds that the DER is operating outside the terms of the  
interconnection agreement but does not find immediate disconnection pursuant to R  
460.978(1)(f) and (g) warranted, the electric utility shall promptly inform the  
interconnection customer or its agent of this finding. The interconnection customer is  
responsible for bringing the DER into compliance within 30 business days or a mutually  
agreed-upon time period. The electric utility may perform an inspection of the DER after  
a remedy is applied.  
(2) If the DER is not brought into compliance within 30 business days or the mutually  
agreed-upon time period, the electric utility may apply a remedy and bill the  
interconnection customer. The interconnection customer shall pay this bill within 5  
business days.  
R 460.978 Disconnection.  
Rule 78. (1) An electric utility may refuse to connect or may disconnect a project from  
the distribution system if any of the following conditions apply:  
(a) Failure of the interconnection customer to bring a DER into compliance pursuant to  
R 460.976(1).  
(b) Failure of the interconnection customer to pay costs of remedy pursuant to R  
460.976(2).  
40  
(c) Termination of interconnection by mutual agreement.  
(d) Distribution system emergency, but only for the time necessary to resolve the  
emergency.  
(e) Routine maintenance, repairs, and modifications performed in a reasonable time and  
with prior notice to the interconnection customer.  
(f) Noncompliance with technical or contractual requirements in the interconnection  
agreement that could lead to degradation of distribution system reliability, electric utility  
equipment, and electric customers’ equipment.  
(g) Noncompliance with technical or contractual requirements in the interconnection  
agreement that presents a safety hazard.  
(h) Other material noncompliance with the interconnection agreement.  
(i) Operating in parallel without prior written authorization from the electric utility as  
provided for in R 460.968.  
(2) An electric utility may disconnect electric service, where applicable, pursuant to R  
460.136.  
R 460.980 Capacity of the DER.  
Rule 80. (1) If the interconnection application requests an increase in capacity for an  
existing DER, the electric utility shall evaluate the application based on the new  
nameplate capacity of the DER. The maximum capacity of a DER is the aggregate  
nameplate capacity or may be limited as described in the electric utility’s interconnection  
procedures.  
(2) An interconnection application for a DER that includes single or multiple types of  
DERs at a site for which the applicant seeks a single point of common coupling must be  
evaluated as described in the electric utility’s interconnection procedures.  
(3) The electric utility’s interconnection procedures must describe acceptable methods  
for power limited export DER including, but not limited to, reverse power protection and  
utilizing inverters or control systems so that the DER capacity considered by the electric  
utility for reviewing the interconnection application is only the amount capable of being  
exported.  
R 460.982 Modification of the interconnection application.  
Rule 82. (1) At any point after an interconnection application is considered accepted  
but before the signing of an interconnection agreement, the applicant, the electric utility,  
or the affected system owner may propose modifications to the interconnection  
application that may improve the costs and benefits of the interconnection, or that  
improve the ability of the electric utility to accommodate the interconnection. The  
applicant shall submit to the electric utility, in writing, all proposed modifications to any  
information provided in the interconnection application and the electric utility shall  
perform a cursory evaluation to determine whether the proposed modification is a  
material modification and provide the results to the applicant within 10 business day.  
(2) The electric utility shall not be required to accept or implement a modification to the  
electric utility’s distribution system or generation assets that is proposed by an applicant  
or affected system operator.  
41  
(3) Neither the electric utility nor the affected system operator may unilaterally modify  
an accepted interconnection application. If the electric utility evaluates DERs using  
individual studies, the timelines specific to that interconnection application must be  
placed on hold while the proposed modification is being evaluated by the electric utility.  
(4) For a proposed modification which the electric utility has determined is a material  
modification, the applicant may request a material modification review to determine  
whether the material modification is an acceptable material modification or an  
unacceptable material modification. The electric utility shall complete the material  
modification review and determine which of the following options are available to the  
applicant:  
(a) If the modification is an unacceptable material modification, the applicant may  
withdraw the modification or withdraw the application.  
(b) If the modification is an acceptable material modification and requires minimal or  
no restudy, the application study activities will resume with the modification and no  
change to the timing.  
(c) If the modification is an acceptable material modification but requires restudy, the  
electric utility shall expedite the restudy. The applicant shall pay any required fee for the  
expedited restudy.  
(5) The applicant may request a 1-hour consultation to discuss the results of the material  
modification review.  
(6) The applicant shall notify the electric utility of its selection pursuant to subrule (4) of  
this rule within 10 business days of receiving the electric utility notification of the results  
or the modification may be considered withdrawn.  
(7) If the proposed modification is determined not to be a material modification or is  
determined to be an acceptable material modification, the electric utility shall notify the  
applicant that the proposed modification has been accepted.  
(8) If the modification is considered an unacceptable material modification, the  
applicant shall withdraw the proposed modification, or initiate mediation pursuant to R  
460.904 or R 460.906, or file a complaint pursuant to R 792.10439 to R 792.10446  
within 10 business days of receipt of the decision, or proceed with a new interconnection  
application for this modification. If the applicant does not provide its determination  
within the 10 business days, the electric utility may consider the interconnection  
application withdrawn.  
ꢀꢀ(9) Any modification to the interconnection application or to the DER that could affect  
the operation of the distribution system, including but not limited to, changes to machine  
data, equipment configuration, or the interconnection site of the DER, not agreed to in  
writing by the electric utility and the applicant may be treated by the electric utility as a  
withdrawal of the interconnection application requiring submission of a new  
interconnection application.  
(10) At any point prior to the execution of an interconnection agreement, changes to  
ownership will cause the interconnection application to be put on hold until the new  
owner signs all necessary agreements and documents. An electric utility may not be  
found in violation of these rules related to the processing of the interconnection  
application during such a transfer of ownership.  
(11) Replacing a component with another component that has near-identical  
characteristics does not constitute a material modification.  
42  
(12) The electric utility’s interconnection procedures must provide examples of  
modification that are not material modifications, acceptable material modifications, and  
unacceptable material modifications.  
(13) The electric utility’s interconnection procedures must provide a procedure for  
performing a material modification review.  
R 460.984 Modifications to the DER.  
Rule 84. After the execution of the interconnection agreement, the applicant shall notify  
the electric utility of any plans to modify the DER. The electric utility shall review the  
proposed modification to determine if the modification is considered a material  
modification. If the electric utility determines that the modification is a material  
modification, the electric utility shall notify the applicant, in writing of its determination  
and the applicant shall submit a new application and application fee along with all  
supporting materials that are reasonably requested by the electric utility. The applicant  
may not begin any material modification to the DER until the electric utility has accepted  
the new interconnection application and completed at least one of the following:  
(a) An initial review.  
(b) A supplemental review.  
(c) A system impact study.  
(d) A facilities study.  
Commented [DTEE19]: The applicant should only  
proceed with executing material modifications to the DER if  
they have an executed Interconnection agreement. For  
example if an initial review indicated supplemental review is  
needed to accept the modification, then it is not decided that  
the modification will not require further changes before  
being implemented.  
R 460.986 Insurance.  
Rule 86. (1) An applicant interconnecting a level 1 or 2 project to the distribution  
system of an electric utility may not be required by the electric utility to obtain any  
additional liability insurance.  
(2) An electric utility shall not require an applicant interconnecting a level 1 or 2 project  
to name the electric utility as an additional insured party.  
(3) For a level 3 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $1,000,000.  
(4) For a level 4 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $2,000,000.  
(5) For a level 5 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $3,000,000.  
R 460.988 Easements and rights-of-way.  
Rule 88. If an electric utility line extension is required to accommodate an  
interconnection, the applicant is responsible for procurement and the cost of providing  
and obtaining easements or rights-of-way.  
R 460.990 Interconnection penalties.  
Rule 90. Pursuant to section 10e of 1939 PA 3, MCL 460.10e, an electric utility shall  
take all necessary steps to ensure that DERs are connected to the distribution systems  
43  
within their operational control. If the commission finds, after notice and hearing, that an  
electric utility has prevented or unduly delayed the ability of a DER greater than 100 kW  
to connect to the distribution system of the electric utility, the commission may order  
remedies designed to make whole the applicant proposing the DER, including, but not  
limited to, reasonable attorney fees. If the electric utility violates this rule, the  
commission may order fines of not more than $50,000 per day, commensurate with the  
demonstrated impact of the violation.  
R 460.991 Catastrophic conditions.  
Rule 91. An electric utility shall notify the commission and all applicants that have in-  
process applications when timelines are being extended due to catastrophic conditions as  
defined in R 460.702(f). The electric utility shall also notify the commission and all  
applicants that have in-process applications when application processing resumes.  
R 460.992 Electric utility annual reports.  
Rule 92. An electric utility shall file an annual interconnection report on a date and in a  
format determined by the commission.  
PART 3. DISTRIBUTED GENERATION PROGRAM STANDARDS  
R 460.1001 Application process.  
Rule 101. (1) An electric utility shall file initial distributed generation program tariff  
sheets in the first rate case filed after June 1, 2018.  
(2) Within 30 days of a commission order approving an electric utility’s initial  
distributed generation tariff, or within 30 days of the effective date of these rules,  
whichever is later, an alternative electric supplier serving customers in that electric  
utility’s service territory shall file an updated distributed generation program plan  
applicable to its customers in the affected electric utility’s service territory.  
(3) An electric utility and an alternative electric supplier shall annually file a legacy net  
metering program report and, if applicable, a distributed generation program report not  
later than March 31 of each year.  
(4) An electric utility and an alternative electric supplier shall maintain records of all  
applications and up-to-date records of all eligible electric generators participating in the  
legacy net metering program and distribution generation program.  
(5) Selection of customers for participation in the legacy net metering program or  
distributed generation program must be based on the order in which the applications are  
received.  
(6) An electric utility or alternative electric supplier shall not refuse to provide or  
discontinue electric service to a customer solely because the customer participates in the  
legacy net metering program or distributed generation program.  
(7) The legacy net metering program and distributed generation program provided by  
electric utilities and alternative electric suppliers must be designed for a period of not less  
44  
than 10 years and limit each applicant to generation capacity designed to meet up to  
100% of the customer’s electricity consumption for the previous 12 months.  
(a) The generation capacity must be determined by an estimate of the expected annual  
kWh output of the generator or generators as determined in an electric utility’s  
interconnection procedures and specified on an electric utility's legacy net metering  
program or distributed generation program tariff sheet or in the alternative electric  
supplier’s legacy net metering program or distributed generation program plan. For  
projects in which energy export controls are implemented pursuant to section R 460.980  
and utilized to limit the export to 100% of the customer’s electricity consumption for the  
previous 12 months, an electric utility shall not add the storage capacity to generation  
capacity for the purpose of the study. If a customer has multiple inverters capable of  
exporting to the distribution grid, the inverters must be configured in a way that prevents  
the cumulative maximum export at any given time to exceed the approved amount in the  
customer’s application.  
(b) A customer’s electric consumption must be determined by 1 of the following  
methods:  
(i) The customer’s annual energy consumption, measured in kWh, during the previous  
12-month period.  
(ii) If there is no data, incomplete data, or incorrect data for the customer’s energy  
consumption or the customer is making changes on-site that will affect total  
consumption, the electric utility or alternative electric supplier and the customer shall  
mutually agree on a method to determine the customer’s electric consumption.  
(c) A net metering or distributed generation customer using an energy storage device in  
conjunction with an eligible electric generator shall not design or operate the energy  
storage device in a manner that results in the customer’s electrical output exceeding  
100% of the customer’s electricity consumption for the previous 12 months. Energy  
storage devices must be configured to prevent export of stored electricity to the  
distribution system. The addition of an energy storage device to an existing approved  
legacy net metering program system or distributed generation program system is  
considered a material modification. The electric utility interconnection procedures must  
include details describing how energy storage equipment may be integrated into an  
existing legacy net metering program system without impacting the 10-year  
grandfathering period.  
(8) An applicant shall notify the electric utility of plans for any material modification to  
the project. An applicant shall re-apply for interconnection pursuant to part 2 of these  
rules, R 460.911 to R 460.992, and submit revised legacy net metering program or  
distributed generation program application forms and associated fees. An applicant may  
be eligible to continue participation in the legacy net metering program or distributed  
generation program when a material modification is made to a customer’s previously  
approved system and it does not violate the requirements of subrule (7) of this rule. An  
applicant shall not begin any material modification to the project until the electric utility  
has approved the revised application, including any necessary system impact study or  
facilities study. The application must be processed pursuant to part 2 of these rules, R  
460.911 to R 460.992.  
Commented [DTEE20]: This should also refer to 460.1026  
(“A customer participating in a legacy net metering program  
who increases the nameplate capacity of its generation  
system after the effective date of an electric utility’s  
distributed generation program tariff is no longer eligible to  
participate in the legacy net metering program.”)  
45  
R 460.1004 Legacy net metering program application and fees.  
Rule 104. (1) An electric utility or alternative electric supplier may use an online legacy  
net metering program application process. An electric utility or alternative electric  
supplier not using an online application process, may utilize a uniform legacy net  
metering program application form which must be approved by the commission. An  
electric utility’s legacy net metering program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the legacy net metering program shall concurrently submit a completed  
legacy net metering program application and interconnection application or indicate on  
the legacy net metering program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968.  
(a) Where a legacy net metering program application is accompanied by an associated  
interconnection application, an electric utility shall complete its review of the legacy net  
metering program application in parallel with processing the interconnection application  
pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, the electric utility shall notify the customer whether  
the legacy net metering program application is accepted, and provide an opportunity for  
the customer to resolve any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application, or the electric utility may consider the legacy  
net metering program application withdrawn without refund of the application fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.940 simplified track or R 460.946 fast track initial review, the electric  
utility shall determine whether the appropriate meter or meters, is installed for the legacy  
net metering program.  
(b) When a legacy net metering program application is filed with an already in-progress  
interconnection application, the utility may process the legacy net metering application in  
parallel with the interconnection application pursuant to part 2 of these rules, R 460.911  
to R 460.992, and subdivision (a) of this subrule, if practicable, or adopt the review  
process pursuant to subdivision (c) of this subrule.  
(c) When a legacy net metering program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the legacy net metering program application in parallel with the interconnection  
application, or when the legacy net metering application is filed subsequent to the  
customer receiving authorization to operate its eligible generator in parallel pursuant to R  
460.968, the electric utility shall process the legacy net metering program application  
pursuant to both of the following:  
(i) The electric utility shall review the legacy net metering program application and  
determine whether to accept the application pursuant to the timelines in R 460.936(6) and  
(7) within 10 business days. The timelines in R 460.936(7)(a) apply to electric utility  
notifications. The electric utility shall provide the customer an opportunity to resolve any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
deficiency within the timelines pursuant to R. 460.936(7)(b), the electric utility may  
46  
consider the legacy net metering application withdrawn without refund of the application  
fees.  
(ii) Within 10 business days of notifying the customer that the legacy net metering  
application has been accepted, the electric utility shall determine whether the appropriate  
meter is installed for the legacy net metering program.  
(d) If a customer approved for participation in the legacy net metering program requires  
a new or additional meter or meters, the electric utility shall arrange with the customer to  
install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit the  
distributed generation program credit to be applied to the account no more than 10  
business days after the necessary meter is installed and all necessary steps in R 460.966  
are completed.  
Commented [DTEE21]: This should say legacy net  
metering program since this is the legacy net metering  
section.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed legacy net metering program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The electric utility shall process the legacy net metering program application  
according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit the legacy net  
metering program credit to be applied to the account.  
(4) If a legacy net metering program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the deficiency  
within the timelines pursuant to R. 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the legacy net metering application withdrawn without  
refund of the application fees.  
(5) If a customer’s application for the legacy net metering program is approved, the  
customer shall have a completed and approved installation within 6 months from the date  
the customer’s application is considered complete, or the electric utility or alternative  
electric supplier may terminate the application without refund and shall have no further  
responsibility with respect to the application.  
(6) Customers participating in a legacy net metering program approved by the  
commission before the commission establishes a tariff pursuant to section 6a(14) of 1939  
PA 3, MCL 460.6a, may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment.  
(7) The legacy net metering program application fee for electric utilities and alternative  
electric suppliers may not exceed $50. The fee must be specified on the electric utility’s  
legacy net metering tariff sheet or in the alternative electric supplier's legacy net metering  
program plan.  
47  
R 460.1006 Distributed generation program application and fees.  
Rule 106. (1) An electric utility or alternative electric supplier may use an online  
distributed generation program application process. An electric utility or alternative  
electric supplier not using an online application process may utilize a uniform distributed  
generation program application form that must be approved by the commission. An  
electric utility’s distributed generation program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the distributed generation program shall concurrently submit a completed  
distributed generation program application and interconnection application or indicate on  
the distributed generation program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968. The following shall also  
apply.  
(a) When a distributed generation program application is accompanied by an associated  
interconnection application, an electric utility shall complete its review of the distributed  
generation program application in parallel with processing the interconnection  
application pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, an electric utility shall notify the customer whether  
the distributed generation program application is accepted, and provide an opportunity for  
the customer to remedy any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the electric utility may consider the  
distributed generation program application withdrawn without refund of the application  
fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.940 simplified track or R 460.946 fast track initial review, the electric  
utility shall determine whether the appropriate meter is installed for the distributed  
generation program.  
(b) If a distributed generation program application is filed with an already in-progress  
interconnection application, the electric utility may process the distributed generation  
program application in parallel with the interconnection application pursuant to part 2 of  
these rules, R 460.911 to R 460.992, and subdivision (a) of this subrule, if practicable, or  
adopt the review process pursuant to subdivision (c) of this subrule.  
(c) If a distributed generation program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the distributed generation program application in parallel with the  
interconnection application or the distributed generation application is filed subsequent to  
the customer receiving authorization to operate its eligible generator in parallel pursuant  
to R 460.968, the electric utility shall process the distributed generation program  
application pursuant to all of the following:  
(i) The electric utility has 10 business days to review the distributed generation  
program application and determine whether to accept the application pursuant to the  
timelines in R 460.936(6) and (7). The timelines in R 460.936(7)(a) apply to utility  
48  
notifications. The electric utility shall provide the customer an opportunity to remedy any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
application deficiencies within the timelines in R 460.936(7)(b), the electric utility may  
consider the distributed generation program application withdrawn without refund of the  
application fees.  
(ii) Within 10 business days of providing notification to the customer that the  
distributed generation program application has been accepted, the electric utility shall  
determine whether the appropriate meter, or meters, is installed for the distributed  
generation program.  
(d) If a customer approved for participation in the distributed generation program  
requires a new or additional meter or meters, the electric utility shall arrange with the  
customer to install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit  
distributed generation program credit to be applied to the account no more than 10  
business days after the necessary meter is installed and all necessary steps in R 460.966  
are completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed distributed generation program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The alternative electric supplier shall process the distributed generation program  
application according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit distributed generation  
program credit to be applied to the account.  
(4) If a distributed generation program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the distributed generation program application withdrawn  
without refund of the application fees.  
(5) If a customer’s distributed generation program application is approved, the customer  
shall have a completed and approved installation within 6 months from the date the  
customer’s application is considered complete, or the electric utility or alternative electric  
supplier may consider the application withdrawn without refund and shall have no further  
responsibility with respect to the application.  
(6) The distributed generation program application fee for electric utilities and  
alternative electric suppliers shall not exceed $50. The electric utility shall specify the fee  
on the electric utility’s distributed generation program tariff sheet or in the alternative  
electric supplier’s distributed generation program plan.  
49  
(7) The customer shall pay all interconnection costs pursuant to part 2 of these rules, R  
460.911 to R 460.992, which include all electric utility costs associated with the  
customer’s interconnection that are not a distributed generation program application fee,  
excluding meter costs as described in R 460.1012 and R 460.1014.  
R 460.1008 Legacy net metering program and distributed generation program size.  
Rule 108. (1) If an electric utility or alternative electric supplier reaches the program  
sizes as defined in section 173(3) of the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1173, as determined by combining both the  
distributed generation program and the legacy net metering program customer  
enrollments, the electric utility or alternative electric supplier shall notify the  
commission.  
(2) The electric utility or alternative electric supplier shall notify the commission of its  
plans to either close the program to new applicants or expand the program.  
(3) The electric utility shall file corresponding revised legacy net metering program or  
distributed generation program tariff sheets.  
(4) The alternative electric supplier shall file a revised legacy net metering program plan  
or distributed generation program plan.  
R 460.1010 Generation and legacy net metering program or distributed generation  
program equipment.  
Rule 110. New legacy net metering program or distributed generation program  
equipment and its installation must meet all current local and state electric and  
construction code requirements, and other standards as specified in part 2 of these rules,  
R 460.911 to R 460.992.  
R 460.1012 Meters for legacy net metering program.  
Rule 112. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility may determine the customer’s net usage using the customer’s  
existing meter if it is capable of reverse registration or may install a single meter with  
separate registers measuring power flow in each direction. If the electric utility uses the  
customer’s existing meter, the electric utility shall test and calibrate the meter to assure  
accuracy in both directions. If the customer’s meter is not capable of reverse registration  
and if meter upgrades or modifications are required, the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to the legacy net metering program customer. The cost of the meter or  
meter modification is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for the meter provided by the electric utility  
to similarly situated non-generating customers shall be paid by the eligible customer.  
50  
(c) An electric utility shall provide a generator meter, if requested by the customer, at  
cost.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, the electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide this functionality, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a legacy net metering program customer. The cost of the meter or  
meters is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for meters provided by the electric utility to  
similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter is  
considered a cost of operating the legacy net metering program.  
(3) For a customer with a generation system capable of generating more than 150 kWac,  
the electric utility shall utilize a meter or meters capable of measuring the flow of energy  
in both directions and the generator output. If meter upgrades are necessary to provide  
this functionality, the customer shall pay the cost of providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a legacy net metering program participant or the legacy net  
metering program.  
R 460.1014 Meters for distributed generation program.  
Rule 114. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility shall determine the customer’s power flow in each direction  
using the customer's existing meter if it is capable of measuring and recording power  
flow in each direction. If the customer’s meter is not capable of measuring and recording  
the customer’s power flow in each direction and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring and recording the customer’s power flow in each  
direction at no additional charge to the distributed generation program customer. The cost  
of the meter or meter modification is considered a cost of operating the distributed  
generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring and recording the power flow in each direction to  
customers at cost. Only the incremental cost above the cost for the meter provided by the  
electric utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter at cost, if requested by the  
customer.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
51  
measuring and recording power flow in each direction and the generator output. If the  
customer’s meter is not capable of measuring and recording the customer’s power flow in  
each direction along with the generator output, and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a distributed generation program customer. If the electric utility  
provides the upgraded meter at no additional charge to the customer, the cost of the meter  
is considered a cost of operating the distributed generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above the cost for the meter provided by the electric  
utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter shall be  
considered a cost of operating the distributed generation program.  
(3) For a customer with a methane digester generation system capable of generating  
more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide such functionality, the customer shall pay the cost of  
providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a distributed generation program customer or the distributed  
generation program.  
R 460.1016 Billing and credit for legacy net metering program customers taking service  
under true net metering.  
Rule 116. (1) Legacy net metering program customers with a system capable of  
generating 20 kWac or less qualify for true net metering. For customers qualifying for  
true net metering, the net of the bidirectional flow of kWh across the customer  
interconnection with the electric utility distribution system during the billing period or  
during each time-of-use pricing period within the billing period, including excess  
generation, shall be credited at the full retail rate.  
(2) The credit for excess generation, if any, shall appear on the next bill. Any excess  
credit not used to offset current charges must be carried forward for use in subsequent  
billing periods.  
R 460.1018 Billing and credit for legacy net metering program customers taking service  
under modified net metering.  
Rule 118. (1) Legacy net metering program customers with a system capable of  
generating more than 20 kWac qualify for modified net metering. A negative net metered  
quantity during the billing period or during each time-of-use pricing period within the  
billing period reflects net excess generation for which the customer is entitled to receive  
credit. Standby charges for customers on an energy rate schedule must equal the retail  
52  
distribution charge applied to the imputed customer usage during the billing period. The  
imputed customer usage is calculated as the sum of the metered on-site generation and  
the net of the bidirectional flow of power across the customer interconnection during the  
billing period. The commission shall establish standby charges for customers on demand-  
based rate schedules that provide an equivalent contribution to electric utility system  
costs. Standby charges may not be applied to customers with systems capable of  
generating 150 kWac or less.  
(2) The credit for excess generation must appear on the next bill. Any excess kWh not  
used to offset current charges must be carried forward for use in subsequent billing  
periods.  
(3) A customer qualifying for modified net metering shall not have legacy net metering  
program credits applied to distribution charges.  
(4) The credit per kWh for kWh delivered into the electric utility’s distribution system  
must be either of the following as determined by the commission:  
(a) The monthly average real-time locational marginal price for energy at the  
commercial pricing node within the electric utility’s distribution service territory or for a  
legacy net metering program customer on a time-based rate schedule, the monthly  
average real time locational marginal price for energy at the commercial pricing node  
within the electric utility’s distribution service territory during the time-of-use pricing  
period.  
(b) The electric utility’s or alternative electric supplier’s power supply component,  
excluding transmission charges, of the full retail rate during the billing period or time-of-  
use pricing period.  
R 460.1020 Billing and credit for distributed generation program customers.  
Rule 120. As part of an electric utility’s rate case filed after June 1, 2018, the  
commission shall approve a tariff for a distributed generation program under the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to  
460.1211. A tariff established under this rule does not apply to customers participating in  
a legacy net metering program under the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1001 to 460.1211, before the date that the  
commission establishes a tariff under this rule, who continue to participate in the program  
at their current site or facility.  
Commented [DTEE22]: This should clarify that pursuant  
to 460.1026 legacy net metering customers can only remain  
on legacy net metering for a certain time-period, not  
indefinitely.  
R 460.1022 Renewable energy credits.  
Rule 122. (1) An eligible electric generator shall own any renewable energy credits  
granted for electricity generated under the legacy net metering program and distributed  
generation program.  
(2) An electric utility may purchase or trade renewable energy credits from a legacy net  
metering program or distributed generation program customer if agreed to by the  
customer.  
(3) The commission may develop a program for aggregating renewable energy credits  
from legacy net metering program and distributed generation program customers.  
53  
R 460.1024 Penalties.  
Rule 124. Upon a complaint or on the commission’s own motion, if the commission  
finds after notice and hearing that an electric utility has not complied with a provision or  
order issued under part 5 of the clean and renewable energy and energy waste reduction  
act, 2008 PA 295, MCL 460.1171 to 460.1185, the commission shall order remedies and  
penalties as necessary to make whole a customer or other person who has suffered  
damages as a result of the violation.  
R 460.1026 Legacy net metering grandfathering clause.  
Rule 126. A customer participating in a legacy net metering program approved by the  
commission before the commission establishes the initial distributed generation program  
tariff pursuant to R 460.1020 may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment. “Initial  
enrollment,” as used in this rule, means the date a customer or site initially enrolled in a  
legacy net metering program as described in the electric utility’s tariff. A customer  
participating in a legacy net metering program who increases the nameplate capacity of  
its generation system after the effective date of an electric utility’s distributed generation  
program tariff is no longer eligible to participate in the legacy net metering program.  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own motion, to )  
promulgate rules governing electric interconnection )  
reconciliation of its power supply cost recovery  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
)
)
)
)
Case No. U-20890  
PROOF OF SERVICE  
ESTELLA R. BRANSON states that on November 1, 2021, she served a copy of the DTE  
Electric Company’s Comments in the above captioned matter, via electronic mail, upon the person  
listed on the attached service list.  
ESTELLA R. BRANSON  
MPSC Case No. U-20ꢀꢁꢂ  
SERVICE LIST  
MPSC STAFF  
Steven D. Hughey  
Assistant Attorney General  
Public Service Division  
7109 W. Saginaw Highway, Fl 3  
Lansing, MI 48917  
hugheys@michigan.gov  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own motion,  
to promulgate rules governing electric  
interconnection and distributed generation and  
)
)
)
Case U-20890  
to rescind legacy interconnection and net metering )  
rules.  
__________________________________________)  
)
COMMENTS OF THE MICHIGAN ELECTRIC AND GAS ASSOCIATION  
Pursuant to the Commission’s September 9, 2021 Order establishing a public hearing for  
administrative rules governing Michigan’s electric interconnection and distributed generation  
programs, the Michigan Electric and Gas Association1 submits these comments in response to the  
Commission’s request for public comment regarding the draft rules.  
I.  
Introductory Comments  
MEGA appreciates the opportunity to provide these public comments concerning the  
Interconnection and Distributed Generation Standards Ruleset 2019-3 with the Michigan Public  
Service Commission.  
As the Commission is aware MEGA members have much smaller staffs, programming, and  
smaller information technology budgets to provide interconnection services that are required under  
these draft rules. MEGA requests, where appropriate, adequate flexibility be provided to utilities  
when needed for effective review and management of the complex interconnection process.  
1
The MEGA member companies are investor-owned natural gas and electric utilities with fewer than 500,000  
customers in the state of Michigan, and include: Alpena Power, Citizens Gas Fuel Company, Indiana Michigan  
Power, Michigan Gas Utilities, Northern States Power Company – Wisconsin, SEMCO Energy Gas Company,  
Upper Michigan Energy Resources Corporation, and Upper Peninsula Power Company.  
For example, having additional time for some of the requirements in the application and site  
inspection process would be extremely beneficial to MEGA members. We suggest moving from  
10 business days for applications and inspections to 30 business days, knowing that many  
applications and inspections will be straightforward and without issue. But having adequate time  
to properly schedule the review and inspection would be helpful. As an alternative, the Association  
would request some form of flexibility being written into the rules that allows a utility in limited  
circumstances to extend beyond a deadline to accommodate MEGA members’ smaller staffs and  
resources.  
Many of these rules will require additional investments that are not currently contemplated by  
many MEGA members, whether that’s potential information technology upgrades or additional  
staff due to the requirements of the process laid out in these rules. As an example, some of our  
utilities will have to create new systems to manage this complex process.  
Further, while not the focus of these rules, MEGA remains concerned that this ruleset could  
result in additional cost shifts that may be unintended consequences, exacerbating existing subsidy  
issues between distributed generation/legacy net metering customers, and non-distributed  
generation/legacy net metering customers.  
Finally, MEGA remains concerned that this ruleset is premature, as there will likely need to be  
revisions based on FERC Order 2222 implementation in 2022.  
Again, the Association appreciates the opportunity to provide feedback on these rules. Specific  
comments for each Section of the Rules and the Rule number are listed below.  
II.  
Specific Rule Comments  
Part 1. General Provisions  
Rule 460.1a(cc) Definitions; A-I  
Some MEGA members currently provide consolidated Distribution Impact Study reports  
which include results from Feasibility, Impact, and Facilities studies.  
Separating these studies will align with Regional Transmission Operator (RTO)  
methodology but will significantly increase time and costs to study applications and delay the  
ability of customers to make decisions for distribution interconnections.  
Rule 460.1b(e) – (i) Definitions; A-I  
These prescribed levels are not effective in correlating requirements for review and cost  
causation. Even small facilities less than 20 kW may require detailed study and analysis, and  
systems greater than 1MW may have no impacts to the bulk system at all.  
These Levels are also fundamentally divergent from all other jurisdictions in that they do  
not have an escalation method, i.e., if something fails at level 2 it advances to Level 3.  
Additionally, some MEGA members operate effectively with a 3-level review/study  
process that can treat all applications equally while still being able to provide rapid approval for  
over 90% of all applications.  
Rule 460.1b(j) Definitions; J-Z  
Like the comments on R460.1b(e)-(i), Interconnection Agreements should be more  
agnostic to size and deal more with guidelines for safe operation. A small residential system may  
require special and specific operational requirements that a 1MW+ facility may not simply due to  
the local impacts. Importantly, those impacts can’t be pre-determined simply by size of facility  
with no evaluation of the Area Electric Power System.  
Rule 460.1b(s) Definitions; J-Z  
MEGA suggests that the Nameplate Rating should also include Ah and kWh ratings for  
Energy Storage.  
Rule 460.1b(nn) Definitions; J-Z  
MEGA suggests an alternative, standard term for a combined Feasibility, Impact, and  
Facilities study would be helpful for Distribution Interconnections to avoid duplication of RTO  
and other state’s names of studies.  
Rule 460.904 Informal mediation  
MEGA remains concerned on the aspects of cost for implementing a system for each  
utility that can track necessary information for mediation proceedings. Some of our members  
estimate costs upwards of $3 - $4 million to implement and manage their systems in Michigan.  
Further, additional staff will be necessary to effectively manage the system, answer  
questions.  
Finally, MEGA remains concerned that these rules are premature given the current  
regulatory conditions. For example, these rules may need to be revisited to accommodate  
wholesale processes due to implementation of FERC Order 2222.  
Rule 460.908  
MEGA notes this will have increased costs for its members to implement and manage.  
Part 2. Interconnection Standards  
Rule 460.914 Transition non-study group  
MEGA members are concerned that these rules will result in additional cost and staff,  
assigned to their Michigan operations, to effectively manage. Further, it is unclear how these  
rules would impact existing requests once effective.  
Rule 460.916 Legacy applications  
MEGA members do not always have Construction Agreements typically that delve into  
the DER commissioning aspect of the construction, just the building of facilities. Post  
Commissioning requirements are typically not spelled out in this agreement.  
Rule 460.918 Transition batch study process  
This rule does not contemplate nor effectively manage when all the applicants enter on  
the same day. For example, in PJM’s similar queue, many applicants enter on the last day,  
preventing the utility from doing any pre-model work on the project. To that end, with the  
timeline requirements listed below, there is concern that feasibility study results can be delivered  
in 1 year for everyone since the whole group must be ready before moving to the next step.  
Further it is not clear if this process will be separate from a FERC Order 2222 process.  
Rule 460.918(8)(b) Transition batch study process  
With no definition for ‘unreasonably delaying,’ it is unclear who makes the determination  
as to what constitutes the delay, or who arbitrates the issue.  
Rule 460.918(10) Transition batch study process  
MEGA asks whether this means that the studies must be delivered in the order that they  
are applied? Or that the EDU cannot get out of “order” of when the batch is received? Or does  
this mean that all studies must be delivered at one time 6 months after the date of the batch  
closure? This would include un-answered sections of the study templates if the developer hasn’t  
answered utility questions in full.  
MEGA is also concerned that this will create issues when developers compete over  
access to constrained systems. If two developers propose 1MW+ systems on the same circuit  
they will almost certainly be electrically coincident, and if one developer applies at the start of  
the queue and someone puts their application in at the end it could be 6 months apart, and  
utilities would be required to treat these applications as if they came in simultaneously and as if  
they were both going to be online.  
Rule 460.918(15) Transition batch study process  
There is concern here that this is not feasible because the reduction will have to be re-  
studied and re-modeled in the planner’s contingency process.  
Rule 460.922 Online applications and electronic submission  
Many MEGA members will require updates to their systems to accommodate the  
electronic application and submissions, including for meeting the extensive daily, monthly, and  
batching requirements.  
Rule 460.924 Communications  
MEGA members are concerned there is a lack of clarity in this section. Specifically, from  
a resource management standpoint, additional staff or staff time will need to provide “reasonable  
assistance” to applicants or interconnection customers.  
It is not clear how the application agents will be registered and identified to the utility.  
While the Rule contemplates the designation, it does not ascribe a process or the information  
necessary to effectuate that.  
Finally, the indemnity suggested under (3) for assistance provided by the interconnection  
coordinator(s) will require some form of security deposit because each application will require  
some form of monitoring.  
Rules 460.926 and 460.928 Initial fees and Fee and fee cap modifications  
MEGA appreciates the recognition there are costs involved for the determination of  
interconnection, however, some of the cost items, particularly on the pre-application fee, are  
likely insufficient to cover costs to review applications. Further, it is not clear who is collecting  
the fees. Fees should not be a “one-size-fits-all” approach when the size of applications will vary  
greatly.  
Rule 460.934 Site control  
MEGA is seeking clarity that if the party interconnecting the DER is not the business or  
homeowner, would the interconnecting party need to register so they can operate on behalf of the  
business or homeowner?  
Rule 460.936 Interconnection applications  
MEGA recommends that proof of Insurance should be required for customers with  
existing service at all levels. Further, all electrical diagrams should be stamped by a professional  
engineer regardless of size or level.  
MEGA also suggests that when applications are rejected for failure to be complete and  
conforming, this reason for rejection should be identifiable and communicated to the customer  
by the interconnecting party.  
Rule 460.938 Public interconnection list  
MEGA appreciates the Commission’s effort to balance the interests of transparency, but  
there should be an avenue to protect sensitive information in the process.  
Rule 460.944 Fast track applicability  
MEGA recommends that utilities should have the option to elevate level 1 & 2  
applications to Fast Track if simplified fails, or alternatively to move something in the Study  
Track down. Adding this caveat would allow utilities to implement the process more effectively  
with existing processes.  
Rule 460.946 Fast track; initial review  
Members remains concerned that this section may not properly align with the batch study  
concept.  
Further, there is concern that it will be difficult for smaller utilities to maintain a batching  
process and verify fault current points every 20 days.  
Rule 460.964 Interconnection agreement  
MEGA argues that modifying Interconnection Agreements to accommodate customer  
specific circumstances can occur with or without physical construction, and that dedicated staff  
will be needed to draft, review, and approve such modifications. Therefore, the rule should be  
adjusted to stipulate that the electric utility will provide a DRAFT of Interconnection Agreement  
language within 20 business days.  
MEGA also remains concerned that the timelines here are very aggressive for smaller  
utilities, who have limited resources, to implement. Having either modified timelines for smaller  
utilities or an avenue to request additional time from the Commission would be helpful in the  
limited cases where an agreement takes longer to implement for various policy, legal, and  
resource reasons.  
Rule 460.976 Post commissioning remedy  
MEGA expresses concern that this Rule may not confer appropriate authority to enter the  
premises of the interconnection customer to determine compliance.  
Rule 460.984 Modifications to the DER  
MEGA remains concerned that there are no penalties for the applicants should they  
choose to modify and inform/request modification after the fact.  
R 460.986 Insurance.  
MEGA is concerned the rules do not define what types of liability insurance are required.  
As the rules are currently written, exclusions could be added to the policy that defeat the purpose  
of the liability insurance. For example, MEGA members have seen exclusions for stray voltage  
claims, claims related to subsidence, any occurrence that happens on or after the first day of  
commercial operation, electromagnetic frequency in other states.  
MEGA recommends that liability insurance include insuring against all claims for  
property damage and for personal injury or death arising out of, resulting from, or in any manner  
connected with the installation, operation, and maintenance of the DG facility.  
Additionally, it should be made clear the utility has the option to review insurance  
policies at any time and take action against deficient policies (reject interconnection or  
disconnect).  
MEGA recommends adding language to the section that the public utility can review the  
entire liability insurance of the DG facility at any time and has the ability to reject  
interconnection or disconnect interconnection if the insurance is inadequate.  
III.  
Conclusion  
As shown by these comments, the MEGA utilities are concerned that the proposed rules  
governing electric interconnection and distributed generation programs will require additional  
staffing to meet strict timelines, will require significant investment in IT and programing costs to  
implement rules that applicable to their small customer base. The MEGA utilities have and will  
continue to address interconnection and DG programs applications on a successful basis without  
the need for burdensome regulatory oversight/rules.  
Sincerely,  
Dated: November 1, 2021  
Daniel Dundas  
President  
Michigan Electric and Gas Association  
DTE Electric Company  
One Energy Plaza, 1635 WCB  
Detroit, MI 48226-1279  
Jon P. Christinidis  
(313) 235-7706  
jon.christinidis@dteenergy.com  
June 27, 2022  
Ms. Lisa Felice  
Executive Secretary  
Michigan Public Service Commission  
7109 West Saginaw Highway  
Lansing, MI 48917  
RE: In the matter, on the Commission’s own motion, to promulgate rules governing  
electric interconnection and distributed generation, and rescind legacy  
interconnection and net metering rules.  
MPSC Case No. U-20890  
Dear Ms. Felice:  
Attached for electronic filing in the above-captioned matter is DTE Electric Company’s  
Comments pursuant to the Michigan Public Service Commission’s May 12, 2022 and May 26, 2022  
Orders in Case No. U-20890.  
Very truly yours,  
Jon P. Christinidis  
JPC/erb  
Attachments  
cc:  
Service List  
S T A T E O F M I C H I G A N  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
* * * * *  
In the matter, on the Commission’s own motion, to )  
promulgate rules governing electric interconnection )  
reconciliation of its power supply cost recovery  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
)
)
)
)
Case No. U-20890  
COMMENTS OF DTE ELECTRIC COMPANY  
Introduction  
On May 12, 2022, the Michigan Public Service Commission (“Commission” or “MPSC”)  
issued an Order in this proceeding in response to a Joint Petition of DTE Electric Company and  
Consumers Energy Company. In the Order the Commission granted the Joint Petition and  
indicated that the Commission would provide a second opportunity for public comment. (Case No.  
U-20890 Order dated May 12, 2022, p. 10) On May 26, 2022 the Commission issued an additional  
Order issuing (as Exhibit B) forty-nine (49) pages of proposed interconnection rules, establishing  
a public hearing date of June 22, 2022 and allowing any person to file “comments, suggestions,  
data, views, questions, argument, and modifications concerning the issues” by 5:00 pm June 27,  
2022. (Case No. U-20890 Order dated May 26, 2022, p. 4)  
The Company appreciates the additional opportunity to provide comments regarding the  
proposed Interconnection and Distributed Generation Standards which the Commission describes  
as the “MIXDG rules” (hereinafter the “newly proposed rules”) and proposed recission of the  
Electric Interconnection and Net Metering Standards (hereinafter the “existing rules”). In light of  
the limited time frame to provide comments and the voluminous and complex nature of the newly  
proposed rules, the Company’s written comments focus on conceptual concerns and include an  
1
attached redline markup (with margin comments) of the newly proposed rules (attached as Exhibit  
A) designed to, in part and among other things, address those matters and various other technical  
concerns. The Company’s prior comments and suggestions regarding interconnection rulemaking  
in this and other dockets are incorporated by reference as if fully restated herein. Failure to address  
each and every provision of the newly proposed rules should not necessarily be construed as  
agreement by the Company.1  
DTE Electric is fully committed to providing a positive customer experience for all  
customers. The Company serves over 2 million customers in Southeast Michigan across a service  
territory that covers over 7,600 square miles, with a distribution system that includes over 31,000  
miles of overhead lines, and over 16,000 miles of underground lines. The Company recognizes  
that our customers share our enthusiasm for clean energy and know that many want to be more  
involved in their energy supply, thus we strive to accommodate interconnection requests as quickly  
and safely as possible.  
However, it bears emphasis that virtually the entire electric utility industry in the state has  
expressed serious concerns regarding the newly proposed rules, including with respect to safety,  
reliability, and proper payment for the costs associated with interconnection to electric utility  
distribution systems. While some portions of the newly proposed rules are helpful in, for example,  
requiring interconnection applicants to maintain reasonable progress in pursuing their project, the  
newly proposed rules also impose unnecessarily complex and prescriptive processes affecting  
safety, reliability, proper cost recovery, and a variety of other issues likely to result in confusion,  
errors, misunderstandings and disagreement.  
1 DTE Electric reserves all rights to further address interconnection issues in this and/or other dockets as well as in  
appeals.  
2
 
The Company believes that this complexity is unnecessary and the rationale for  
promulgating new rules is not well explained or supported by meaningful facts or data. The vast  
majority of interconnections to the DTE Electric distribution system are accomplished without  
significant issue. In fact, the Company has successfully interconnected over 6,000 small generators  
to its distribution system since the enactment of 2008 PA 295.  
Applying the Proper Scope of Rulemaking is Critical  
The Administrative Procedures Act provides that:  
“A rule must not exceed the rulemaking delegation contained in the statute  
authorizing the rulemaking.” (MCL 24.232(7))  
Because the Company and others have previously explained the various legal (and technical)  
concerns in this docket, rather than completely reiterate them, the Company highlights some of the  
more critical concerns and incorporates the remainder by reference as if fully restated herein. (See,  
by way of example and not limitation, the following pleadings filed in this docket: DTE Electric  
Company’s Comments dated November 1, 2021, DTE Electric Company’s and Consumers Energy  
Company’s Joint Petition for Rehearing dated April 14, 2022, Answer of Indiana Michigan Power  
Company to Joint Petition for Rehearing dated May 4, 2022, Answer of the Michigan Electric and  
Gas Association to Joint Petition for Rehearing dated May 4, 2022, Answer of the Michigan  
Electric Cooperative Association to Joint Petition for Rehearing dated May 4, 2022) The only  
specific grants of authority identified by the Commission with respect to the newly proposed rules  
include MCL 460.10e (addressing generally “merchant plants”)2 and MCL 460.1173 (addressing  
2
Most relevant to the instant rulemaking, MCL 460.10e provides: “The commission shall  
establish standards for the interconnection of merchant plants with the transmission and  
distribution systems of electric utilities. The standards shall not require an electric utility to  
interconnect with generating facilities with a capacity of less than 100 kilowatts for parallel  
operations. The standards shall be consistent with generally accepted industry practices and  
guidelines and shall be established to ensure the reliability of electric service and the safety of  
customers, utility employees, and the general public. The merchant plant will be responsible for  
3
 
generally “distributed generation programs”)3. MCL 460.10e was enacted more than 20 years ago.  
Much of what is now MCL 460.1173 has been in place since 2008, although modified in some  
respects in 2016.  
In Consumers Power Co v Public Service Comm, 460 Mich 148, 155-56; 596 NW2d 126  
(1999), our Supreme Court explained:  
“The Public Service Commission has no common-law powers. It possesses only  
that authority granted by the Legislature. Union Carbide v Public Service Comm,  
431 Mich 135, at 146, 428 N.W.2d 322. Moreover, this Court strictly construes the  
statutes which confer power on the PSC. As this Court explained in Union Carbide,  
supra at 151, 428 N.W.2d 322, quoting Mason Co. Civic Research Council v Mason  
Co, 343 Mich 313, 326–327, 72 NW2d 292 (1955):  
“The power and authority to be exercised by boards or commissions must be  
conferred by clear and unmistakable language, since a doubtful power does not  
exist.”  
Noncompliance with the APA is reversible error. In re Public Service Commission Guidelines  
for Transactions Between Affiliates, 252 Mich App 254, 267; 652 NW2d 1 (2002) provided:  
“Invoking the public interest and the need for policy that is responsive to a  
changing industry, the PSC eschewed the procedural mandates of the APA in favor  
of its own course of action . . . While we do not doubt the PSC’s legitimate concerns  
. . . the process utilized by the PSC constituted a rather heavy-handed rebuke of  
all costs associated with the interconnection unless the commission has otherwise allocated the  
costs and provided for cost recovery.” (MCL 460.10e(3); emphasis added)  
3 As it relates specifically to rulemaking, MCL 460.1173 provides: “The commission shall establish  
a distributed generation program by order issued not later than 90 days after the effective date of  
the 2016 act that amended this section. The commission may promulgate rules the commission  
considers necessary to implement this program. Any rules adopted regarding time limits for  
approval of parallel operation shall recognize reliability and safety complications including those  
arising from equipment saturation, use of multiple technologies, and proximity to synchronous  
motor loads…If necessary to promote reliability or safety, the commission may promulgate rules  
that require the use of inverters that perform specific automated grid-balancing functions to  
integrate distributed generation onto the electric grid. (MCL 460.1173(1)(5)(b); emphasis added)  
4
 
established APA procedures, and, accordingly, we are compelled to invalidate that  
process” (252 Mich App at 267-68).4  
The Commission cannot re-write the Legislature’s language to include new or different provisions.  
Hanson v Mecosta Co Rd Comm, 465 Mich 492, 501-503; 638 NW2d 396 (2002). If a Commission  
order conflicts with a statute, the order is void. Manufacturers Nat’l Bank v DNR, 420 Mich 128,  
146; 362 NW2d 572 (1984). Our Supreme Court recently reaffirmed that “agencies cannot  
exercise legislative power by creating law or changing the laws enacted by the Legislature.” In re  
Complaint of Rovas Against SBC Michigan, 482 Mich 90, 98; 754 NW2d 259 (2008) (Emphasis  
added).  
In light of the thousands of successful interconnections to DTE Electric’s and other  
Michigan electric utilities’ distribution systems, relatively static law, and limited “clear and  
unmistakable” direction to promulgate rules it is likely that the newly proposed rules have  
exceeded the Commission’s legislative directives.  
Another example includes application of the newly proposed rules to limit electric utilities’  
management authority and use of their own property for their own business purposes – including  
electric utility-owned generation and distribution systems. Newly proposed rules R 460.901(a)(h)  
and (vv) as well as R 460.936(8) and (9) are implicated and all restrictions set forth in those  
4 Allowing third parties to control electric utility property (its distribution system) and undercharging generators for  
access to and use of that property presents an additional, constitutional problem because the Company’s private  
property is essentially being taken by another private entity. Mich Const 1963, art 10, §2 provides that: “Private  
property shall not be taken for public use without just compensation therefor being first made or secured in a manner  
prescribed by law.” The Fifth Amendment of the United States Constitution similarly provides that “the government  
may not take private property unless it is done for a public use and with just compensation.”4 Taking electric utilities’  
private property and giving it to other private entities (merchant plants) violates the “public use” requirement. The  
Commission’s authority does not include the ability to take property for the private use of another.  
5
 
provisions (or any other) purporting to restrict an electric utility’s utilization of its own property  
must be removed.5  
The bounds of regulation are aptly described in Union Carbide v. Public Service Comm.,  
431 Mich 135; 428 NW2d 322 (1988)  
“The power to fix and regulate rates, however, does not carry with it, either  
explicitly or by necessary implication, the power to make management decisions.  
‘It must never be forgotten that while the State may regulate with a view to  
enforcing reasonable rates, it is not the owner of the property of public utility  
companies and is not clothed with the general power of management incident to  
ownership.’ [citations omitted]”.  
It is clear that the Commission is principally an economic regulator and not the operator of electric  
utility facilities. There is no relevant administrative rulemaking authority to the contrary. Ford  
Motor Co. v. Public Service Comm, 221 Mich App 370, 385, 387-388; 562 NW2d 224 (1997)  
(“The PSC here exceeded its ratemaking authority by, in effect, requiring Detroit Edison’s  
management to adopt the DSM program the PSC thought best.”); Attorney General v. Public  
5 The referenced provisions relevantly provide:  
(h) “Applicant” means the person or entity submitting an interconnection application, a legacy net  
metering program application, or a distributed generation program application. An applicant is  
not required to be an existing customer of an electric utility. An electric utility is considered an  
applicant when it submits an interconnection application for a DER that is not a temporary DER.  
(R 460.901(a)(h); emphasis added)  
“(vv) ‘Interconnection customer’ means the person or entity, which may include the electric utility,  
responsible for ensuring a DER is operated and maintained in compliance with all local, state, and  
federal laws, as well as with all rules, standards, and interconnection procedures.” (R  
460.901(a)(vv); emphasis added)  
“ (8) An electric utility shall comply with part 2 of these rules, R 460.911 to R 460.992, and its  
interconnection procedures when interconnecting DERs that it owns and operates onto its  
distribution system, with the exception of temporary DERs.” (R 460.901(8); emphasis added)  
“(9) An electric utility shall use the same process when processing and studying interconnection  
applications from all applicants, whether the DER is owned or operated by the electric utility, its  
subsidiaries or affiliates, or others, with the exception of temporary DERs.” (R 460.936(9);  
emphasis added)  
6
 
Service Comm, 269 Mich App 473; 713 NW2d 290 (2005) (MPSC exceeded its authority when it  
ordered the utility to expand its “green power” program and required customers who did not  
participate in the program to subsidize its costs). Consumers Power Co, Public Service Comm,  
189 Mich App 151, 180; 472 NW2d 77 (1991) (“To the extent that the PSC actually ordered  
Consumers to enter, or not enter, into any particular contract, it exceeded its authority”).6  
The Commission is an “administrative body created by statute and the warrant for the  
exercise of all its power and authority must be found in statutory enactments.” Union Carbide v  
Public Service Comm, 431 Mich 135, 146; 428 NW2d 322 (1988); Sparta Foundry Co v Public  
Utilities Comm, 275 Mich 562, 564; 267 NW 736 (1936). The Commission’s authority must be  
conferred by clear and unmistakable statutory language, and a doubtful power does not exist.  
Mason Co Civil Research Council v Mason Co, 343 Mich 313, 326-27; 72 NW2d 292 (1955). The  
Commission cannot expand its jurisdiction through its own acts or assumption of authority. Ram  
Broadcasting v Public Service Comm, 113 Mich App 79, 92; 317 NW2d 295 (1982). The  
Commission cannot re-write the Legislature’s language to include new or different provisions.  
Hanson v Mecosta Co Rd Comm, 465 Mich 492, 501-503; 638 NW2d 396 (2002). If a Commission  
order conflicts with a statute, the order is void. Manufacturers Nat’l Bank v DNR, 420 Mich 128,  
146; 362 NW2d 572 (1984)  
Preserving Proper Consideration of Safety and Reliability by Electric Utilities is  
Critical  
The law is clear that the safety and reliability of electric utility distribution systems is to  
remain paramount as distributed generation becomes more prevalent. State statutory provisions  
emphasize the point multiple times:  
6
Consistent with Consumers, neither is there any apparent authority to require “standard level 1, 2, and 3  
interconnection agreements”. (See, for example R 460.901b(mm) and R 460.964)  
7
 
(1) The commission shall establish a distributed generation program by order issued not  
later than 90 days after the effective date of the 2016 act that amended this section. The  
commission may promulgate rules the commission considers necessary to implement this  
program. Any rules adopted regarding time limits for approval of parallel operation shall  
recognize reliability and safety complications including those arising from equipment  
saturation, use of multiple technologies, and proximity to synchronous motor loads…  
(6) The distributed generation program created under subsection (1) shall include all of  
the following:  
(a) Statewide uniform interconnection requirements for all eligible electric generators. The  
interconnection requirements shall be designed to protect electric utility workers and  
equipment and the general public.  
(b) . . . If necessary, to promote reliability or safety, the commission may promulgate  
rules that require the use of inverters that perform specific automated grid-balancing  
functions to integrate distributed generation onto the electric grid. Inverters that  
interconnect distributed generation resources may be owned and operated by electric  
utilities. Both of the following must be completed before the equipment is operated in  
parallel with the distribution system of the utility:  
(i) Utility testing and approval of interconnection, including all metering.  
(ii) Execution of a parallel operating agreement. (Emphasis added). (MCL 460.1173;  
emphasis added)  
and  
The commission shall establish standards for the interconnection of merchant plants with  
the transmission and distribution systems of electric utilities. The standards shall not  
require an electric utility to interconnect with generating facilities with a capacity of less  
than 100 kilowatts for parallel operations. The standards shall be consistent with generally  
accepted industry practices and guidelines and shall be established to ensure the  
reliability of electric service and the safety of customers, utility employees, and the  
general public. The merchant plant will be responsible for all costs associated with the  
interconnection unless the commission has otherwise allocated the costs and provided for  
cost recovery. (MCL 460.10e(3); emphasis added).  
The electric grid, and the customers who depend on it, are very sensitive to even small  
changes in system operation. Voltage levels and other power quality characteristics need to be  
maintained within a narrow band at all times. It is critical that the reverse power flow from  
interconnected generation exports to the grid be maintained within the tight limits of the  
distribution equipment on the grid side of the interconnection. Any reverse power flow above  
8
prescribed limits is called an “inadvertent export.” It is also critical that any slight disturbances  
from potential mis-operation of distributed generation-related equipment, that could cause a higher  
than allowed reverse power flow, occur for only a tiny amount of time, which under the existing  
rules was milliseconds. The newly proposed rules allow for potentially repeated inadvertent  
reverse power flow for up to 32 seconds. With respect to grid equipment stability, 32 seconds is a  
very long time, and these power disturbances could potentially cause significant damage to grid or  
customer equipment such as transformers or appliances, or even cause equipment fires or arc  
flashes, any of which might pose safety risks to electric utility employees or the public. The  
inadvertent export definitions included in the revised rules are inconsistent with industry standards  
and practices and pose significant challenges to operating the grid safely and reliably. Accordingly,  
DTE requests that these definitions be removed from the rules as set forth in Exhibit A.  
In order to maintain safe conditions, electric utilities as the owners and operators of their  
respective distribution grids, are required to properly study and assess the potential impacts of any  
customer attachment or changes to their distribution grids. These assessments have historically  
been performed using industry accepted screening criteria applied to each proposed  
interconnection. It has been recognized that the existing interconnection rules have allowed for  
safe and reliable interconnection and operation of distribution systems in Michigan.7  
7 See, for example, “Q. Have there been any safety or reliability issues related to the DG Program? A. No, not to my  
knowledge. In testimony filed in this case, the Company does not raise any concerns regarding reliability of the  
distribution system related to solar DG systems. This is likely because the interconnection process governs the  
interconnection of any electric generator to the distribution grid and requires each utility to carefully assess the safety  
and integrity of the grid before approving an application.” (Case No. U-20836 Prefiled Direct Testimony of Dr. Laura  
S. Sherman p. 22 on behalf of Michigan EIBC/IEI)  
9
 
Distributed energy resources and generation8 can introduce changes to power flowing  
either to or from the grid and the interconnection process must permit electric utilities to carefully  
assess the safety and integrity of the impacts of the specific proposed interconnection before  
approving an application. The newly proposed rules unreasonably and unnecessarily constrain  
electric utilities’ ability to perform a complete technical assessment by limiting the screening  
criteria that electric utilities can apply. Reducing the screening criteria may in some cases lead to  
distributed energy resources and generation installations that cannot be reliably and safely  
supported by the distribution grid, which in turn could result in potentially dangerous conditions.  
Accordingly, DTE Electric requests that the newly proposed rules allow for the incorporation of  
additional screening criteria in order to adequately assess safety and reliability for each individual  
interconnection situation.  
Proper Cost Allocation and Recovery is Critical  
A third concern involves the newly proposed rules determination to utilize “fee caps” for  
actions and studies required by the rules (See, for example, R 460.920, R460.926, and R 460.928)  
as well as requirements to disclose through, inter alia a “Pre-application report”, various  
proprietary and commercially valuable electric utility system information to 3rd parties for only a  
nominal fee ($300) and despite the possibility it could be sensitive Critical Electric Infrastructure  
8
It is further relevant that distributed generation is comprised of an increasing variety of equipment and operators  
with different operational characteristics and priorities – substantially increasing the number of different  
circumstances to which electric utilities must respond. Newly proposed rule R 460.920 would permit innumerable  
other persons with varying degrees of understanding or skill to potentially change electric utility interconnection  
procedures based on that person’s self-interest and without knowledge of, or regard for, the safety and reliability of  
electric utilities’ electric systems. Furthermore, electric utilities control over its own property is a crucial element of  
the Company’s property rights. [See generally, Loretto v Teleprompter Manhattan CATV Corp, 458 US 419, 435-36;  
102 S Ct 3164; 73 L Ed 2d (1982) (holding that a New York law requiring a landlord to permit a cable television  
company to install cable facilities on the landlord’s property constituted a taking of the landlord’s property); Kaiser  
Aetna v United States, 444 US 164, 176; 100 S Ct 383; 62 L Ed 332 (1979) (a requirement that subjected a formerly  
private pond to public access took away the landlord’s right to exclude, one of the most essential sticks in the bundle  
of rights that are commonly characterized as property.”)]  
10  
 
Information (CEII) (See, for example, R460.926 and R 460.932). The Company cannot be required  
to provide services without full compensation nor relinquish its property rights in proprietary  
business information (including but not limited to electrical system information) without just  
compensation. At a minimum, these “fee caps” and mandated proprietary and commercially  
valuable electric utility information disclosures risk violation of the requirement that “[t]he  
merchant plant will be responsible for all costs associated with the interconnection unless the  
commission has otherwise allocated the costs and provided for cost recovery.” (MCL 460.10e(3))  
Electric utilities like DTE Electric have constitutional protections against “takings” and  
confiscatory rates under the Fifth Amendment to the US Constitution, which is applicable to the  
states through the Fourteenth Amendment. Similarly, the Michigan Constitution of 1963, art 10, §  
2 provides in part, “Private property shall not be taken for public use without just compensation  
therefore being first made or secured in a manner prescribed by law.” These constitutional  
protections have been recognized and applied to public utility rates in well-established case law.  
See generally, Missouri ex rel Southwestern Bell Telephone Co v Public Service Comm of  
Missouri, 262 US 276; 43 S Ct 544; 67 L Ed 981 (1923); Federal Power Comm v Natural Gas  
Pipeline, 315 US 575; 62 S Ct 736; 86 L Ed 1037 (1942); Duquesne Light Co v Barasch, 488 US  
299; 109 S Ct 609; 102 L Ed 2d 646 (1989). See also, Northern Michigan Water Co v Public  
Service Comm, 381 Mich 340; 161 NW2d 584 (1968); Consumers Power Co v Public Service  
Comm, 415 Mich 134; 327 NW2d 875 (1982); ABATE v Public Service Comm, 430 Mich 33;  
420 NW2d 81 (1988). Such requirements must be removed from the newly proposed rules.  
Proper Utilization of Well Understood Commission Rules and APA Procedures is  
Critical  
An overarching Due Process concern involves the complex dispute resolution procedures  
set forth in the newly proposed rules which provide for “Informal Mediation”, “Formal  
11  
Mediation”, “Contested Cases”, and “Complaints.” (See generally R 460.904 and R 460.906)  
Informal Mediation places Commission Staff in what appears to be the role of mediator. (See R  
460.904(3)) Subsequent to any Informal Mediation, Formal Mediation appears to be required.9  
Formal Mediation requires multiple submissions to the Commission and involves an  
Administrative Law Judge (ALJ) as mediator with “assistance from commission staff.” (R  
460.906(1)(a)-(f)) And the newly proposed rules also appear to preserve the potential filing of a  
“contested case proceeding” pursuant to the Rules of Practice and Procedure Before the  
Commission (See generally, R 792.10401 et. seq.; See specific reference in newly proposed rule  
R 460.906(1)(f) to R 792.10415 “General Provisions” addressing a “contested case proceeding”).  
The newly proposed rules, however, also appear to preserve the right to file a complaint (addressed  
generally in R 792.10439 – R792.10446 of the Rules of Practice and Procedure Before the  
Commission). It is also worthy of note that Staff has historically participated in contested cases  
and complaints10 as a party11, so it is unclear under the newly proposed rules how Staff would  
reconcile its roles as mediator, provider of “assistance” to an ALJ mediator, and potential  
contested case party. Thus, the newly proposed rules contemplate the potential for multiple forms  
of addressing disputes that are not mutually exclusive, lack clear adherence to the Administrative  
Procedures Act MCL 24.201 et. seq. and the existing Rules of Practice and Procedure Before the  
Commission R 792.10401 et. seq., and otherwise do not clearly ensure adequate Due Process.  
9 “(1) If the parties have been unable to resolve a dispute through the informal mediation process under R 460.904,  
the parties shall then attempt to resolve the dispute in the following manner:…” (R 460.906(1))(emphasis added)  
10 A “complaint” is also a “contested case” but a “contested case” may not also be a “complaint.”  
11  
It is noteworthy that the Rules of Practice and Procedure Before the Commission R 792.10402(f) identifies  
Commission Staff as a “Party” “…in any proceeding in which the staff participates.” It is therefore unclear how Staff  
can be expected to engage in the roles set forth in the newly proposed rules consistent with Due Process, the APA, or  
the existing Rules of Practice and Procedure Before the Commission.  
12  
     
DTE Electric and others have Due Process rights under the Fourteenth Amendment to the  
United States Constitution. Michigan’s Constitution similarly provides DTE Electric with the right  
to fair and just treatment in MPSC proceedings: “No person shall be compelled in any criminal  
case to be a witness against himself, nor be deprived of life, liberty or property, without due  
process of law. The right of all individuals, firms, corporations and voluntary associations to fair  
and just treatment in the course of legislative and executive investigations and hearings shall not  
be infringed.” Michigan Const 1963, art 1, § 17. In addition, In re Public Service Commission  
Guidelines for Transactions Between Affiliates, 252 Mich App 254, 267; 652 NW2d 1 (2002)  
confirms that adherence to the Administrative Procedures Act is critical:  
“Invoking the public interest and the need for policy that is responsive to a  
changing industry, the PSC eschewed the procedural mandates of the APA in favor  
of its own course of action . . . While we do not doubt the PSC’s legitimate concerns  
. . . the process utilized by the PSC constituted a rather heavy-handed rebuke of  
established APA procedures, and, accordingly, we are compelled to invalidate that  
process” (252 Mich App at 267-68).  
Many Additional Modifications to the Newly Proposed Rules are Required  
As explained generally above as well as in prior pleadings submitted by the Company and  
other state electric utilities in this and other dockets, there are several significant overarching  
considerations (in addition to more specific concerns found throughout the details of the 49-pages  
of newly proposed rules) that must be addressed and remediated prior to formal adoption of a final  
rule on these topics. Attached as Exhibit A is a redlined markup that addresses the concerns  
described herein (as well as other more technical concerns) that must be addressed to begin to align  
the newly proposed rules with existing law, procedure, and good utility practice.  
Respectfully Submitted,  
DTE ELECTRIC COMPANY  
Dated: June 27, 2022  
13  
Exhibit A  
DEPARTMENT OF LICENSING AND REGULATORY AFFAIRS  
PUBLIC SERVICE COMMISSION  
Commented [A1]: Nothing in this set of rules allows  
for the review of transient issues, like flicker, harmonics,  
transient over voltage, power fluctuations, or other  
dynamic events as well as destruction of customer  
equipment, ferro-resonance in transformers, VFDs and  
potential fires. Finally, transients can lead to mass  
inverter tripping and Bulk Electrical System impacts  
which have been observed in other states and  
countries.  
INTERCONNECTION AND DISTRIBUTED GENERATION STANDARDS  
Filed with the secretary of state on  
These rules take effect immediately upon filing with the secretary of state unless adopted  
under section 33, 44, or 45a(9) of the administrative procedures act of 1969, 1969 PA  
306, MCL 24.233, 24.244, or 24.245a. Rules adopted under these sections become  
effective 7 days after filing with the secretary of state.  
(By authority conferred on the public service commission by section 7 of 1909 PA 106,  
MCL 460.557, section 5 of 1919 PA 419, MCL 460.55, sections 4, 6, and 10e of 1939 PA  
3, MCL 460.4, 460.6, and 460.10e, and section 173 of the clean and renewable energy  
and energy waste reduction act, 2008 PA 295, MCL 460.1173)  
R 460.901a, R 460.901b, R 460.902, R 460.904, R 460.906, R 460.908, R 460.910, R  
460.911, R 460.920, R 460.922, R 460.924, R 460.926, R 460.928, R 460.930, R  
460.932, R 460.934, R 460.936, R 460.938, R 460.940, R 460.942, R 460.944, R  
460.946, R 460.948, R 460.950, R 460.952, R 460.954, R 460.956, R 460.958, R  
460.960, R 460.962, R 460.964, R 460.966, R 460.968, R 460.970, R 460.974, R  
460.976, R 460.978, R 460.980, R 460.982, R 460.984, R 460.986, R 460.988, R  
460.990, R 460.991, R 460.992, R 460.1001, R 460.1004, R 460.1006, R 460.1008, R  
460.1010, R 460.1012, R 460.1014, R 460.1016, R 460.1018, R 460.1020, R 460.1022, R  
460.1024, and R 460.1026 are added to the Michigan Administrative Code, as follows:  
PART 1. GENERAL PROVISIONS  
R 460.901a Definitions; A-I.  
Rule 1a. As used in these rules:  
(a) “AC” means alternating current at 60 Hertz.  
(b) “Affected system” means another electric utility’s distribution system, a municipal  
electric utility’s distribution system, the transmission system, or transmission system-  
connected generation which may be affected by the proposed interconnection.  
(c) “Affiliate” means that term as defined in R 460.10102(1)(a).  
(d) “Aggregate capacity” or “aggregate generation capacity” means the aggregated  
ongoing operating capacities of all DERs across multiple points of common coupling,  
within a defined portion of the distribution system.  
Commented [A2]: Concern: Definition duplicative and  
defined in such a way to have no useful meaning or bounds.  
(e) “Alternative electric supplier” means that term as defined in section 10g of 1939 PA  
3, MCL 460.10g.  
Solution: Existing nameplate capacity and export capacity  
definitions are sufficient to identify what value is intended.  
April 7, 2022  
Exhibit A  
2
(f) “Alternative electric supplier distributed generation program plan” means a  
document supplied by an alternative electric supplier that provides detailed information to  
an applicant about the alternative electric supplier's distributed generation program.  
(g) “Alternative electric supplier legacy net metering program plan” means a document  
supplied by an alternative electric supplier that provides detailed information to an  
applicant about the alternative electric supplier's legacy net metering program.  
(h) “Applicant” means the person or entity, other than an electric utility, submitting an  
interconnection application, a legacy net metering program application, or a distributed  
generation program application. An applicant is not required to be an existing customer  
of an electric utility. An electric utility is considered an applicant when it submits an  
interconnection application for a DER that is not a temporary DER.  
Commented [A3]: Concern: the restrictions on electric  
utilities are overly broad and conflicts with utilities  
responsibility to maintain the grid, safety, and reliability.  
Example: Substation backup batteries to provide energy  
storage are connected to the distribution system and are not  
temporary. As written would these be subject to  
interconnection applications? Would NWA projects need  
interconnection applications? Is the commission expecting  
NWA’s to be solely screened/studied based on their potential  
operating capability, or based on their specific function as a  
distribution asset?  
(i) “Application” means an interconnection application, a legacy net metering program  
application, or a distributed generation program application.  
(j) “Area network” means a location on the distribution system served by multiple  
transformers interconnected in an electrical network circuit.  
(k) “Business day” means Monday through Friday, starting at 12:00:00 a.m. and ending  
at 11:59:59 p.m., excluding electric utility holidays and any day in which electric service  
is interrupted for 10% or more of an electric utility’s customers. A list of electric utility  
holidays shall be provided in the electric utility’s interconnection procedures.  
(l) “Calendar day” means every day including Saturdays, Sundays, and holidays.  
(m) “Certified” means an inverter-based system hardware has met published  
performance requirements acceptable safety and reliability standards by a nationally  
recognized testing laboratory in conformance with IEEE 1547.1-2020 and the UL 1741  
September 28, 2021 edition except that prior to January 1, 2023, inverter-based systems  
which conform to the UL 1741SA September 7, 2016 edition are acceptable.  
(n) “Commission” means the Michigan public service commission.  
(o) “Commissioning test” means the test and verification procedure that is performed  
on a device or combination of devices forming a system to confirm that the device or  
system, as designed, delivered, and installed, meets the interconnection and  
interoperability requirements of IEEE 1547-2018 and IEEE1547.1-2020. A  
commissioning test must include visual inspections and may include, as applicable, an  
operability and functional performance test and functional tests to verify interoperability  
of a combination of devices forming a system.  
Solution: striking of the provision provides the most  
flexibility in ensuring electric utilities maintain grid safety  
and reliability. Any project connected by the electric utility  
is already subject to commission review as the regulator of  
the electric utility.  
Commented [A4]: There should be no expectation to  
provide 24 hour support. This should be limited to standard  
hours of business and posted in procedures.  
Commented [A5]: Concern: “Certified” is not restricted  
to inverter-based systems. Also, the UL and IEEE  
certifications apply to safety and reliability of the specific  
device under normal operation and expected utility events  
(outages, transients etc.) and does not certify that the device  
will not cause safety or reliability events on the distribution  
system or is being used properly. The interconnection  
review is what is intended to ensure that the device will not  
result in abnormal electrical gird behavior.  
Example: A certified inverter with a power limited setting is  
capable of creating over voltage on the electrical system  
without conflicting with the certification if the power  
limiting setting is based on the inverter connection point  
instead of a gird limitation.  
(p) “Conforming” means the information in an interconnection application is consistent  
with the general principles of distribution system operation and DER characteristics.  
(q) “Customer” means a person or entity who receives electric service from an electric  
utility’s distribution system or a person who participates in a legacy net metering or  
distributed generation program through an alternative electric supplier or electric utility.  
(r) “DC” means “direct current.”  
Solution: “an inverter-based system” should be replaced  
with “a component” and “Utility review of certified devices  
should be limited to a review of the safety and reliability of  
the component’s impact on other the electrical grid.” Should  
be added for clarity.  
(s) “Distributed energy resource” or “DER” means a source of electric power and its  
associated facilities that is connected to a distribution system. DER includes both  
generators and energy storage devices capable of exporting active power injecting power  
and energy to a distribution system.  
(t) “Distributed generation program” means the distributed generation program  
approved by the commission and included in an electric utility’s tariff pursuant to section  
Commented [A6]: Concern: IEEE1547.1-2020 is the  
testing requirement  
Commented [A7]: Concern: Definition is not consistent  
with other industry standards which may create confusion  
and conflict with future standards.  
Commented [A8]: Concern: Without this change, DER  
that can supply reactive power are excluded.  
Exhibit A  
3
6a(14) of 1939 PA 3, MCL 460.6a, or established in an alternative electric supplier  
distributed generation program plan.  
(u) “Distribution system” means the structures, equipment, and facilities owned and  
operated by an electric utility to deliver electricity to end users, not including  
transmission and generation facilities that are subject to the jurisdiction of the federal  
energy regulatory commission.  
(v) “Distribution upgrades” mean the additions, modifications, or improvements to the  
distribution system necessary to accommodate a DER’s connection to the distribution  
system.  
(w) “Electric utility” means any person or entity whose rates are regulated by the  
commission for selling electricity to retail customers in this state. For purposes of R  
460.901a through R 460.992 only, “electric utility” includes cooperative electric utilities  
that are member regulated as provided in section 4 of the electric cooperative member-  
regulation act, 2008 PA 167, MCL 460.34.  
(x) “Electrically coincident” means that 2 or more proposed DERs associated with  
pending interconnection applications have operating characteristics and nameplate  
capacities which require that distribution upgrades, DER site upgrades, or some  
combination of both distribution and DER site upgrades will be necessary if the DERs are  
installed in electrical proximity with each other on a distribution system.  
(y) “Electrically remote” means a proposed DER is not electrically coincident with a  
DER that is associated with a pending interconnection application.  
Commented [A9]: Concern: as originally defined this  
does not consider the impact to the operation of other DER  
or the ability of DER to coordinate to resolve distribution  
system constraints.  
Example: Combined fault current contribution of two new  
DER’s may exceed system constraints, modification of one  
or both DER’s may be necessary or be the most cost  
effective option to resolve the issue as opposed to  
distribution upgrades.  
(z) “Eligible electric generator” means a methane digester or renewable energy system  
with a generation capacity limited to a customer’s electric need and that does not exceed  
either of the following:  
(i) 150 kWac of aggregate generation at a single site for a renewable energy system.  
(ii) 550 kWac of aggregate generation at a single site for a methane digester.  
(aa) “Energy storage device” means a device that captures energy produced at one time,  
stores that energy for a period of time, and delivers that energy as electricity for use at a  
future time. For purposes of these rules, an energy storage device may be considered a  
DER.  
(bb) “Export capacity” means the maximum possible simultaneous generation of the  
DER, and is calculated as the maximum amount of export as permitted by limiting the  
amount of the DER’s export at the point of common coupling. means the amount of  
power that can be transferred from the DER to the Distribution System. Export  
Capacity is either the Nameplate Rating, or a lower amount if limited using an  
acceptable means defined by the utility.  
(cc) “Facilities study” means a study to specify and estimate the cost of the equipment,  
engineering, procurement, and construction work if distribution upgrades or  
interconnection facilities are required.  
Solution: Add “…, DER site upgrades, or combination of  
both distribution and DER site upgrades…”  
Commented [A10]: Concern: Not consistent with  
industry definitions  
Example/Solution: US DOE sponsored BATRIES  
definition “means the amount of power that can be  
transferred from the DER to the Distribution System. Export  
Capacity is either the Nameplate Rating, or a lower amount  
if limited using an acceptable means” adding for clarity “as  
defined in procedures by the electric utility or otherwise  
mutually agreed within an interconnection agreement”  
Commented [A11]: Concern: Not consistent with  
industry definitions  
Example/Solution: US DOE sponsor BATRIES definition  
“means the amount of power that can be transferred from the  
DER to the Distribution System. Export Capacity is either  
the Nameplate Rating, or a lower amount if limited using an  
acceptable means” adding for clarity “as defined in  
procedures by the electric utility or otherwise mutually  
agreed within an interconnection agreement”  
(dd) “Fast track” means the procedure used for evaluating a proposed interconnection  
that makes use of screening processes, as described in R 460.944 to R 460.950.  
(ee) “Force majeure event” means an act of God; labor disturbance; act of the public  
enemy; war; insurrection; riot; fire, storm, or flood; explosion, breakage, or accident to  
machinery or equipment; an emergency order, regulation or restriction imposed by  
governmental, military, or lawfully established civilian authorities; or another cause  
Document is available for download at  
Toolkit and Guidance for the Interconnection of Energy  
Storage and Solar-Plus-Storage - BATRIES  
(energystorageinterconnection.org)  
https://energystorageinterconnection.org/resources/batries-  
toolkit/  
Exhibit A  
4
beyond a party’s control. A force majeure event does not include an act of negligence or  
intentional wrongdoing.  
(ff) “Full retail rate” means the power supply and distribution components of the cost of  
electric service. Full retail rate does not include a system access charge, service charge,  
or other charge that is assessed on a per meter, premise, or customer basis.  
(gg) “Generating capacity” means the maximum nameplate rating of a DER in  
alternating current, except that where this capacity is limited by any of the methods of  
limiting electrical export, generating capacity shall be the net capacity as limited though  
the use of such methods not including inadvertent export.  
(hh) “Good standing” means an applicant has paid in full all undisputed bills rendered  
by the interconnecting electric utility and any alternative electric supplier in a timely  
manner and none of these bills are in arrears.  
(ii) “Governmental authority” means any federal, state, local, or other governmental  
regulatory or administrative agency, court, commission, department, board, or other  
governmental subdivision, legislature, rulemaking board, tribunal, or other governmental  
authority having jurisdiction over the parties, their respective facilities, or the respective  
services they provide, and exercising or entitled to exercise any administrative, executive,  
police, or taxing authority or power; provided, however, that this term does not include  
the applicant, interconnection customer, electric utility, or any affiliate thereof.  
(jj) “GPS” means global positioning system.  
Commented [A12]: Concern: creates confusion with  
export capacity.  
Example: For purposes of providing nameplate capacity in a  
pre-application report, is a 5 MW generator that is limited to  
1 MW of grid export but connected to a facility with a  
minimum load of 4 MW a 1 MW or a 5 MW generator?  
Solution: Existing nameplate capacity and export capacity  
definitions are sufficient to identify what value is intended.  
Commented [A13]: Concern: creates incentive to dispute  
bills  
Solution: strike “Undisputed”  
(kk) “Grid network” means a configuration of a distribution system or an area of a  
distribution system in which each customer is supplied electric energy at the secondary  
voltage by more than 1 transformer.  
(ll) “High voltage distribution” means those parts of a distribution system that operate  
within a voltage range specified in the electric utility’s interconnection procedures. For  
purposes of these rules, the term “subtransmission” means the same as high voltage  
distribution.  
Commented [A14]: IEEE 519 is missing from the  
definitions  
(mm) “IEEE” means Iinstitute of Eelectrical and Eelectronics Eengineers.  
(nn) “IEEE 1547-2018” means “IEEE Standard for Interconnection and Interoperability  
of Distributed Energy Resources with Associated Electric Power Systems Interfaces,” as  
adopted by reference in R 460.902.  
if storage is going to be included  
https://sagroups.ieee.org/scc21/standards/2030-2-1-2019/  
needs to be included.  
(oo) “IEEE 1547.1-2020” means IEEE “Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces,” as adopted by reference in R 460.902.  
(pp) “Inadvertent export” means the potential condition in which a normally non-  
exporting or limited-exporting DER experiences an unscheduled export that does not  
exceed limitations in terms of magnitude or duration as specified in UL 1741 CRD for  
PCS. means the unscheduled export of active power from a DER, exceeding a  
specified magnitude and for a limited duration, due to fluctuations in load-  
following behavior.  
(qq) “Independent system operator” means an independent, federally-regulated entity  
established to coordinate regional transmission in a non-discriminatory manner and to  
ensure the safety and reliability of the transmission and distribution systems.  
(rr) “Initial review” means the fast track initial review screens described in R 460.946.  
Commented [A15]: Concern: In addition to providing  
for normal fluctuations this allows for potentially damaging  
flows to the distribution system as UL 1741 only has scope  
of the DER equipment and not the interconnection.  
Example: A large DER offsetting a large load, experiences a  
loss of load resulting in the DER reaching its UL limit of  
110% (132V) at the point of interconnection, utility  
distribution equipment which was compensating for low  
voltage prior to the inadvertent export event was set for 5%  
raise taking the distribution system to 115% or 138V, which  
would not be allowed to exist for 30 seconds by UL 1741 or  
any other industry standard.  
Solution: US DOE sponsored BATIERS definition “means  
the unscheduled export of active power from a DER,  
exceeding a specified magnitude and for a limited  
duration, due to fluctuations in load-following behavior.  
“
Exhibit A  
5
(ss) “Interconnection” means the process undertaken by an electric utility to construct  
the electrical facilities necessary to connect a DER with a distribution system so that  
parallel operation can occur.  
(tt) “Interconnection agreement” means an agreement containing the terms and  
conditions governing the electrical interconnection between the electric utility and the  
applicant or interconnection customer. Where construction of interconnection facilities or  
distribution upgrades are necessary, the agreement, or amendments, shall estimatespecify  
timelines, provide non-binding cost estimates, and require payment(s) in advance to the  
electric utility, or timely payment in advance of milestones acceptable to the electric  
utility, payment milestones for construction of facilities and distribution upgrades to  
interconnect a DER into the distribution system, and shall identify design, controls,  
settings, procurement, installation, and construction requirements associated with  
installation of the DER. Standard level 1, 2, and 3 interconnection agreements and level  
4 and 5 interconnection agreements are types of interconnection agreements.  
(uu) “Interconnection coordinator” means a person or persons designated by the electric  
utility who shall serve as the point of contact from which general information on the  
application process and on the affected system or systems can be obtained through  
informal request by the applicant or interconnection customer.  
Commented [A16]: Concern: Agreements missing scope  
items and combining time limited construction items with  
ongoing requirement in the interconnection agreement.  
Example: Payment prior to construction is needed to limit  
liability transfer. Control settings need to be added.  
Solution: Second sentence as modified “Where construction  
of interconnection facilities or distribution upgrades are  
necessary, the agreement, or amendments, shall estimate  
timelines, provide non-binding cost estimates, and require  
payment in advance to the electric utility for construction of  
facilities and distribution upgrades to interconnect a DER  
into the distribution system, and shall identify design,  
controls, settings, procurement, installation, and construction  
requirements associated with installation of the DER.”  
(vv) “Interconnection customer” means the person or entity, which may does not  
include the electric utility, responsible for ensuring a DER is operated and maintained in  
compliance with all local, state, and federal laws, as well as with all rules, standards, and  
interconnection procedures.  
Commented [A17]: Concern: Clarification that control  
settings should be included within the agreement as they are  
important part of the ongoing DER operation.  
(ww) “Interconnection facilities” mean any equipment required for the sole purpose of  
connecting a DER with a distribution system.  
(xx) “Interconnection procedures” mean the requirements that govern project  
interconnection adopted by each electric utility and approved by the commission.  
(yy) “Interconnection study agreement” means an agreement between an applicant and  
an electric utility for the electric utility to study a proposed DER.  
Example: if control settings are used to eliminate the need  
for system upgrades those settings need to be in the  
agreement.  
Solution: added “controls, settings” to language.  
Commented [A18]: Concern: the restrictions on electric  
utilities are overly broad,  
Example: Substation control (non-system storage) backup  
batteries provide ability to operate switching equipment and  
restore the system during outages. As written would these be  
subject to interconnection applications?  
R 460.901b Definitions; J-Z.  
Rule 1b. As used in these rules:  
(a) “kW” means kilowatt.  
(b) “kWac” means the electric power, in kilowatts, associated with the alternating  
current output of a DER at unity power factor.  
(c) “kWh” means kilowatt-hours.  
Solution: striking of the provision provides the most  
flexibility in ensuring electric utilities maintain grid safety  
and reliability. Any project connected by the electric utility  
is already subject to commission review as the regulator of  
the electric utility.  
(d) “Legacy net metering program” means the true net metering or modified net  
metering programs in place prior to commission approval of a distributed generation  
program tariff pursuant to section 6a(14) of 1939 PA 3, MCL 460.6a, and prior to the  
establishment of an alternative electric supplier distributed generation plan.  
(e) “Level 1” means a project using certified equipment with a nameplate capacity  
project of 20 kWac or less.  
(f) “Level 2” means a project using certified equipment with a nameplate capacity  
project of greater than 20 kWac and not more than 150 kWac.  
(g) “Level 3” means a project of 150 kWac or less that is not using certified equipment,  
or a project greater than 150 kWac and not more than 550 kWac.  
Commented [A19]: Concern: Certification applies only to  
the equipment response to variations on the electrical system,  
not the potential system impact from the DER equipment on  
the system.  
Example: An UL 1741 certified inverter can ensure that  
voltage remains at 110% at the terminals of the device but  
can’t prevent further voltage rise from other devices on the  
electrical system.  
Solution: definitions adjusted to reflect proper use of  
certification.  
Exhibit A  
6
(h) “Level 4” means a project of greater than 550 kWac and not more than 1 MWac.  
(i) “Level 5” means a project of greater than 1 MWac.  
(j) “Level 4 and 5 interconnection agreement” means an interconnection agreement  
applicable to level 4 and 5 interconnection applications.  
(k) “Limited export” means the exporting capability of a DER whose generating  
nameplate capacity is limited by means accepted by the electric utility.the use of any  
configuration or operating mode.  
(l) “Low voltage distribution” means those parts of a distribution system that operate  
with a voltage range specified in the electric utility’s interconnection procedures.  
(m) “Mainline” means a conductor that serves as the three-phase backbone of a low  
voltage distribution circuit.  
(n) “Material modification” means a modification to the DER nameplate  
ratinggenerating capacity, electrical size of components, bill of materials, machine data,  
equipment configuration, or the interconnection site of the DER at any time after  
receiving notification by the electric utility of a complete interconnection application.  
Replacing a component with another component that has near-identical characteristics  
does not constitute a material modification. For the proposed modification to be  
considered material, it shall have been reviewed and been determined to have or  
anticipated to have a material impact on 1 or more of the following:  
(i) The cost, timing, or design of any equipment located between the point of common  
coupling and the DER.  
(ii) The cost, timing, or design of any other application.  
(iii) The electric utility’s distribution system or an affected system.  
(iv) The safety or reliability of the distribution system.  
(o) “Methane digester” means a renewable energy system that uses animal or  
agricultural waste for the production of fuel gas that can be burned for the generation of  
electricity or steam.  
(p) “Modified net metering” means an electric utility billing method that applies the  
power supply component of the full retail rate to the net of the bidirectional flow of kWh  
across the customer interconnection with the electric utility’s distribution system during a  
billing period or time-of-use pricing period.  
(q) “MW” means megawatt.  
(r) “MWac” means the electric power, in megawatts, associated with the alternating  
current output of a DER at unity power factor.  
(s) “Nameplate capacity” means the maximum active power, in kWac or MWac, at  
which a DER is capable of sustained operation. Nameplate Rating means the sum total of  
maximum rated power output of all of a DER’s constituent generating units and/or ESS  
as identified on the manufacturer nameplate, regardless of whether it is limited by any  
approved means.  
(t) “Nameplate rating” means all of the following at which a DER is capable of  
sustained operation:  
(i) Nominal voltage (V).  
(ii) Current (A).  
(iii) Maximum active power (kWac).  
Commented [A20]: Concern: some configuration or  
operating modes are not sufficient to ensure limited export.  
Example: A device that fails to maintain export limits  
during software or firmware updates or that that can be  
changed at any time due to poor implementation of access  
controls or cyber security would be an example of an  
unacceptable operating mode for limited export.  
Solution: language as modified  
Commented [A21]: Concern: near identical is not defined  
and is subject to a wide range of interpretation.  
Example: does ‘near identical’ apply to the number or the  
severity of the change in characteristics? An inverter that is  
the same nameplate size and voltage ratings, but has a 200%  
vs. a 110% nameplate fault current contribution may be near  
identical to an interconnection customer. This would not be  
‘near identical’ from an electrical system perspective.  
Solution: strike language.  
Commented [A22]: Concern: nameplate capacity is the  
appropriate term here. Power export is one factor out of  
many that need to be considered when assessing the impact  
to system reliability and power quality.  
Example: Replacing a 1 MW inverter with a 2 MW inverter  
control limited to 1 MW is not equivalent from an  
inadvertent export or fault current perspective and creates  
new risk that would need to be studied.  
Solution: Use of nameplate capacity in place of nameplate  
capacity.  
Commented [A23]: Concern: definition is not consistent  
with industry:  
Example/Solution: US DOE sponsored BATIERS  
definition “Nameplate Rating means the sum total of  
maximum rated power output of all of a DER’s constituent  
generating units and/or ESS as identified on the  
manufacturer nameplate, regardless of whether it is limited  
by any approved means.”  
(iv) Apparent power (kVA).  
(v) Reactive power (kvar).  
Exhibit A  
7
(u) “Nationally recognized testing laboratory” means any testing laboratory recognized  
by the accreditation program of the United States Department of Labor Occupational  
Safety and Health Administration.  
(v) “Network protector” means those devices associated with a secondary network used  
to automatically disconnect a transformer when reverse power flow occurs.  
(w) “Non-export track” means the procedure for evaluating a proposed interconnection  
that will not inject electric energy into an electric utility’s distribution system, as  
described in R 460.942.  
(x) “Ongoing operating capacity” means the actual simultaneous generating capacity,  
taking into account the operational differences of load offset and export. If the  
contribution of energy storage to the total contribution is limited by programing of the  
maximum active power output, use of a power control system, use of a power relay, or  
some other mutually agreed upon, on-site limiting element, only the capacity that is  
designed to inject electricity to the utility’s distribution system, other than inadvertent  
exports and fault contribution, will be used within certain technical screens and  
evaluations.  
(y) “Parallel operation” means the operation, for longer than 100 milliseconds, of a DER  
while connected to the energized distribution system.  
(z) “Party” or “parties” means an electric utility, applicant, or interconnection customer.  
(aa) “Point of common coupling” means the point where the DER connects with the  
electric utility’s distribution system.  
Commented [A24]: Concern: Duplicative, Conflicts with  
other definitions.  
Example/Solutions: this can be more effectively  
accomplished by making those inclusions/exclusions within  
the applicable screens.  
(bb) “Power control system” means systems or devices which electronically limit or  
control steady state currents to a programmable limit and certified under UL 1741 CRD  
for PCS by a nationally recognized testing laboratory. Power Control System or PCS  
means systems or devices which electronically limit or control steady state current to a  
programmable limit.  
(cc) “Radial supply” means a configuration of a distribution system or an area of a  
distribution system in which each customer can only be supplied electric energy by 1  
substation transformer and distribution line at a time.  
Commented [A25]: Concern: definition is not consistent  
with industry:  
Example/Solution: US DOE sponsored BATIERS  
definition “Power Control System or PCS means systems or  
devices which electronically limit or control steady state  
current to a programmable limit.  
(dd) “Readily available” means no creation of data is required, and little or no  
computation or analysis of data is required.  
(ee) “Reasonable efforts” mean, with respect to an action required to be attempted or  
taken by a party under these interconnection rules, efforts that are as timely as possible  
and consistent with those a party would take to protect its own interests.  
(ff) “Regional transmission operator” means a voluntary organization of electric  
transmission owners, transmission users, and other entities approved by the federal  
energy regulatory commission to efficiently coordinate electric transmission planning,  
expansion, operation, and use on a regional and interregional basis.  
(gg) “Renewable energy credit” means a credit granted pursuant to the commission's  
renewable energy credit certification and tracking program in section 41 of the clean and  
renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1041.  
(hh) “Renewable energy resource” means that term as defined in section 11(i) of the  
clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL  
460.1011.  
Commented [A26]: Unnecessary.  
(ii) “Renewable energy system” means that term as defined in section 11(k) of the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1011.  
Exhibit A  
8
(jj) “Secondary network” means those areas of a distribution system that operate at a  
secondary voltage level and are networked.  
(kk) “Site” means a contiguous site, regardless of the number of meters at that site. A  
site that would be contiguous but for the presence of a street, road, or highway is  
considered to be contiguous for the purposes of these rules.  
(ll) “Spot network” means a location on the distribution system that uses 2 or more  
inter-tied transformers to supply an electrical network circuit, such as a network circuit in  
a large building.  
(mm) “Standard level 1, 2, and 3 interconnection agreement” means the statewide  
interconnection agreement approved by the commission and applicable to levels 1, 2 and  
3 interconnection applications. A cover sheet including modifications to address any  
special operating conditions may be added.  
(nn) “Study track” means the procedure used for evaluating a proposed interconnection  
as described in R 460.952 to R 460.962.  
(oo) “Supplemental review” means the fast track supplemental review screens described  
in R 460.950.  
(pp) “System impact study” means a study to identify and describe the impacts to the  
electric utility’s distribution system that would occur if the proposed DER were  
interconnected exactly as proposed and without any modifications to the electric utility’s  
distribution system. A system impact study also identifies affected systems.  
(qq) “Temporary DER” means a DER that is installed on the distribution system by the  
electric utility with the intention of not operating at the site permanently.  
(rr) “True net metering” means an electric utility billing method that applies the full  
retail rate to the net of the bidirectional flow of kWh across the customer interconnection  
with the electric utility’s distribution system, during a billing period or time-of-use  
pricing period.  
(ss) “UL” means underwriters laboratory.  
(tt) “UL 1741” means the September 28, 2021 edition of “Standard for Inverters,  
Converters, Controllers and Interconnection System Equipment for Use With Distributed  
Energy Resources,” as adopted by reference in R 460.902.  
(uu) "UL 1741 CRD for PCS" means the Certification Requirement Decision for Power  
Control Systems for the standard titled Inverters, Converters, Controllers and  
Interconnection System Equipment for Use With Distributed Energy Resources, March 8,  
2019, as adopted by reference in R 460.902(b).  
R 460.902 Adoption of standards by reference.  
Rule 2. (1) The standards specified in these rules are adopted by reference as follows:  
(a) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, September 28, 2021  
edition, is available from Underwriters Laboratories at the internet website:  
https://standardscatalog.ul.com/ProductDetail.aspx?productId=UL1741 at a cost of  
$798.00 at the time of adoption of these rules.  
(b) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, January 28, 2010 edition,  
is available from Underwriters Laboratories at the internet  
Exhibit A  
9
website: https://standardscatalog.ul.com/ProductDetail.aspx?productId=UL1741 at a  
cost of $716.00 at the time of adoption of these rules.  
(c) ANSI C84.1 – 2016 Electric Power Systems and Equipment – Voltage Ratings (60  
Hz), June 9, 2016, is available from the American National Standards Institute, Inc. at the  
internet website https://webstore.ansi.org/ at a cost of $111.24 at the time of adoption of  
these rules.  
(d) The following standards adopted by reference are available from IEEE at the  
internet website https://standards.ieee.org at the time of adoption of these rules.  
(i) The IEEE 1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating  
Installations on Power Systems, October 30, 2015, is available at a cost of $99.00 -  
$147.00 at the time of adoption of these rules.  
(ii) The IEEE 1547 - 2018, IEEE Standard for Interconnection and Interoperability of  
Distributed Energy Resources with Associated Electric Power System Interfaces, April 6,  
2018, is available at a cost of $149.00 - $224.00 at the time of adoption of these rules.  
(iii) The IEEE 1547.1-2020 IEEE Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces, May 21, 2020, is available at a cost of $197.00 - $296.00 at the  
time of adoption of these rules.  
(iv) The IEEE 519-2014 IEEE Recommended Practice and Requirements for  
Harmonic Control in Electric Power Systems, June 11, 2014, is available at a cost of  
$52.00 - $66.00 at the time of adoption of these rules.  
(2) The commission has copies of the standards specified in subrule (1) of this rule  
available for review at its offices located at 7109 W. Saginaw Hwy., Lansing, Michigan  
48917-1120. The mailing address is Michigan Public Service Commission, P.O. Box  
30221, Lansing, Michigan 48909-0221.  
R 460.904 Informal mediation.  
Rule 4. (1) The parties shall may attempt to resolve all disputes arising out of the  
interconnection process, as defined by R 460.901a through R 460.992, according to the  
provisions of this rule.  
(2) Prior to formal mediation under R 460.906, the parties shall attempt to resolve any  
conflict without commission intervention through direct discussion and informal  
negotiation.  
(3) In the event that parties are unable to resolve the dispute privately, the parties may,  
by mutual agreement, make a written request for informal mediation to the commission  
staff. The informal mediation shall be conducted by an interconnection ombudsperson  
who shall be a member of the commission staff and designated by the commission. Both  
parties may choose to have attorneys or appropriate representation present.  
(4) During informal mediation, the parties mayshall discuss relevant facts pertaining to  
the dispute and the relief being sought. The interconnection ombudsperson and relevant  
commission staff shall be present to facilitate the discussion and provide guidance among  
the parties. Parties shall operate in good faith and use commercially reasonablebest  
efforts to resolve the dispute.  
(5) If a resolution is reached by the end of the meeting or meetings, the parties may draft  
a resolution of the dispute.  
Exhibit A  
10  
(6) If the parties reach impasse and are unable to resolve the dispute, the parties shall  
proceed to the formal mediation process described in R 460.906.  
R 460.906 Formal mediation.  
Rule 6. (1) If the parties have been unable to resolve a dispute through the informal  
mediation process under R 460.904, the parties shall then attempt to resolve the dispute in  
the following manner:  
(a) The complaining party shall file a written notice of dispute with the commission.  
The notice of dispute must state the specific grounds for the dispute, sufficient facts to  
support the allegations, the relief requested, and must contain all information, testimony,  
exhibits, or other documents and information within the party’s possession on which the  
party intends to rely to support the party’s position.  
(b) The complaining party shall give notice that it is invoking the procedures in this  
rule. The complaining party shall send the notice to the non-complaining party’s email  
address and file the notice with the commission.  
(c) The non-complaining party shall acknowledge the notice of dispute within 10  
business days of its receipt and identify a representative with the authority to make  
decisions on its behalf with respect to the dispute.  
(d) An administrative law judge shall serve as the mediator in these proceedings. The  
administrative law judge may request and receive assistance from commission staff.  
(e) Within 60 business days from the date the non-complaining party acknowledges the  
dispute, the mediator shall issue a recommended settlement.  
(f) Within 5 business days after the date the recommended settlement is issued, each  
party shall file with the commission a written acceptance or rejection of the  
recommended settlement. If the parties accept the recommendation, then the  
recommendation shall become an order. If a party rejects or fails to respond within 5  
business days to the recommended settlement, then the dispute may proceed to a  
contested case hearing before the commission as provided in R 792.10415.  
(2) Nothing in these rules precludes a disputing party from filing a formal complaint  
with the commission, either instead of or after pursuing informal mediation or formal  
mediation pursuant to these rules.  
(3) The initiation of any form of dispute resolution by a party tolls any applicable  
deadlines under these rules until the dispute is resolved.  
R 460.908 Timelines for electric utilities serving fewer than 1,000,000 in-state customers.  
Rule 8. An electric utility serving fewer than 1,000,000 in-state customers shall have an  
additional 10 business days to comply with the timelines in R 460.911 to R 460.1026.  
This rule does not apply to applicants or interconnection customers.  
R 460.910 Waivers.  
Rule 10. An electric utility or, customer, alternative electric supplier, applicant, or  
interconnection customer may requestapply to the commission for a waiver from 1 or  
more provisions of these rules and may request expeditious processing. The commission  
Exhibit A  
11  
may grant a waiver upon a showing of good cause and a finding that the waiver is in the  
public interest. No waiver is necessary or required with respect to an electric utility’s  
right to test, study, examine, and if appropriate in the judgment of the electric utility not  
connect or disconnect a DER that threatens the reliability of electric service or the safety  
of customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
PART 2. INTERCONNECTION STANDARDS  
R 460.911 Applicability.  
Rule 11. These rules apply to all interconnection applications filed on or after the  
effective date of these rules. The electric utility shall complete work on any  
interconnection study agreement executed prior to the effective date of these rules  
pursuant to the terms and conditions of that interconnection study agreement. Any new  
studies or other additional work must be completed pursuant to these rules. Existing  
applications that are inactive, become subject to these rules once either party perform an  
action to progress a project under these rules. An electric utility or an alternative electric  
supplier shall not restrict access to interconnection for level 1, level 2, and level 3 DERs  
that are not participants in the legacy net metering or distributed generation programs.  
Commented [A27]: Concern: Need to resolve conflicts  
between existing projects and the new rules.  
Example: It is unclear if a project not moving forward under  
the old rules should impact projects under the new rules.  
Solution: New language: “Existing applications where no  
study or work is active, become subject to these rules once  
either party performs an action to progress a project under  
these rules.”  
Commented [A28]: Concern: Need to resolve conflicts  
between existing projects and the new rules.  
Example: It is unclear if a project not moving forward under  
the old rules should impact projects under the new rules.  
R 460.920 Electric utility interconnection procedures.  
Solution: New language: “Existing applications that are  
inactive, become subject to these rules once either party  
perform an action to progress a project under these rules.”  
Rule 20. (1) An electric utility shall file applications for approval of interconnection  
procedures and forms within 12030 business days of the effective date of these rules.  
(2) The commission shall issue its order approving or, rejecting, or modifying the  
proposed interconnection procedures and forms within 360 calendar days of the effective  
date of these rules. If the commission finds the procedures and forms proposed by the  
electric utility to be inadequate or unacceptable, the commission may either adopt  
procedures and forms proposed by another person in the proceeding or modify and  
accept the procedures and forms proposed by the electric utility.  
Commented [A29]: Concern: The changes adopted after  
the initial deadline are significant and invalidate significant  
work performed in the development of the procedures.  
Example: The initial procedures stakeholder meeting  
highlights many gaps between draft procedures and current  
rules.  
(3) Until the commission accepts, rejects, or modifies all of an electric utility’s  
interconnection procedures and forms, the electric utility may use the proposed  
interconnection procedures and forms when processing interconnection applications. with  
the exception of fixed fees and fee caps. An electric utility shall only charge fees that  
comply with the requirements of R 460.926 until the commission accepts, rejects, or  
modifies the proposed interconnection procedures and forms unless the commission  
approves different fees pursuant to R 460.926(4).  
Solution: Additional time to make the necessary  
adjustments pending the final version of the rules.  
Exhibit A  
12  
(4) Two or more electric utilities may file a joint application proposing interconnection  
procedures for use by the joint applicants. The proposed interconnection procedures must  
ensure compliance with these rules.  
(5) The proposed interconnection procedures must, at a minimum, describeinclude all of  
the electric utility’s requirements for the following:  
(a) All necessary applications and, forms, and relevant template agreements.  
(b) A schedule of all applicable fixed fees and fee caps.The interconnection application  
fees that will recover the electric utility’s costs as provided for in R 460.926 and R  
460.928.  
(c) Voltage ranges for high voltage distribution and low voltage distribution.  
(d) Required initial review screens.  
(e) Required supplemental review screens.  
(f) The process for conducting system impact studies and facilities studies on DERs  
when there is an affected system issue.  
(g) Testing and certification requirements of DER telecommunications, cybersecurity,  
data exchange, and remote control operation.  
(h) Parallel operation requirements.  
(i) A method to estimate the expected annual kWh output of the generator or  
generators.  
(j) Acceptable methods or standards for power-limited export DERs in compliance with  
allowances in R 460.980.  
(k) A cost allocation methodology for study track DERs.  
(l) An evaluation of an interconnection application for a project that includes single or  
multiple types of DERs at a site for which the applicant seeks a single point of common  
coupling.  
(m) Details describing how an energy storage device may be integrated into an existing  
legacy net metering program system without impacting the 10-year grandfathering period  
or participation in the distributed generation program.  
(n) For electric utilities that are member-regulated electric cooperatives, a procedure for  
fairly processing applications in instances in which the number of applications exceed the  
capacity of the electric cooperative to timely meet the deadlines in these rules.  
(o) Examples of modifications that are not material modifications.  
(p) The procedure for performing a material modification review to determine if a  
modification is material.  
(q) Any required terms and conditions which must be specified in the general liability  
insurance for level 3, 4, and 5 projects.  
(r) A list of the electric utility’s holidays.  
(s) If an electric utility uses an alternative process pursuant to R 460.956, a description  
of that process.  
(6) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
Exhibit A  
13  
deadlines under these rules until the matter is resolved. An electric utility shall obtain  
commission approval to revise its interconnection procedures.  
R 460.922 Online applications and electronic submission.  
Rule 22. (1) An electric utility shall allow pre-application report requests,  
interconnection applications, and interconnection agreements to be submitted  
electronically, such as, through the electric utility’s website or via email.  
(2) An electric utility shall dedicate a page on its website or direct customers to a linked  
website with information on these rules. The relevant information available to an  
applicant or interconnection customer via a website must include all of the following:  
(a) These rules and interconnection procedures in an electronically searchable format.  
(b) The electric utility’s applications and all associated forms in a format that allows for  
electronic entry of data.  
(c) Sample documents including, at a minimum, a 1-line diagram with required labels.  
(d) Contact information for the electric utility’s DER interconnection coordinator,  
including an email address and a phone number.  
(e) Directions for the submission of applications.  
R 460.924 Communications.  
Rule 24. (1) An electric utility shall designate 1 or more interconnection coordinators.  
The telephone number and e-mail address of the interconnection coordinator or  
coordinators must be made available on the electric utility’s website. The interconnection  
coordinator or coordinators must be available to provide reasonable assistance to the  
applicant or interconnection customer but is not responsible to directly answer or resolve  
all of the issues that may arise in the interconnection process. The interconnection  
coordinator utility is not responsible forto providinge repeated training to an applicantte,  
or ongoing support for how to properly apply for interconnection.  
(2) An applicant may designate an application agent. An application agent may serve as  
the single point of contact for the applicant and may coordinate with the electric utility on  
the applicant’s behalf. Designation of an application agent does not absolve the applicant  
from signing interconnection documents or from complying with the requirements in  
these rules and the interconnection agreement.  
Commented [A30]: Concern: Reasonableness could use  
some supporting language.  
Example: Reasonable support for an interconnection  
customer that has never been through the process is  
materially different than the support that should be provided  
to an applicant that has attempted hundreds of previous  
applications.  
(3) An electric utility must be indemnified by the applicant and its application agent  
with respect to assistance provided by an interconnection coordinator or coordinators.  
Solution: additional language to clarify reasonable “The  
interconnection coordinator is not responsible for providing  
repeated training to an applicant’s employees, or ongoing  
support for how to properly apply for interconnection once  
reasonable assistance has been given.”  
R 460.926 Fees.  
Rule 26. (1) After the effective date of these rules, all electric utility fees for the pre-  
application report, application, the non-export track and the fast track shall be the electric  
utility’s actual documented fully embedded costs with a return at the electric utility’s  
authorized rate of return on capital expenses and without markup on operations and  
maintenance expense. Information that the electric utility chooses to disclose in a pre-  
application report or otherwise shall be priced at the market value of such information as  
determined by the electric utility. The customer shall pay all interconnection costs.  
Exhibit A  
14  
theestablished as listed in subrule (2) of this rule. Initial fees for the study track shall not  
exceed initial fee caps as established in subrule (3) of this rule. Fees must remain in effect  
until interconnection procedures are approved by the commission under R 460.920. At  
the electric utility’s option, a system impact study and a facilities study may be conducted  
by a qualified 3rd party engineering firm and the fee for such study or studies shall be the  
electric utility’s actual documented cost.  
(2) The fee amounts for the pre-application report, non-export track, and fast track for  
all levels of DERs are as follows:  
(a) The pre-application report fee may not exceed $300.  
(b) The non-export track fee may not exceed $100 + $1/kWac for certified DERs and  
$100 + $2/kWac for non-certified DERs.  
(c) The fast track initial review fee is $100 + $1/kWac for certified DERs and $100 +  
$2/kWac for non-certified DERs.  
(d) Any applicable legacy net metering program application fee pursuant to R  
460.1004(7) or distributed generation program application fee pursuant to R 460.1006(6),  
together, may not exceed a total of $50.  
(3) The initial fee caps for a fast track supplemental review and the study track for all  
levels of DERs are as follows:  
(a) The fee for a fast track supplemental review including all review screens may not  
exceed $1,000.  
(b) The study track fee for interconnection application review and the scoping meeting  
may not exceed $300.  
(c) The system impact study fee may not exceed $10,000.  
Commented [A31]: Concern: clarification need to ensure  
that this is only for a review of the application form in a  
scoping meeting and does not substitute for application  
review fee for fast track or study process.  
(d) The facilities study fee may not exceed $15,000.  
(4) ApplicationThe fees listed in subrule (2) and initial fee caps listed in subrule (3) of  
this rule, must be displayed prominently on the electric utility’s interconnection website.  
(5) An electric utility that expects to incur costs greater than the fees listed in subrule  
(2) or initial fee caps listed in subrule (3) of this rule in the evaluation of an  
interconnection application may file a request for a waiver pursuant to R 460.910.  
Commented [A32]: Language was written to provide  
clarity to written comments. In addition, the following  
technical concerns exist as written.  
R 460.928 Fee and fee cap modifications.  
Concern: size-based fees need to be referenced to nameplate  
capacity. No processes exist to collect insufficient fees  
based on changes in use of certified or non-certified devices  
or where the applicant provided an undersized application.  
Rule 28. (1) An electric utility shall include in its proposed interconnection procedures  
fixed fees to replace the fees specified in R 460.926(2)(a), (b), and (c), and add any  
other fixed fees the electric utility considers necessary.  
Example a 2 MW project that proposes to proceed with a 1  
MW export limit using a certified inverter. The initial  
review should be based on the 2 MW value and if it is  
identified that a non-certified inverter is used the additional  
$1/kWac should be collected.  
(2) An electric utility shall include in its proposed interconnection procedures adjusted  
fee caps to replace the initial fee caps specified in R 460.926(3)(a), (b), (c), and (d), and  
add any other fee caps the electric utility considers necessary. An electric utility may  
charge actual costs up to the fee caps.  
(3) The fixed fees must be specific to level size and be based on estimates of reasonable  
costs to perform the applicable service or study. The fee caps must be specific to level  
size and be based on a reasonable range of costs for performing the applicable study.  
(4) The most recently approved fixed fees and fee caps must be listed in the electric  
utility’s interconnection procedures and displayed prominently on the electric utility’s  
interconnection website.  
Solution: Add nameplate, provide for collection of  
insufficient fees while in application, alternatively require  
that the application be withdrawn and resubmitted.  
Exhibit A  
15  
(5) Application feesThe fixed fees and fee caps that are approved for inclusion in the  
electric utility’s interconnection procedures by the commission may be reviewed at any  
time by the electric utility and adjusted, if necessary, subject to commission review and  
approval.  
(6) Any modification of fees may not be applicable to fees already paid.  
(7) An electric utility that expects to incur costs greater than its prevailing fee caps in  
the evaluation of an interconnection application may file a request for a waiver pursuant  
to R 460.910.  
R 460.930 Pre-application report request form.  
Rule 30. (1) An applicant shall submit a completed pre-application report request form  
and the required fee for a pre-application report on a proposed level 4 or level 5 DER.  
(2) The pre-application report request form must include all of the following  
information:  
(a) Project contact information, including name, address, phone number, and email  
address.  
(b) Project location, as accurately as can be identified, which may be given by any of  
the following:  
(i) Street address with nearby cross streets and town, county and zip code.  
(ii) An aerial map with location clearly marked.  
(iii) GPS coordinates.  
(c) Account number, meter number, structure number, or other equivalent information  
identifying the proposed point of common coupling, if available.  
(d) Whether the DER equipment is certified or non-certified and is any combination of  
the following:  
Commented [A33]: Concern: Standards certify  
equipment performance, not interconnections  
(i) Solar.  
Solution: language as modified.  
(ii) Wind.  
(iii) Cogeneration.  
(iv) Storage.  
(v) Solar with storage.  
(vi) Other type of DER (must specify).  
(e) Capacity of the DER types in alternating current kW, direct current kW, and kVA,  
and kWh for storage including existing and new.  
(f) Whether the DER configuration is single or 3-phase.  
(g) Whether the DER will be a stand-alone generator, meaning no onsite load other than  
station service.  
(h) Whether the DER will be certified.  
(i) Whether new service is requested. If there is existing service, the customer account  
number and site minimum and maximum current or proposed electric loads in kW, if  
available, must be included, and how the load is expected to change must be specified.  
(j) Whether the location is new construction.  
(k) if the coupling between generation and/or storage is A/C or D/C and if separate  
inverters will be used.  
(l) where the site is planning on participating in market programs  
Commented [A34]: Concern: These questions help  
provide clarification about the expected operation of the  
DER.  
Exhibit A  
16  
R 460.932 Pre-application report.  
Rule 32. (1) Using the information provided in the pre-application report request form  
described in R 460.930, an electric utility shall identify the substation bus, bank, or  
circuit most likely to serve the point of common coupling. This identification by the  
electric utility does not necessarily indicate that this would be the circuit to which the  
project ultimately connects.  
(2) An applicant may request additional pre-application reports if information about  
multiple points of common coupling is requested. No more than 10 pre-application  
report requests may be submitted by an applicant and its affiliates during a 1-week  
period. An electric utility may reject additional pre-application report requests.  
(3) At the electric utility’s option, and upon full payment in advance of the market value  
as determined by the electric utility, of such information, tThe pre-application report  
maymust include all of the following information:  
(a) Total capacity, in MW, of substation bus, bank, or circuit based on normal or  
operating ratings likely to serve the proposed point of common coupling.  
(b) Existing aggregate generation capacity, in MW, interconnected to a substation bus,  
bank, or circuit likely to serve the proposed point of common coupling.  
(c) Aggregate capacity, in MW, of generation not yet built but found in previously  
accepted interconnection applications, for a substation bus, bank, or circuit likely to serve  
the proposed point of common coupling.  
(d) Available capacity, in MW, of substation bus, bank, or circuit likely to serve the  
proposed point of common coupling.  
(e) Substation nominal distribution voltage.  
(f) Nominal distribution circuit voltage at the proposed point of common coupling.  
(g) Label, name, or identifier of the distribution circuit on which the proposed point of  
common coupling is located.  
(h) Approximate circuit distance between the proposed point of common coupling and  
the substation.  
(i) The actual or estimated peak load and minimum load data at any relevant line  
section or sections, including daytime minimum load and absolute minimum load, when  
available. If not readily available, the report must indicate whether the generator is  
expected to exceed minimum load on the circuit.  
(j) Whether the point of common coupling is located behind a line voltage regulator and  
whether the substation has a load tap changer.  
(k) Limiting conductor ratings from the proposed point of common coupling to the  
distribution substation.  
(l) Number of phases available at the primary voltage level at the proposed point of  
common coupling, and, if a single phase, distance from the 3-phase circuit.  
(m) Whether the point of common coupling is located on a spot network, area network,  
grid network, radial supply, or secondary network.  
(n) Based on the proposed point of common coupling, the report must indicate whether  
power quality issues may be present on the circuit.  
(o) Whether or not the area has been identified as having a prior affected system.  
(p) Whether or not the site will require a system impact study for high voltage  
distribution based on size, location, and existing system configuration.  
Exhibit A  
17  
(4) The pre-application report may include only existing and readily available data. A  
request for a pre-application report does not obligate an electric utility to conduct a study  
or other analysis of the proposed DER if data is not readily available. The pre-  
application report must also indicate any information listed in subrule (3) of this rule that  
is not readily available. An electric utility may, at its discretion, return any portion of the  
pre-application report fee because some or all information does not exist.  
(5) Pre-application report requests must be processed in the order in which an electric  
utility received the requests.  
(6) An electric utility shall provide the data required in the pre-application report to the  
applicant within 20 business days of receipt of the completed request form and payment  
of the fee. The pre-application report produced by the electric utility is non-binding and  
does not confer any rights on the applicant. In no event shall the electric utility be  
required to provide information prior to full payment in advance, or that the electric  
utility in good faith determines to be Critical Electric Infrastructure Information (CEII) or  
subject to National Electric Reliability Council Critical Infrastructure Protection (NERC  
CIP).  
Commented [A35]: Concern: Costs of, and risk of,  
providing detailed system information can change rapidly  
and it is necessary to ensure that utilities can take reasonable  
actions to protect the security of the electrical system.  
R 460.934 Site control.  
Rule 34. (1) Documentation of site control must be submitted with the application by  
the applicant.  
Example: Cybersecurity teams identify critical circuit  
information available on the web linked to pre-application  
reports.  
(2) For level 3, 4, or 5 DERs, site control may be demonstrated by providing  
documentation that shows any of the following:  
(a) Ownership of, a leasehold interest in, or a right to develop a site for the purpose of  
constructing and operating the DER.  
Solution: The electrical utility should be able to respond to  
real time information and make determinations about what  
level of information protection is required to maintain grid  
security based real world conditions.  
(b) An enforceable option to purchase or acquire a leasehold site for this purpose.  
(c) A legally binding agreement transferring a present real property right to specified  
real property along with the right to construct and operate a DER on the specified real  
property for a period of time not less than 5 years.  
(3) For level 1 or 2 DERs, proof of site control may be demonstrated by the site owner’s  
signature and contact information on the application.  
(4) An applicant may redact commercially sensitive information from site control  
documents.  
R 460.936 Interconnection applications.  
Rule 36. (1) An electric utility shall provide an interconnection application for an  
applicant to complete, including for those applicants whose DERs will be configured to  
be non-exporting.  
(2) All documents required for a complete interconnection application must be listed on  
the interconnection application. For level 4 and 5 interconnection applications, the list of  
required documents must include a completed pre-application report.  
(3) For interconnection applications with proposed DERs that fall into level 1, an  
applicant shall provide a 1-line diagram and a site diagram.  
(4) For interconnection applications with proposed DERs that fall into levels 2 and 3, an  
applicant shall provide a 1-line diagram that is either sealed by a professional engineer  
Exhibit A  
18  
licensed in this state or signed by an electrical contractor who is licensed in this state with  
the electrical contractor’s license number noted on the diagram. An applicant shall also  
provide a site diagram.  
(5) For interconnection applications with proposed DERs that fall into levels 4 and 5, an  
applicant shall provide a 1-line diagram that is sealed by a professional engineer who is  
licensed in this state. An applicant shall also provide a site diagram.  
(6) Applications shall be reviewed to assess whether they are complete and conforming  
in the order in which they were received. An application is considered received when an  
electric utility receives the application, the application’s attachments, and the application  
fee. The application must be date-stamped for the first business day when the electric  
utility has received the interconnection application, the application attachments, and  
payment of the application fee. An electric utility shall notify the applicant of receipt of  
the application by the end of the third business day following the date of the date stamp.  
(7) The electric utility shall notify the applicant that the interconnection application is  
either complete and conforming, or incomplete, or non-conforming, within 10 business  
days of the date stamp.  
(a) If an interconnection application is determined to be complete and conforming by the  
electric utility, the applicant must be notified that the interconnection application is  
accepted. The electric utility shall also indicate whether the interconnection application  
will be processed using the non-export track, fast track, or study track.  
(b) If the application is incomplete or non-conforming, the electric utility shall provide  
to the applicant a written list of all deficiencies with the notification. The applicant shall  
have 60 business days from the date of electric utility notification to submit the necessary  
information and may provide up to 2 submissions during this time period. After each  
submission of information, the electric utility shall have 10 business days to notify the  
applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this rule,  
the utility may withdraw the application.  
(8) An electric utility shall comply with part 2 of these rules, R 460.911 to R 460.992,  
and its interconnection procedures when interconnecting DERs that it owns and operates  
onto its distribution system, with the exception of temporary DERs.  
(9) An electric utility shall use the same process when processing and studying  
interconnection applications from all applicants, whether the DER is owned or operated  
by the electric utility, its subsidiaries or affiliates, or others, with the exception of  
temporary DERs.  
(10) An electric utility shall review and update interconnection applications periodically  
to reflect new information required to properly review DERs, subject to commission  
review and approval.  
Commented [A36]: Concern: the restrictions on electric  
utilities are overly broad.  
Example: Substation backup batteries provide energy  
storage are connected to the distribution system and are not  
temporary. As written would these be subject to  
interconnection applications? Would NWA projects need  
interconnection applications? Is the commission expecting  
NWA’s to be studied based solely on their potential  
operating capability as an interconnection or based on their  
specific function as a distribution asset?  
R 460.938 Public interconnection list.  
Rule 38. (1) An electric utility shall maintain a publicly available interconnection list,  
which is available in a sortable spreadsheet format. The sortable spreadsheet must be  
provided to the public upon request. An electric utility that has received not less than  
100 complete interconnection applications in a year shall publish this list on the electric  
utility’s website. The public interconnection list must be updated monthly unless no  
Solution: striking of the provision provides the most  
flexibility in ensuring electric utilities maintain grid safety  
and reliability. Any project connected by the electric utility  
is already subject to commission review as the regulator of  
the electric utility.  
Exhibit A  
19  
changes to the spreadsheet have occurred in that month. The date of the most recent  
update must be clearly indicated.  
(2) The public interconnection list must include all of the following:  
(a) An application identifier.  
(b) The date that the electric utility received the application.  
(c) The date that the electric utility considered the application to be complete and  
conforming.  
(d) Whether the application is on the non-export track, fast track, or study track.  
(e) The proposed DER nameplate capacity.  
(f) The proposed DER interconnection size level.  
(g) The DER technology type.  
(h) The county and township in which the proposed point of common coupling will be  
located.  
(i) The current status of the application’s progress in the interconnection process.  
(j) The labels, names, or identifiers of the distribution circuit and substation.  
(3) In no event shall the electric utility be required to provide information prior to full  
payment in advance or that the electric utility in good faith determines to be Critical  
Electric Infrastructure Information (CEII) or subject to National Electric Reliability  
Council Critical Infrastructure Protection (NERC CIP).  
Commented [A37]: Concern: This is a rapidly evolving  
area of distribution systems.  
Example: This list would provide an adversary a list of  
circuits that could be impacted based on if a specific  
technology has been compromised.  
R 460.942 Non-export track review.  
Rule 42. (1) Interconnection applications for DERs that agree in writing to install and  
properly operate utility approved controls that will limit prevent injection of electric  
energy into an electric utility’s distribution system are eligible for evaluation under the  
non-export track. Non-export eligibility requires an existing electrical service at the  
applicant’s premise.  
(2) Subject to review and approval by the commission, an An electric utility may limit  
the eligibility of the non-export track in its interconnection procedures based on the  
characteristics of its distribution system.  
(3) Before submitting an interconnection application, a non-export track applicant may  
contact the electric utility interconnection coordinator for assistance in determining  
whether a non-export track review will be sufficient or the study track is necessary. The  
electric utility shall provide the applicant reasonable assistance based on available  
information. If the applicant chooses to proceed, an interconnection application shall be  
submitted pursuant to R 460.936.  
(4) Within 20 business days after being notified that the application was accepted, the  
electric utility shall perform an initial review by using some or all of the initial review  
screens specified in the electric utility’s interconnection procedures, including evaluating  
the potential for power quality or operational impacts to other customers power quality  
and utility assets, and notify the applicant of the results. If an electric utility chooses to  
perform a review using a subset of the initial review screens, the exclusion of 1 or more  
screens may not be the only basis for the electric utility to require interconnection  
facilities, distribution upgrades, further study, or application modifications, subject to  
subsection (7).  
Solution: Electric utilities should be able to respond to new  
information as it becomes available to the industry.  
Commented [A38]: Concern: Non-export is different  
than limited export and this clarifies that limited export is  
processed under the applicable fast track or study screens.  
Example: A project with 2 MW nameplate limited to 1 MW  
of export should be processed under the appropriate track  
under the remainder of these rules, not non-export.  
Solution: Added clarification that the method to prevent  
export must be approved by the utility to be processed as a  
non-export track.  
Commented [A39]: Concern: This section is specifically  
to allow for a non-export interconnection, not limited export.  
The potential impacts of large generation hidden behind  
large load would not be adequately addressed by the existing  
screens.  
Example: a non-export project would default to level 1 in  
the rules as written, which would exclude most screens. The  
interaction of the DER with other distribution devices such  
as capacitors and regulators is important to coordinate and  
would not be covered by the screens listed.  
Solution: Add language to ensure that non-export specific  
criteria can be used and any issues identified could be  
addressed.  
Exhibit A  
20  
(a) If the notification indicates that no interconnection facilities, distribution upgrades,  
further study, or application modifications are required, the electric utility shall provide  
specifications for any equipment the applicant will be required to install and, in order to  
properly do so, may require site walkdowns to identify appropriate locations for  
disconnects, metering, and other equipment. Applicant shall schedule such walkdowns at  
at a reasonable, mutually agreeable time.within 20 business days of the applicant being  
notified. Within 10 business days of receiving the equipment specifications, the applicant  
shall notify the electric utility whether it will proceed under R 460.964 to an  
interconnection agreement or will withdraw the application. The applicant’s failure to  
notify the electric utility within the required time period shall result in the interconnection  
application being withdrawn by the electric utility.  
Commented [A40]: Concern: Non-export configurations  
vary significantly and may be part of customer industrial  
process and operations. Site visits or additional configuration  
information is typically needed to ensure alignment in the  
placement of equipment and future configurations or facility  
upgrades.  
Example: Siting protective equipment such as relay and  
disconnect equipment can often be made simpler by  
coordinating on site with customers.  
(b) If application modification is offered by the electric utility, the applicant shall either  
withdraw the interconnection application or provide a modified application within 60  
business days from the date of electric utility notification, with up to 2 resubmissions  
during this time period to provide a modified application. After each submission of  
information, the electric utility shall notify the applicant within 10 business days that the  
interconnection application is either accepted or rejected due to continuing deficiencies.  
If the applicant does not meet the timelines required by this subrule, the electric utility  
may withdraw the application. When the applicant provides a modified application, the  
electric utility shall follow the procedure specified in subrule (4) of this rule.  
(5) If further study is required, the electric utility shall present options and the applicant  
shall decide whether to proceed to a supplemental review under R 460.950, or to the  
study track under R 460.952, or to withdraw the application. The applicant shall have 20  
business days to decide on a course of action and notify the electric utility. In the  
absence of this notification, the electric utility may withdraw the application within the  
required time period.  
Solution: Updated language to include added options for site  
walkdowns and adjust timelines to allow for site visit  
coordination.  
(6) IfWhen an applicant changes electric utility tariff service or from a non-exporting  
system to an exporting system, the applicant shall submit a new interconnection  
application to permit proper evaluation of equipment and operational requirements.  
(7) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
Commented [A41]: Concern: Additional clarification  
that moving to an export tariff will require re-evaluation.  
Example/Solution: Adjust language to ensure that its clear  
that a new evaluation will be needed if the export level is  
changed.  
Commented [A42]: Concern: 5 MWac exceeds utility  
operating criteria and exceeds maximum ratings of almost all  
4.8kV circuits.  
Solution: Lower threshold should be used to reflect realistic  
opportunity to pass fast track screens.  
Commented [A43]: Concern: Fast Track applicability  
should be based on an agreed point of interconnection for  
study, not an initially proposed one that may be infeasible.  
R 460.944 Fast track applicability.  
Example: A 5 MW project proposing to interconnect to a  
4.8kV distribution area, but with a 40kV line on site should  
be directed to study at the 40kV point of interconnection vs.  
the 4.8kV location.  
Rule 44. (1) Level 1, level 2, level 3, and level 4 applications and level 5 applications as  
large as 15 MWac in which the DER will not is not proposing to interconnect with the  
electric utility’s high voltage distribution system are eligible for the fast track. Projects  
using an acceptable method for limited export shall be eligible for fast track, the Level of  
Solution: modified language to clarify the actual point of  
interconnection.  
Exhibit A  
21  
the project shall be determined by the nameplate rating. Applications that provide for the  
use of an energy storage device so the export of power meets the requirements of level 1,  
level 2, level 3, level 4 or level 5 as large as 5 MWac in which the applicant is not  
proposing to interconnect the DER with the electric utility’s high voltage distribution  
system are also eligible for the fast track.  
Commented [A44]: Concern: The applicability of  
nameplate or export capacity varies by screen. Nameplate  
should be the default. Use of export capacity should be  
considered as applicable to ensure the safety and reliability  
of electrical grid and other equipment not covered by  
certification.  
(2) An applicant that is eligible for the fast track may forgo the fast track and proceed  
directly to the study track.  
(3) An applicant with an application that is outside the limitations specified in subrule  
(1) of this rule may petition the electric utility to have its application evaluated under fast  
track. The electric utility may approve or reject this request at its discretion.  
(4) In determining fast track eligibility, an electric utility may, at its discretion,  
aggregate all proposed new generation on a site regardless of the existence of a shared  
point of common coupling or multiple points of common coupling.  
(5) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
Solution: Language as modified and supported by the  
Toolkit & Guidance for the Interconnection of Energy  
Storage & Solar-Plus-Storage  
Commented [A45]: Concern: Multiple points of  
common coupling should only be used when doing still  
allows for accurate screening.  
Example: A customer with a second service may or may not  
have its generation aggregated based on if the services are at  
the same voltage level and electrically proximate (physically  
close without operating equipment between) and other  
factors.  
Solution: made it clear that the electric utility would make  
the determination to aggregate based on its assessment of  
how the generation would interact across the various points  
of interconnection.  
R 460.946 Fast track; initial review.  
Rule 46. (1) An electric utility shall list in its interconnection procedures the initial  
review screens specified in subrule (4) of this rule. An electric utility may add additional  
details to each of these screens, or additional screens in the interconnection procedures.  
(2) The electric utility may waive application of 1, some, or all of the initial review  
screens.  
(3) Within 10 business days after an electric utility receives a complete and conforming  
level 1 or level 2 application and associated payment, or within 20 business days after an  
electric utility receives a complete and conforming level 3, level 4, or level 5 application  
and associated payment, the electric utility shall perform an initial review and notify the  
applicant of the results. The initial review must consist of applying the initial review  
screens selected by the electric utility pursuant to subrule (2) of this rule to the proposed  
DER. The electric utility shall not require a supplemental review or a system impact  
study if the DER passes the applied initial review screens, subject to subsection (8).  
(4) The initial review screens are all of the following:  
(a) The entire proposed DER, including all aggregated site generation and point or  
points of interconnection, must be located within the electric utility’s service territory.  
(b) For interconnection of a proposed DER to a radial distribution circuit, the  
aggregated generation, including the proposed DER, on the circuit may not exceed 15%  
of the line section annual peak load as most recently measured or calculated if measured  
data is not available. A line section is that portion of an electric utility’s distribution  
system connected to a customer bounded by automatic sectionalizing devices or the end  
of the distribution line. The electric utility shall consider 100% of applicable loading, if  
Commented [A46]: Concern: While modification of  
these screens in procedures is a good step. It is critical that  
as the electrical utility be able to place new screens that  
account for known system conditions or previously identified  
issues to be address during the screening process instead of  
at, or after commissioning. Additionally, emerging  
technology or higher levels of DER penetration may require  
new screens to adequately assess system impacts.  
Example: FERC SGIP, which most of these screens are  
based on, specifically includes provision 2.2.1.10 that  
protects asset owners in the event that an issue requiring  
action by the electrical utility is required. For example, for a  
customer with a dedicated 25kVA transformer installing a  
40kW PV system would pass the screens because the  
secondary is not shared, while clearly potentially  
overloading electrical utility equipment.  
Solution: Adjust language to allow for additional screens to  
be added via procedures.  
Exhibit A  
22  
available, instead of 15% of line section peak load for level 1 and level 2 DER. In the  
event daytime loading data is not available, the data must be collected by January  
December 2023 for electric utilities with more than 1,000,000 customers in this state, or  
by a date specified in interconnection procedures approved by the commission for electric  
utilities with fewer than 1,000,000 customers in this state, and shall not consider as part  
of the aggregate generation, for purposes of this screen, DER capacity known to be  
already reflected in the minimum load data. This screen does not apply to level 1 and  
level 2 non-export DER applications.  
Commented [A47]: Concern: Time is needed to collect  
this data and the adoption of the rules may not make this date  
feasible. Unclear if this is a utility interconnection or  
planning activity?  
Solution: Remove requirement or extend date of  
requirement to accurately collect information once rules go  
into effect.  
(c) For interconnection of a proposed DER to the load side of network protectors, the  
proposed DER must either implement a non-sell back protection scheme approved by the  
electric utility to not exceed the customer load or utilize an inverter-based equipment  
package and, together with the aggregated other inverter-based DERs, may not exceed  
the smaller of 5% of a network’s protectors maximum load or 50 kWac.  
(d) The proposed DER, in aggregation with other DERs on the distribution circuit, may  
not contribute more than 10% to the distribution circuit’s maximum fault current at the  
point on the primary voltage nearest the proposed point of common coupling. This  
screen does not apply to level 1 applications.  
(e) The proposed DER, in aggregate with other DERs on the distribution circuit, may  
not cause any distribution protective devices and equipment or interconnection customer  
equipment on the system to exceed 87.5% of the short circuit interrupting capability. An  
interconnection may not be proposed for a circuit that already exceeds 87.5% of the short  
circuit interrupting capability. Distribution protective devices and equipment include, but  
are not limited to, substation breakers, fuse cutouts, and line reclosers. This screen does  
not apply to level 1 applications.  
(f) The initial review screen determines the type of interconnection to a primary  
distribution line for the proposed DER, according to the requirements specified in the  
table in this subdivision. This screen includes a review of the type of electrical service  
provided to the applicant, including line configuration and the transformer connection to  
limit the potential for creating over-voltages on the electric utility’s distribution system  
due to a loss of ground during the operating time of any anti-islanding function.  
Commented [A48]: Concern: This screen should apply  
to level 1 and level 2 DER’s where existing aggregated  
generation already exceeds 15% of line section.  
Example: a new subdivision is built as a net zero  
community. While each interconnection may be level 1 or 2  
the combined nameplate capacity will likely exceed 100% of  
the daytime for that line section.  
Solution: Apply screen to level 1 and level 2.  
Commented [A49]: Concern: Limit should be based on  
the rating of the protective device not the entire network.  
Example: 5% of a networks load may be larger than the  
rating of an individual network protector and cause  
unintended operation.  
Solution: added protector for clarification.  
Commented [A50]: Concern: This screen should apply  
to level 1 DER’s where existing aggregated fault  
contribution capability exceeds 10% of the system  
capability.  
Example: a new subdivision is built as a net zero  
community. While each interconnection may be level 1 the  
combined fault current contribution may exceed 10%.  
Solution: Apply screen to level 1.  
Primary Distribution Line  
Type  
Type of Interconnection to  
Primary Distribution Line  
3-phase or single phase,  
phase-to-phase  
Effectively-grounded 3- phase  
or single-phase, line-to-neutral  
Result  
Commented [A51]: Concern: This screen should apply  
to level 1 DER’s where existing aggregated fault  
contribution capability may cause equipment on the system  
to exceed 87.5% of the system capability.  
3-phase, 3 wire  
Pass screen  
Pass screen  
3-phase, 4 wire  
Example: a new subdivision is built as a net zero  
community. While each interconnection may be level 1 the  
combined fault current contribution may cause equipment o
...  
(g) If the proposed DER is to be interconnected on single-phase shared secondary, the  
aggregate generation capacity on the shared secondary, including the proposed DER  
export nameplate capacity, may not exceed 20 kWac or 65% of the transformer  
nameplate rating.  
(h) If the proposed DER is single-phase and is to be interconnected on a center tap  
neutral of a 240 volt service, its addition may not create an imbalance between the 2 sides  
of the 240 volt service of more than 20% of the nameplate rating of the service  
transformer.  
Commented [A52]: Removed because of aggregate  
contribution is equivalent to a larger DER  
Commented [A53]: Concern: potential voltage issues  
during inadvertent export should receive supplemental  
review.  
Example: A 40kW system with a net export limit of  
20kWac would cause a 5.6V raise during inadvertent export.  
This could place voltage in an immediate action window.  
...  
Exhibit A  
23  
(i) If the proposed DER is single-phase and is to be interconnected to a 3-phase service,  
its nameplate rating may not exceed 10% of the service transformer nameplate rating.  
(j) If the proposed DER’s point of common coupling is behind a line voltage regulator,  
the aggregate DER’s nameplate rating beyond that regulator must be less than 250 kWac.  
This screen does not include substation voltage regulators.  
Commented [A54]: Concern: Not all line or substation  
distribution regulators are capable of bi-directional operation  
and this screen doesn’t not address substation regulation that  
would be impacted or aggregate impacts.  
(k) No construction of facilities by the electric utility on its own system shall be  
required to accommodate the DER.  
(l) With a power change equal to the Nameplate Rating minus the Export Capacity, the  
change in voltage at the point on the medium voltage (primary) level nearest the Point of  
Interconnection does not exceed 3%.  
Example: A small rural substation with 1.5 MVA capacity is  
regulated by uni-directional line regulators inside the  
substation. A 250kW DER or multiple ones, would  
potentially cause failure or mis operation during reverse  
power flow conditions.  
(5) If the proposed interconnection passes the initial review screens, or if the proposed  
interconnection fails the screens but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant. If a facilities study is not required, the interconnection  
application must proceed under R 460.964 to an interconnection agreement. If a facilities  
study is required, the interconnection application must proceed under R 460.962.  
(6) If the proposed interconnection fails any of the initial review screens, or the  
interconnection does not comply with the applied for tariff, and the electric utility does  
not or cannot determine that the DER may be interconnected consistent with safety,  
reliability, and power quality standards, the electric utility shall notify the applicant,  
provide the applicant with the results of the application of the initial review screens, and  
offer all of the following options:  
Solution: Aggregate should be added to the DER capacity  
determination and determination of capability of the voltage  
regulator handle the DER should be determined during  
supplemental review.  
Commented [A55]: Concern: This FERC SGIP screen  
was not included in the current draft.  
Example: Replacement of a dedicated transformer or service  
is required to accommodate a new DER. A path to  
supplemental review or study is needed to allow for scope  
development of necessary upgrades to proceed to facilities  
study.  
(a) Attend a customer options meeting, as described in R 460.948.  
(b) Proceed to supplemental review under R 460.950.  
Solution: This screen provides for a path to supplemental  
review or study necessary to determine scope of work and  
options to be passed to facilities study.  
(c) Submit within 60 business days from the date of the electric utility notification, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility. The application modifications must mitigate or eliminate the factors  
that caused the interconnection application to fail 1 or more of the initial review screens.  
After each submission of information, the electric utility has 10 business days to notify  
the applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this  
subrule, the electric utility may withdraw the application. After the electric utility  
determines the application is accepted, the revised interconnection application must  
proceed under subrule (3) of this rule.  
Commented [A56]: Concern: Other screens do not  
address the voltage impact of sudden generation or load  
changes on the electrical system. Use suggested new screen  
from US DOE sponsored BATIERS report.  
Example: Generating facility uses export limiting and  
experiences inadvertent export such that the power quality  
and voltage of neighboring customers is affected.  
Solution: This screen provides for a path to supplemental  
review, site modification, or study necessary to determine  
scope of work and options to be passed to a facilities study.  
(d) Withdraw the interconnection application.  
Commented [A57]: Concern: It is critical to ensure that a  
customer understands the tariff eligibility of a DER prior to  
moving to construction of that DER.  
(7) If the applicant does not select a course of action under subrule (6) of this rule within  
10 business days of notice from the electric utility, the electric utility shall withdraw the  
interconnection application.  
(8) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
Example: Customer applies for DG tariff but the system size  
exceeds allowance under DG tariff. The electric utility  
should be able to provide that information to the  
interconnection customer as soon as possible.  
Solution: Proposed language to allow the utility to notify the  
customer of a conflict between expected tariff and any know  
eligibility requirements.  
Exhibit A  
24  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.948 Fast track; customer options meeting.  
Rule 48. (1) Upon an applicant’s request, the electric utility and the applicant shall  
schedule a customer options meeting between the electric utility and the applicant to  
review possible facility modifications, screen analysis, and related results to determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The customer options meeting must take place within 30 business  
days of the date of notification pursuant to R 460.946(6).  
(2) At the customer options meeting, the electric utility shall offer all of the following  
options:  
(a) Proceed to a supplemental review pursuant to R 460.950.  
(b) Continue evaluating the interconnection application under the study track pursuant  
to R 460.952.  
(c) Submit within 60 business days from the date of the customer options meeting, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility, which mitigates or eliminates the factors that caused the  
interconnection application to fail 1 or more of the initial review screens. After each  
submission of information, the electric utility has 10 business days to notify the applicant  
that the interconnection application is either accepted or rejected due to continuing  
deficiencies. If the applicant does not meet the timelines required by this subrule, the  
electric utility may withdraw the application. After the electric utility accepts the revised  
interconnection application, it must proceed under R 460.946(3).  
(d) Withdraw the interconnection application.  
(3) Following the customer options meeting, the applicant has up to 20 business days to  
decide on a course of action and notify the electric utility. In the absence of this  
notification within the required time, the electric utility shall withdraw the application.  
(4) The customer options meeting may take place in person or via telecommunications.  
(5) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.950 Fast track; supplemental review.  
Rule 50. (1) An electric utility shall list in its interconnection procedures the  
supplemental review screens specified in subrule (5) of this rule. An electric utility may  
add additional details to each of these screens in the interconnection procedures.  
Exhibit A  
25  
(2) An electric utility may waive application of 1, some, or all of the supplemental  
review screens.  
(3) To receive a supplemental review, an applicant shall submit payment of the  
supplemental review fee within 20 business days of agreeing to a supplemental review. If  
payment of the fee has not been received by the electric utility within 25 business days,  
the electric utility shall withdraw the interconnection application.  
(4) Within 30 business days after the applicant pays the applicable supplemental review  
fee or fees, and provides any reasonably requested data, an electric utility shall perform a  
supplemental review and notify the applicant of the results. The supplemental review  
must consist of applying the initial review screens selected by the electric utility pursuant  
to subrule (2) of this rule to the proposed DER. The electric utility shall not require a  
system impact study if the DER passes the applied supplemental review screens.  
(5) The supplemental review screens must include all of the following:  
(a) Minimum load screen. Where 12 months of line section minimum load data,  
including onsite load but not station service load served by the proposed DER, are  
available, can be calculated, can be estimated from existing data, or can be determined  
from a power flow model, the aggregate DER capacity on the line section must be less  
than 100% of the minimum load for all line sections bounded by automatic sectionalizing  
devices upstream of the proposed DER. If minimum load data are not available, or cannot  
be calculated, estimated, or determined, an electric utility shall include the reason or  
reasons that it is unable to calculate, estimate, or determine minimum load in its  
supplemental review results notification under subrules (6) and (7) of this rule. All of the  
following must be applied by the electric utility:  
Commented [A58]: Concern: Clarity to ensure that  
customers understand that all requirements including  
payment and providing any additional data are necessary to  
initiate supplemental review.  
Example: Customer provides payment on 1/1/23 but  
requested data on 1/15/23, supplemental review timeline  
would start on 1/15/23.  
Solution: Language as modified.  
(i) The type of generation used by the proposed DER will be considered when  
calculating, estimating, or determining circuit or line section minimum load relevant for  
the application of the minimum load screen specified in subrule (5)(a) of this rule. Solar  
photovoltaic generation systems with no battery storage must use daytime minimum load.  
All other generation must use absolute minimum load unless an operating schedule is  
provided.  
(ii) When this screen is being applied to a DER that serves some station service load,  
only the net injection of electric energy into the electric utility’s distribution system may  
be considered as part of the aggregate generation.  
(iii) The electric utility shall not consider as part of the aggregate generation, for  
purposes of this supplemental screen, DER capacity known to be already reflected in the  
minimum load data.  
(b) Voltage and power quality screen. In aggregate with existing generation on the line  
section, all of the following conditions must be met:  
(i) The voltage regulation on the line section can be maintained in compliance with  
relevant requirements under all system conditions.  
(ii) The voltage fluctuation is within acceptable limits as defined by the IEEE Standard  
1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating Installations on  
Power Systems.  
(c) Safety and reliability screen. The location of the proposed DER and the aggregate  
generation capacity on the line section shallmay not create impacts to safety or reliability  
that require application of the study track to address. An electric utility shall consider all  
Exhibit A  
26  
of the following when determining potential impacts to safety and reliability in applying  
this screen:  
(i) Whether the line section has significant minimum loading levels dominated by a  
small number of customers, such as several large commercial customers.  
(ii) Whether the loading along the line section is uniform.  
(iii) Whether the proposed DER is located less than 0.5 electrical circuit miles for less  
than 5 kV or less than 2.5 electrical circuit miles for greater than 5 kV from the  
substation. In addition, whether the line section from the substation to the point of  
common coupling is a mainline rated for normal and emergency ampacity.  
(iv) Whether the proposed DER incorporates a time delay function to prevent  
reconnection of the DER to the distribution system until distribution system voltage and  
frequency are within normal limits for a prescribed time.  
Commented [A59]: Concern: Emergency ampacity is  
only used in abnormal configurations to maintain service  
until repairs can be completed.  
Solution: remove language.  
(v) Whether operational flexibility is reduced by the proposed DER, such that transfer  
of the line section or sections of the DER to a neighboring distribution circuit or  
substation may trigger overloads, power quality issues, or voltage issues.  
(vi) Whether the proposed DER employs equipment or systems certified by a  
recognized standards organization to address technical issues including, but not limited  
to, islanding, reverse power flow, or voltage quality.  
(6) If the proposed interconnection passes the supplemental review, or if the proposed  
interconnection fails the review but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant and the interconnection application must proceed  
pursuant to both of the following:  
(a) If the proposed interconnection requires a facilities study, the interconnection  
application must proceed under R 460.962.  
(b) If the proposed interconnection does not require further study, the interconnection  
application must proceed under R 460.964 to an interconnection agreement.  
(7) If the proposed interconnection fails any of the supplemental review screens or the  
electrical utility is unable to perform a supplemental review screen, and the electric utility  
does not or cannot determine that the DER may be interconnected consistent with safety,  
reliability, and power quality standards, the electric utility shall notify the applicant,  
provide the applicant with the results of the application of the supplemental review  
screens, and offer both of the following options:  
(a) Stop the supplemental review and continue evaluating the proposed interconnection  
under the study track under R 460.952.  
(b) Withdraw the interconnection application.  
(8) For subrules (6) and (7) of this rule, if an applicant does not select a course of action  
within 10 business days of notice from the electric utility, the electric utility shall  
withdraw the interconnection application.  
(9) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
Exhibit A  
27  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.952 Study track.  
Rule 52. (1) An electric utility shall use the study track to evaluate an interconnection  
application that has been accepted under R 460.936 if 1 or more of the following  
conditions is met:  
(a) The DER is not eligible for the non-export track or fast track.  
(b) The DER did not pass the initial review screens as part of the fast track and the  
applicant selected the study track option in the customer options meeting.  
(c) The DER did not pass 1 or more supplemental review screens.  
(d) The DER was evaluated under the non-export track and further study is required.  
(e) The DER is eligible for the fast track, but the applicant elected the study track.  
(2) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(a) of this rule, within 10 business days after the electric  
utility notifies the applicant that the interconnection application has been accepted  
pursuant to R 460.936, the electric utility shall provide to the applicant an individual  
study agreement or an agreement for an alternative process pursuant to R 460.956.  
(3) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(b), (c), or (d), of this rule, within 10 business days after  
the applicant has notified the electric utility to proceed to the study track, the electric  
utility shall provide to the applicant an individual study agreement or an agreement for an  
alternative process.  
(4) An electric utility’s interconnection procedures may include a provision for  
determining appropriate milestone payments to include with the system impact study fee  
and facilities study fee.  
(5) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.954 Individual study.  
Rule 54. (1) An electric utility that is evaluating DERs in the study track individually  
shall process the interconnection applications in the order in which the applications were  
placed into the study track, taking into account withdrawn interconnection applications  
and electrically remote DERs.  
(a) An electrically remote DER in an individual study may be studied on an expedited  
schedule relative to electrically coincident DERs. Electrically remote DERs must be  
studied in the order the interconnection applications were considered complete.  
Exhibit A  
28  
(2) When an interconnection application is delayed due to an affected system issue,  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint pursuant to R 792.10439 to R 792.10446, other interconnection applications  
that were placed into the study track on a later date may progress in the order in which  
the interconnection applications were placed into the study track.  
(3) An individual study process must consist of a system impact study pursuant to R  
460.960 and a facilities study pursuant to R 460.962. An electric utility may waive 1 or  
both studies for a particular interconnection application. An electric utility may specify  
additional studies it may perform on an interconnection application in its interconnection  
procedures, provided the electric utility is able to meet all applicable timelines associated  
with an individual study process.  
(4) Interconnection applications that meet all of the following requirements must be  
admitted into an individual study:  
(a) An electric utility determined the application to be complete and conforming.  
(b) An application qualifies for study track pursuant to R 460.952.  
(c) An interconnection application has a pre-application report, when required by R  
460.936(2).  
(d) An applicant has paid all required fees.  
(e) An applicant has signed and returned an individual study agreement.  
(f) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.956 Alternative process.  
Rule 56. An electric utility may use a process to study interconnection applications that  
is different from the process described by R 460.954 and R 460.958 to R 460.962. If an  
electric utility elects to use an alternative process, this process must be described in the  
electric utility’s interconnection procedures. Nothing in these rules shall be construed to  
foreclose an electric utility’s right to test, study, examine, and if appropriate in the  
judgment of the electric utility not connect or disconnect a DER that threatens the  
reliability of electric service or the safety of customers, utility employees, or the general  
public. An electric utility shall not be prevented from testing, studying, or examining a  
proposed or interconnected DER that threatens the reliability of electric service or the  
safety of customers, utility employees, or the general public and any electric utility action  
pursuant to this right tolls any applicable deadlines under these rules until the matter is  
resolved.  
R 460.958 Scoping meeting for interconnection applications that are to be studied  
individually.  
Exhibit A  
29  
Rule 58. (1) This rule applies only to interconnection applications proceeding pursuant  
an individual study agreement.  
(2) Upon request of the applicant, the electric utility and the applicant shall schedule a  
scoping meeting between the electric utility and the applicant to discuss the  
interconnection application and review existing fast track results, if any. The scoping  
meeting must take place within 20 business days after the interconnection application is  
considered complete by the electric utility or, if applicable, the fast track has been  
completed and the applicant has elected to continue with the system impact study or  
facilities study.  
(3) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting.  
(4) The scoping meeting may occur in-person or via telecommunications.  
(5) During the scoping meeting, the electric utility shall identify and communicate to the  
applicant whether the applicant must proceed to a system impact study, a facilities study,  
or an interconnection agreement and the basis for that decision, and 1 of the following  
must occur:  
(a) If a system impact study must be performed, the interconnection application  
proceeds to R 460.960.  
(b) If a facilities study must be performed, the interconnection application proceeds to  
R 460.962.  
(c) If a system impact study is not required and a facilities study is not required, the  
interconnection application must proceed to R 460.964 for an interconnection agreement.  
(d) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.960 System impact study agreement, scope, procedure, and review meeting.  
Rule 60. (1) For all DERs being studied individually, all of the following apply:  
(a) An electric utility shall provide the applicant a system impact study agreement  
within 5 business days of proceeding to this rule.  
(b) A system impact study agreement must include all of the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee including appropriate credit for any studies previously  
completed pursuant to the fast track or non-export track.  
(iii) If necessary, a list of any additional and reasonable technical data needed from the  
applicant to perform the system impact study.  
(iv) An estimated timeline for completion of the system impact study. In the event that  
acquisition of new or additional data, studies, or other information from an affected  
system or independent system operator such as the Midcontinent Independent System  
Operator, PJM or their successor organizations is indicated in order to perform a system  
Exhibit A  
30  
impact study consistent with good utility practice, the time for completion of a system  
impact study is tolled until such information is received.  
.
Commented [A60]: Concern: Electric utility should not  
be accountable for the timelines of others.  
(v) A list of the information that maymust be provided to the applicant in the system  
impact study report.  
(vi) In no event shall the electric utility be required to provide information prior to full  
payment in advance or that the electric utility in good faith determines to be Critical  
Electric Infrastructure Information (CEII) or subject to National Electric Reliability  
Council Critical Infrastructure Protection (NERC CIP).  
(c) An applicant who has requested a system impact study shall return the completed  
system impact study agreement, provide any additional technical data requested by the  
electric utility, and pay the required fee within 20 business days. An electric utility may  
consider the application withdrawn if the system impact study agreement, payment, and  
required technical data are not returned within 20 business days.  
(d) A system impact study must identify and describe the electric system impacts that  
would result if the proposed DER was interconnected without electric system  
modifications. A system impact study must provide a non-binding good faith list of  
facilities that are required as a result of the application and non-binding estimates of costs  
and time to construct these facilities.  
Example: Updated transmission information is needed from  
the MISO model to determine expected system impedance at  
the point of interconnection to resolve potential issue with  
equipment short circuit interrupting capability rating.  
Solution: Timeline must be tolled between notification of  
request for third party information and receipt of the  
information.  
Commented [A61]: Concern: This is a rapidly evolving  
area of distribution systems.  
Example: This list would provide an adversary a list of  
circuits that could be impacted based on if a specific  
technology has been compromised.  
Solution: Electric utilities should be able to respond to new  
information as it becomes available to the industry.  
(e) An electric utility shall explain in its interconnection procedures the process for  
conducting system impact studies on DERs when there is an affected system issue.  
(f) The electric utility shall complete the system impact study and transmit a system  
impact study report to the applicant within 60 business days of the receipt of the signed  
system impact study agreement, payment of the system impact study fee, completion of  
system impact study review meeting (if requested), and receipt of any necessary technical  
data. If necessary, the electric utility shall transmit a facilities study agreement to the  
applicant within 60 business days of receipt of the signed system impact study agreement,  
payment of all applicable fees, and any necessary technical data.  
(g) An electric utility may request reasonable additional data from the applicant within  
20 business days of beginning the system impact study. The electric utility and the  
applicant shall work together to resolve the additional data request so that the electric  
utility will be able to complete the system impact study within 60 business days as  
specified in subrule (1)(f) of this rule. If the applicant cannot provide the data in a manner  
to allow the impact study to complete in 60 business days, the study shall be put on hold  
day for day until the data is received and then resume.  
(h) Within 15 business days of receiving the system impact study report, the applicant  
shall notify the electric utility that it plans to pursue a system impact study review  
meeting, proceed to a facilities study pursuant to R 460.962, or withdraw the application.  
If the applicant fails to notify the electric utility within 15 business days, the electric  
utility may consider the application to be withdrawn.  
(i) Upon request by the applicant pursuant to subrule (1)(h) of this rule, the electric  
utility and the applicant shall schedule a system impact study review meeting between the  
electric utility and the applicant to review system impact study results and determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The system impact study review meeting must take place within 25  
Commented [A62]: Concern: If the applicant requests a  
study review meeting that may have a material effect on the  
direction of the facility study.  
Solution: System impact study timeline should reflect  
customer input.  
Commented [A63]: Concern: Interconnection customer  
need to be held to a timeline to respond to informational  
requests or utility studies can’t be completed in a timely  
manner.  
Example: A need for additional information is identified  
and communicated on day 5, the interconnection customer  
provides the data on day 59 of the study resulting in the need  
to restudy.  
Solution: Proposed solution is to hold the study day for day  
until necessary information is provided.  
Exhibit A  
31  
business days of the electric utility receiving notification that the applicant plans to attend  
a system impact study review meeting.  
(j) At the system impact study review meeting, the electric utility shall offer the  
applicant the option to withdraw the interconnection application, and 1 of the following  
options:  
(i) Proceed to a facilities study pursuant to R 460.962.  
(ii) Proceed directly to R 460.964 for an interconnection agreement.  
(k) Following the meeting, the applicant has not more than 45 business days to decide  
on a course of action. If an applicant fails to notify the electric utility within 45 business  
days, the electric utility may consider the application to be withdrawn.  
(l) The system impact study review meeting may occur in-person or via  
telecommunications.  
(m) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.962 Facilities study agreement, scope, procedure; review meeting.  
Rule 62. (1) For DERs being studied individually, all of the following apply:  
(a) If construction of facilities is required to provide interconnection and  
interoperability of the DER with the electric utility’s distribution system, the electric  
utility shall provide the applicant a facilities study agreement and the results of the  
applicant’s system impact study pursuant to R 460.960, if applicable. If no system impact  
study was performed, the The electric utility shall provide a facilities study agreement  
within 10 business days of proceeding to this rule.  
Commented [A64]: Concern: Clarity that in all cases a  
facilities study agreement should be provided within 10 days  
of proceeding to this rule.  
(b) The facilities study agreement must include the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee including appropriate credit for any studies previously  
completed pursuant to the fast track or non-export track.  
Example/Solution: Suggested change provides consistency  
and clarity to when a facilities study agreement should be  
provided.  
(iii) A timeline for completion of the facilities study.  
(iv) A list of the information that will be provided to the applicant in the facilities study  
report.  
(v) In no event shall the electric utility be required to provide information prior to full  
payment in advance or that the electric utility in good faith determines to be Critical  
Electric Infrastructure Information (CEII) or subject to National Electric Reliability  
Council Critical Infrastructure Protection (NERC CIP).  
(c) The applicant shall return the signed facilities study agreement and pay the required  
facilities study fee within 20 business days. The electric utility may withdraw the  
application if the facilities study agreement and payment are not returned within 20  
business days.  
Exhibit A  
32  
(d) A facilities study must specify and estimate the cost of the required equipment,  
engineering, procurement, and construction work, including overheads, needed to  
interconnect the DER, and an estimated timeline for the completion of construction. The  
electric utility shall provide cost estimates that are detailed and itemized.  
(e) The electric utility shall explain in its interconnection procedures the process for  
conducting facilities studies on DERs while there is an affected system issue.  
(f) The electric utility shall complete the facilities study and transmit a facilities study  
report to the applicant within 80 business days of the receipt of the signed facilities study  
agreement and payment of the facilities study fee. If clarification or information is  
required from the applicant to complete the study, the study shall be put on hold day for  
day until the data is received and then resume.  
(g) Within 10 business days of receiving a facilities study report from the electric  
utility, the applicant shall select 1 option from the following options:  
(i) Request a facilities study review meeting with the electric utility.  
(ii) Proceed to an interconnection agreement pursuant to R 460.964.  
(iii) Withdraw the interconnection application.  
If the applicant fails to inform the electric utility within 10 business days of its chosen  
course of action, the electric utility may consider the application withdrawn.  
(h) Upon request by the applicant pursuant to subrule (1)(g)(i) of this rule, the electric  
utility and the applicant shall schedule a facilities study review to review the facilities  
study results and determine what further steps are needed to permit the DER to be  
connected safely and reliably to the distribution system. The facilities study review  
meeting must take place within 25 business days of the electric utility receiving  
notification that the applicant will attend a facilities study review meeting.  
(i) At the facilities study review meeting, the electric utility shall offer both of the  
following options:  
Commented [A65]: Concern: Interconnection customers  
need to be held to a timeline to respond to informational  
requests or utility studies can’t be completed in a timely  
manner.  
Example: A need for additional information is identified and  
communicated on day 5, the interconnection customer  
provides the data on day 59 of the study resulting in the need  
to restudy.  
Solution: Proposed solution is to hold the study day for day  
until necessary information is provided.  
(i) Proceed to an interconnection agreement pursuant to R 460.964.  
(ii) Withdraw the interconnection application.  
(j) Following the meeting, the applicant has no more than 20 business days to decide on  
a course of action and notify the electric utility of this course of action. If the applicant  
fails to notify the electric utility within 20 business days, the electric utility may withdraw  
the application.  
(k) The facilities study review meeting may be conducted in-person or via  
telecommunications.  
(l) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
Exhibit A  
33  
R 460.964 Interconnection agreement.  
Rule 64. (1) For level 1, 2, or 3 interconnection applications, where no construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
provide transmit its standard level 1, 2, and 3 interconnection agreement, which may  
include modifications to address any special operating conditions, to an applicant within  
53 business days of reaching this stage.  
Commented [A66]: Concern: While most agreements are  
electronic, some customers still prefer hard copies. To  
achieve timelines electric utility should be measured on  
distributing the agreement not the customer receiving it.  
(2) For level 1, 2, or 3 interconnection applications, where construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
provide its standard level 1, 2, and 3 interconnection agreement with modifications to  
address any special operating conditions, required construction activities, estimated  
construction milestone timing, and estimated cost to an applicant within 305 business  
days of reaching this stage. The applicant and electric utility shall attempt to mutually  
agree on the timing of construction milestones consistent with the electric utility’s other  
obligations, commercial reasonableness, and good utility practice.  
Example: customer request agreement be mailed to home  
for review and signature.  
Solution: replace provide with transmit to reflect the  
agreement being sent electronically or mailed.  
Commented [A67]: Concern: Interconnection  
agreements should include all the same provisions a  
reasonable utility would make for normal commercial  
activity.  
(3) For an applicant with level 1, 2, or 3 interconnection applications, the applicant shall  
sign and return the standard level 1, 2, and 3 interconnection agreement with payment, if  
applicable, within 20 business days of receiving the agreement.  
Solution: modified language to reflect cost and timing are  
estimates, extend the timeline for reaching a mutually  
agreeable schedule, and added clarification to ensure that  
interconnection agreements are consistent with other  
agreements the utility would make in the course of business.  
(a) If the applicant did not sign and return the standard level 1, 2, and 3 interconnection  
agreement and payment, if applicable, within 20 business days, the electric utility shall  
notify the applicant of the missed deadline and may grant an extension of 15 business  
days. If the electric utility did not receive the signed standard level 1, 2, and 3  
interconnection agreement and any applicable payment during the 15-business-day  
extension, the electric utility may consider the interconnection application withdrawn  
subject to subrule 3(b) of this rule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, the  
formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446 within the 20 business days, the outcome of that process must  
establish a time frame for the applicant to return the signed interconnection agreement  
and any applicable payment.  
(4) For level 1, 2, or 3 projects, the electric utility shall countersign and provide a  
completed copy of the standard level 1, 2, and 3 interconnection agreement within 130  
business days of the applicant returning the signed standard level 1, 2, and 3  
interconnection agreement and the interconnection application shall proceed to R  
460.966.  
(5) For level 4 or 5 projects, the electric utility shall provide its level 4 and 5  
interconnection agreement, which may include modifications to address any special  
operating conditions, within 3010 business days of reaching this stage. When  
construction of interconnection facilities or distribution upgrades is necessary, the level 4  
and 5 interconnection agreement must contain either estimated timelines for completion  
of activities and estimates of construction costs or a timetable when these requirements  
can be determined. The interconnection agreement must include a payment in advance for  
all estimated costs of interconnection facilities and distribution upgradesschedule that  
corresponds to the milestones established and must require the electric utility to refund  
any unspent and unobligated funds if the agreement is terminated.  
Commented [A68]: Concern: Clarification of advanced  
payment  
Example/Solution: modified language to make advanced  
payment clear.  
Exhibit A  
34  
(6) For an applicant with level 4 or 5 DERs, the applicant shall sign and return with  
payment, if applicable, a level 4 and 5 interconnection agreement within 30 business  
days.  
(a) If the applicant does not sign and return the level 4 and 5 interconnection agreement  
with payment within 30 business days, an electric utility shall notify the applicant of the  
missed deadline and may grant an extension of 15 business days. If the electric utility  
does not receive the signed level 4 and 5 interconnection agreement and payment, if  
applicable, during the 15-business-day extension, the electric utility may consider the  
interconnection application withdrawn, subject to subrule (6)(b) of this rule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or the complaint process pursuant to R 792.10439 to R  
792.10446 within 30 business days, the outcome of that process must establish a time  
frame for the applicant to return the signed interconnection agreement and applicable  
payment. There is a rebuttable presumption in the complaint proceeding that the electric  
utility’s standard construction, procurement, installation, design, and cost practices are  
lawful, reasonable, and prudent.  
(i) For study track interconnection applications filed with an electric utility conducting  
individual studies, electrically coincident applications filed after the interconnection  
application must be placed on hold for not more than 60 business days. If either informal  
mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or the  
complaint process pursuant to R 792.10439 to R 792.10446 does not result in the  
applicant returning a signed interconnection agreement with any applicable payment  
within 60 business days and there are electrically coincident interconnection applications  
in progress behind this application, the electric utility may require the withdrawal of the  
interconnection application.  
(7) For level 4 or 5 projects, an electric utility shall countersign and provide a completed  
copy of the level 4 and 5 interconnection agreement within 10 business days of the  
applicant returning a mutually agreed-upon and signed level 4 and 5 interconnection  
agreement and the interconnection application shall proceed to R 460.966.  
(8) An applicant shall pay the actual cost of the interconnection facilities and  
distribution upgrades. An applicant shall pay, in advance, or through timely payment in  
advance of milestones acceptable to the electric utility, the estimated cost of the  
interconnection facilities and distribution upgrades based upon the electric utility’s  
standard construction, procurement, installation, design, and cost practices The cost to the  
applicant for interconnection facilities and distribution upgrades may not exceed 110% of  
If the cost for interconnection facilities and distribution upgrades exceeds the estimate  
without an itemized summary and by 125% the electric utility shall explain thenation of  
cost increases being provided to the applicant. If the costs are expected to exceed 125%  
of the estimate, the electric utility shall provide further explanation to the applicant prior  
to the costs being incurred. If the applicant does not consent in writing to pay the  
additional costs within 20 business days of receiving further explanation from the electric  
utility, the electric utility shall initiate informal mediation pursuant to R 460.904 no later  
than 5 business days after the conclusion of the 20 business day applicant consent period.  
After payment of all actual costs up to 125% of the estimated costs, tThe applicant may  
dispute the amount by which the estimated expected costs exceed 125% of the estimated  
costs pursuant to either informal mediation pursuant to R 460.904, formal mediation  
Exhibit A  
35  
pursuant to R 460.906, or the complaint process pursuant to R 792.10439 to R 792.10446.  
If there is a dispute, the applicant shall make payment within 30 business days of final  
resolution of the dispute.  
(9) A party’s obligations under the interconnection agreement may be extended by  
agreement. If a party anticipates that it will be unable to meet a milestone for any reason  
other than an unforeseen event, the party shall do all of the following:  
(a) Immediately notify the other party of the reason or reasons for not meeting the  
milestone.  
(b) Propose the earliest alternate date when it can attain this and future milestones.  
(c) Request amendments to the interconnection agreement, if needed to address the  
changed milestones.  
(10) The party affected by the failure to meet a milestone shall not withhold agreement  
to any amendments proposed in subrule (9)(c) of this rule unless 1 of the following  
applies:  
(a) The party affected will suffer significant uncompensated economic or operational  
harm from the amendment or amendments.  
(b) The milestone under question has been previously delayed. (c) The affected party  
has reason to believe that the delay in meeting the milestone is intentional or unwarranted  
notwithstanding the circumstances explained by the party proposing the amendment.  
(11) If the party affected by the failure to meet a milestone disputes the proposed  
extension, the affected party may pursue either informal mediation pursuant to R  
460.904, formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446.  
(12) The electric utility shall provide the applicant with a final accounting report of any  
difference between costs charged to the applicant and previous payments to the electric  
utility for interconnection facilities or distribution upgrades.  
(a) If the costs charged to the applicant exceed its previous aggregate payments, the  
electric utility shall bill the applicant for the amount due and the applicant shall make a  
payment to the electric utility within 20 business days of the final accounting report. The  
applicant may dispute the invoice only for computational errors and amounts that exceed  
125% of the estimated costs pursuant to either informal mediation pursuant to R 460.904,  
formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446. If there is a dispute, the applicant shall make payment within  
30 business days of final resolution of the dispute. Failure by the applicant to pay its costs  
is cause for disconnection of the applicant’s DER and the electric utility may transfer its  
resources to other electric utility work in its management discretion.  
(b) If the applicant’s previous aggregate payments exceed its costs under the  
interconnection agreement, the electric utility shall refund to the applicant an amount  
equal to the difference within 20 business days of the final accounting report.  
(13) The electric utility is responsible for specifying requirements in interconnection  
agreements to support independent system operator regulations or regional transmission  
operator regulations.  
Commented [A69]: Concern: Dispute of costs to be paid  
should relieve the electric utility of the duty to continue  
progress on the project.  
Example: While pursuing facilities construction a portion of  
the project is forced to reroute after permits where denied.  
This results in increased costs that the interconnection  
customer wishes to consider/dispute. The utility may divert  
resources to other projects pending resolution of the dispute.  
(14) The electric utility may propose to the commission that a signed interconnection  
agreement be modified to require compliance with changes to an independent system  
operator, a regional transmission operator, or the state’s regulations, provided that these  
modifications do not alter the rights or obligations of the interconnection customer. Unless  
Solution: Language as modified.  
Exhibit A  
36  
the electric utility has the consent of the applicant or interconnection customer in writing,  
an electric utility shall not modify a signed interconnection agreement without commission  
approval.  
(15) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of customers,  
utility employees, or the general public. An electric utility shall not be prevented from  
testing, studying, or examining a proposed or interconnected DER that threatens the  
reliability of electric service or the safety of customers, utility employees, or the general  
public and any electric utility action pursuant to this right tolls any applicable deadlines  
under these rules until the matter is resolved.  
Commented [A70]: Concern: Clarification that  
inspection, testing and commissioning occur under normal  
operating conditions including the full completion of any  
necessary facility work and required shutdowns.  
R 460.966 Inspection, testing, and commissioning.  
Rule 66. (1) If the interconnection application requires telecommunications, cybersecurity,  
data exchange or remote controls operation, successful testing and certification of these  
items must be completed prior to or during testing. Any required construction, coordination  
or shutdowns as specified in the interconnection agreement shall also be completed. The  
electric utility’s interconnection procedures must describe the technical requirements of  
common items, but site-specific requirements may be included in the interconnection  
agreement including, but not limited to, initial and ongoing obligations for data exchange,  
cybersecurity, telemetry, operational control and protection configuration.  
(2) An applicant shall notify the electric utility when installation of a DER and any  
required local code inspection and approval is complete. The applicant shall provide any  
test reports or configuration documents as defined in the standard level 1, 2, and 3  
interconnection agreement or level 4 and 5 interconnection agreement.  
(3) The electric utility shall review the applicant’s inspection, test reports, or configuration  
documents, and communicate its intent to perform a witness or commissioning test, or  
waive its right to perform a witness test and commissioning test within 10 business days.  
If the electric utility finds the applicant’s inspection, test reports, or configuration  
documents to be incomplete, insufficient, or unsatisfactory, the electric utility shall provide  
its reasons for doing so in writing and the applicant shall have at least 20 business days or  
a mutually agreed to timeframe with the utility, to implement corrections to those  
documents. The applicant, after taking corrective action, shall request the electric utility to  
reconsider its inspection, test reports, or configuration documents.  
(4) Upon the resolution of subrule (3), If the electric utility intends to witness or perform  
commissioning tests required to comply with the interconnection agreement or the  
interconnection procedures and inspect the DER, the electric utility shall witness or  
perform the commissioning tests and inspect the DER within the following:  
Example: Customer requested testing prior to the  
completion of an overhead reconductoring project. As this  
reconductoring might impact the testing, the utility should be  
able to ensure any necessary testing occurs under conditions  
consistent with future operating conditions. Second example:  
customer has a CT enclosure that requires a shutdown to pull  
cables into the enclosure for their testing work to begin.  
Solution: Addition of language to clarify need to test after  
all other work is complete.  
Commented [A71]: Concern: Provide allowance for more  
complex interconnections, or where the applicant has  
internal scheduling constraints such as a production line  
shutdown or multi step construction project.  
Example: PCS system configuration that requires shipping a  
component back to the vendor to reset.  
Solution: provide for a mutually agreeable arrangement as  
an alternative fixed timeline.  
Commented [A72]: Concern: Clarification that timelines  
under section (4) must follow and are not included in section  
(3)  
Example: If in review, the applicant is required to fix a  
deficiency, the problem must be resolved prior to a site visit  
regardless if the utility has indicated that it will perform a  
witness test earlier. Sufficient time must be given to schedule  
this witness test.  
Solution: Section 4 is dependent on the resolution of section  
3.  
(a) Ten business days of receiving the notification from the applicant pursuant to  
completion of subrule (2 &23) of this rule for level 1 applications.  
(b) Twenty business days of receiving the notification from the applicant pursuant to  
completion of subrule (2 &23) of this rule for level 2 and level 3 applications.  
Commented [A73]: Concern: Clarity around identifying  
when timelines begin.  
Example/Solution: If an incomplete test record is provided  
and the utility elects to witness follow on testing the 10 days  
starts once the testing gap has been resolved.  
Exhibit A  
37  
(c) A mutually-agreed upon timeframe after receiving the notification from the  
applicant pursuant to completion of subrule (2 & 3) of this rule for level 4 and 5  
applications.  
(5) The electric utility may waive its right to visit the site and inspect the DER or  
perform the commissioning tests.  
(a) If the electric utility waives this right, it shall provide a written waiver to the  
applicant within 10 business days from receiving the notification from the applicant  
pursuant to subrule (2) of this rule.  
(b) The applicant shall provide the electric utility with the completed commissioning  
test report within 20 business days of receipt of the electric utility’s written waiver.  
(6) If the electric utility attempts to conduct the inspection and testing pursuant to  
subrule (4) of this rule at the arranged time and is unable to access the DER or complete  
the testing, the DER must remain disconnected until the applicant and the electric utility  
can complete the inspection and testing.  
(7) If the electric utility witnessed or performed commissioning tests and inspected the  
DER pursuant to subrule (4) of this rule, within 5 business days of the receipt of the  
completed commissioning test report, the electric utility shall notify the applicant whether  
it has accepted or rejected the commissioning test report and found the site to be  
satisfactory or unsatisfactory.  
(a) If the commissioning test report is accepted and the site was found satisfactory, the  
electric utility shall provide the notification of acceptance in writing, and the  
interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report or did not find the site  
satisfactory, the electric utility shall provide its reasons for doing so in writing and the  
applicant has not less than 20 business days to implement corrections. The applicant, after  
taking corrective action, shall request the electric utility to reconsider its findings. The  
applicant may be billed the actual cost of any re-inspections.  
(8) If the electric utility waived its right to witness or perform commissioning tests and  
inspect the DER pursuant to subrule (5) of this rule, within 5 business days of the receipt  
of the completed commissioning test report, the electric utility shall notify the applicant  
whether it has accepted or rejected the commissioning test report.  
(a) If the commissioning test report is accepted, the electric utility shall provide  
notification of acceptance, and the interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report, the electric utility shall  
provide its reasons for doing so in writing and the applicant has not less than 20 business  
days to implement corrections. The applicant, after taking corrective action, may then  
request the electric utility to reconsider its findings.  
(9) The cost of testing and inspection for applicants participating in an electric utility’s  
distributed generation program, as described in part 3 of these rules, R 460.1001 to R  
460.1026, are considered a cost of operating a distributed generation program and must  
be recovered pursuant to section 175(1) of the clean and renewable energy and energy  
waste reduction act, 2008 PA 295, MCL 460.1175.  
(10) If the applicant does not notify the electric utility that the DER is installed and  
ready to test pursuant to subrule (2) of this rule, the electric utility may, in writing, query  
the status of the interconnection. If the applicant does not provide a written response  
Exhibit A  
38  
within 10 business days or no progress is evident, the electric utility may consider the  
interconnection application withdrawn.  
(11) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.968 Authorization required prior to parallel operation.  
Rule 68. (1) The electric utility shall provide to the applicant written authorization to  
operate in parallel with the electric utility within 5 business days of all of the following  
conditions being met:  
(a) The electric utility notified the interconnection applicant that the commissioning test  
and inspection, where applicable, are accepted.  
(b) The applicant executed the parallel operating agreement required by the electric  
utility and complied with all applicable parallel operation requirements as set forth in the  
electric utility’s interconnection procedures and applicable interconnection agreement.  
(c) The applicant complied with all applicable local, state, and federal requirements.  
(d) The electric utility received full payments for all outstanding bills.  
(2) With the written authorization, interconnection of the DER is considered approved  
for parallel operation, the DER may begin operating, and the applicant is considered an  
interconnection customer.  
Commented [A74]: Concern: clarification that the  
parallel operating agreement must be executed and complied  
with.  
Example/Solution: language modified to reflect execution  
of agreement.  
(3) The applicant shall not operate its DER in parallel with the electric utility’s  
distribution system without prior written permission to operate from the electric utility.  
(4) Subject to reasonable timing and other conditions, including completion of  
conditions in the interconnection agreement or interconnection procedures, the electric  
utility shall allow for reasonable but limited testing before written authorization has  
occurred.  
(5) should the interconnection customer at any time fail to continue to meet these  
conditions or meet conditions set forth in R 460.978 the utility shall disconnect the  
customer until such time as the conditions are met to the utility's satisfaction  
(6) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
Commented [A75]: Concern: Adding clarity that  
authorization for parallel operation does not prevent the  
utility from disconnecting a DER if it is later discovered to  
not be meeting the conditions of the agreement.  
Example: A project is discovered to have fallen out of  
technical compliance after reconfiguring their system  
operating practices.  
Solution: language to ensure the utility right to disconnect  
and perform all necessary testing to ensure future  
compliance with parallel operating agreement and safety and  
reliability of the electrical grid.  
Exhibit A  
39  
R 460.970 Cost allocation of interconnection facilities, distribution upgrades, and  
associated operation and maintenance costs.  
Rule 70. Costs for interconnection facilities, distribution upgrades, and associated  
operation and maintenance costs must be classified into 1 of the following categories:  
(a) Site-specific costs, which include, but are not limited to, costs of interconnection  
facilities and distribution upgrades that are caused by 1 DER, whether that DER is  
electrically co-incident with other DERs or not. These costs must be assigned to the cost-  
causing applicant.  
(b) Shared interconnection facilities costs, which are costs caused by DERs which  
together necessitate the construction of interconnection facilities. The interconnection  
facilities costs, including any associated operation and maintenance costs, that should be  
shared must be allocated to each applicant based on a methodology described in the  
electric utility’s interconnection procedures.  
(c) Shared distribution upgrade costs, which are costs caused by electrically co-incident  
DERs that together necessitate a distribution upgrade. The distribution upgrade costs,  
including any associated operation and maintenance costs, that should be shared must be  
allocated to each applicant based on a methodology described in the electric utility’s  
interconnection procedures.  
R 460.974 Interconnection metering and communications.  
Rule 74. (1) Any metering and communications requirements necessitated by use of the  
DER must be installed at the applicant’s expense. The electric utility may furnish this  
equipment at the applicant’s expense.  
(2) The electric utility may charge the interconnection customer reasonable ongoing fees  
to maintain the metering and communications equipment. These fees must be listed in the  
interconnection agreement.  
R 460.976 Post commissioning remedy.  
Rule 76. (1) If the electric utility finds that the DER is operating outside the terms of the  
interconnection agreement but does not find immediate disconnection pursuant to R  
460.978(1)(f) and (g) warranted, the electric utility shall promptly inform the  
interconnection customer or its agent of this finding. The interconnection customer is  
responsible for bringing the DER into compliance within 30 business days or a mutually  
agreed-upon time period. The electric utility may perform an inspection of the DER after  
a remedy is applied.  
(2) If the DER is not brought into compliance within 30 business days or the mutually  
agreed-upon time period, the electric utility may apply a remedy and bill the  
interconnection customer. The interconnection customer shall pay this bill within 5  
business days.  
R 460.978 Disconnection.  
Rule 78. (1) An electric utility may refuse to connect or may disconnect a project from  
the distribution system if any of the following conditions apply:  
Exhibit A  
40  
(a) Failure of the interconnection customer to bring a DER into compliance pursuant to  
R 460.976(1).  
(b) Failure of the interconnection customer to pay costs of remedy pursuant to R  
460.976(2).  
(c) Termination of interconnection by mutual agreement.  
(d) Distribution system emergency, but only for the time necessary to resolve the  
emergency.  
(e) Routine maintenance, repairs, and modifications performed in a reasonable time and  
with prior notice to the interconnection customer.  
(f) Noncompliance with technical or contractual requirements in the interconnection  
agreement that could lead to degradation of distribution system reliability, electric utility  
equipment, and electric customers’ equipment.  
(g) Noncompliance with technical or contractual requirements in the interconnection  
agreement that presents a safety hazard.  
(h) Other material noncompliance with the interconnection agreement.  
(i) Operating in parallel without prior written authorization from the electric utility as  
provided for in R 460.968.  
(2) An electric utility may disconnect electric service, where applicable, pursuant to R  
460.136.  
(3) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.980 Capacity of the DER.  
Rule 80. (1) If the interconnection application requests an increase in capacity for an  
existing DER, the electric utility shall evaluate the application based on the new ongoing  
operatingaggregate nameplate capacity of the DER. The maximum capacity of a DER is  
the aggregate nameplate capacity or may be limited as described in the electric utility’s  
interconnection procedures, subject to subsection (4)(g).  
(2) An interconnection application for a DER that includes single or multiple types of  
DERs at a site for which the applicant seeks a single point of common coupling must be  
evaluated as described in the electric utility’s interconnection procedures, subject to  
subsection (4)(g).  
(3) The electric utility’s interconnection procedures must include acceptable methods  
for power limited export DER so that the DER capacity considered by the electric utility  
for reviewing the interconnection application is only the amount capable of being  
exported, subject to subsection (4)(g). The utility may require back up methods or  
redundant schemes to mitigate any failure of these methods.  
Commented [A76]: Concern: needs clarification to  
ensure that a capacity change is processed consistently with  
how a new application would be processed.  
Solution: Project is reviewed at nameplate capacity and  
limited export will be considered, but must maintain safety,  
reliability and compliance with tariffs and programs.  
Commented [A77]: Concern: The level of protection and  
operating expectations of a DER for component failure  
should be consistent with the risk of a mis-operation.  
Example: a larger generator may be required to provide  
additional relaying to isolate the generator in the event of a  
breaker failure.  
(4) An electric utility shallmay allow interconnection of limited-export or non-exporting  
DERs according to this subrule subject to the electric utility’s rights under subsection  
Solution: Make it explicit that utility grade protection and  
redundance practices are applicable to the interconnection  
customers as well.  
Exhibit A  
41  
(4)(g). If a DER uses any configuration or operating mode in this subrule to limit the  
export of electrical power across the point of common coupling, then the generating  
export capacity shall be only the amount capable of being exported not including any  
inadvertent export. To prevent impacts on system safety and reliability, any inadvertent  
export from a DER must comply with the limits in subdivisions (e) or (f) of this subrule.  
The generating export capacity specified by the applicant in the application will  
subsequently be included as a limitation in the interconnection agreement. Other means  
not listed in this subrule may be utilized to limit export if mutually agreed upon by the  
electric utility and applicant.  
(a) To ensure power is never exported across the point of common coupling, a utility  
grade reverse power protective function may be provided. The default setting for this  
protective function shall be 0.1%not exceed export of the service transformer’s rating  
when including the total metering accuracy, with a maximum 2.0 second time delay. or as  
determined by study.  
(b)To ensure at least a minimum amount of power is imported across the point of  
common coupling at all times and, therefore, that power is not exported, an under-power  
protective function may be provided. The default setting for this protective function shall  
be 5% import of the DER’s total nameplate rating, with a maximum 2.0 second time  
delay or as determined by study.  
(c)This option requires the nameplate rating of the DER, minus any auxiliary load, to  
be so small in comparison to its host facility’s minimum load that the use of additional  
protective functions is not required to ensure that power will not be exported to the  
distribution system. This option requires the DER capacity to be no greater than 5030%  
of the applicant’s verifiable minimum host load over the past 12 months and shall include  
provisions to automatically curtail the exported power in any case that this minimum load  
is reduced further.  
Commented [A78]: Concern: modified language to  
ensure utility grade equipment, compliance with non-export  
function, account for metering capability, and provide  
allowance for maximum delay to be reduced based on study  
results without requiring system upgrades necessary to  
support maximum delay.  
Example: the protective relay setting for a reverse power  
relay should default to zero export, and if a reaction time  
below 2 seconds is required for protective coordination, that  
delay should be provided by the study.  
(d) A reduced output rating utilizing the power rating configuration setting may be  
used to ensure the DER does not generate power beyond a certain value lower than the  
nameplate rating.  
Solution: language as modified in (4a) and (4b)  
Commented [A79]: Concern: Minimum verifiable load  
is a dynamic value and should adjust as the customer  
removes load or increases energy efficiency.  
(e) DERs may utilize, a nationally recognized testing laboratory certified power  
control system and inverter system that results in the DER disconnecting from the  
distribution system, ceasing to energize the distribution system or halting energy  
production within 2 seconds (or shorter as determined by study) if the period of  
continuous inadvertent export exceeds 30 2 seconds. Failure of the control or inverter  
system for more than 30 2 seconds, resulting from loss of control or measurement signal,  
or loss of control power, must result in the DER immediately entering an operational  
mode where no energy is exported across the point of common coupling to the  
distribution systemthe DER disconnects from the utility system and cannot return to  
service until the loss of control or measurement signal is or control power is corrected  
and authorization is received from the utility to reconnect. The owner of a DER utilizing  
a certified power control system and inverter system described in this section shall obtain  
insurance in the amount of $10 million with respect to the DER, shall name the electric  
utility to which it is interconnected as an additional named insured, shall indemnify the  
electric utility to which it is interconnected for any and all damage and injury to electric  
utility personnel and property, and shall indemnify the electric utility to which it is  
interconnected for any and all third party claims, losses, damages, costs, charges,  
Solution: Language as modified  
Exhibit A  
42  
expenses, liens, settlements or judgments, including interest thereon, arising directly or  
indirectly out of operation of the DER.  
Commented [A80]: Concern: UL 1741 PCS limitations  
only apply to the device which is certified. Any inadvertent  
export capability must also be reviewed against system  
conditions and grid capabilities. Failure to follow agreed  
export limits should result in cessation of operation and  
disconnection until control issues are resolved.  
(f) DERs may be designed with other control systems or protective functions, or both,  
to limit export and inadvertent export to levels mutually agreed upon by the applicant and  
the electric utility. The limits may be based on technical limitations of the applicant’s  
equipment or the distribution system’s equipment. To ensure inadvertent export remains  
within mutually agreed-upon limits, the applicant shall use an internal transfer relay,  
energy management system, or other customer facility hardware or software.  
(f)(g)Nothing in these rules shall be construed to foreclose an electric utility’s right to  
test, study, examine, and if appropriate in the judgment of the electric utility not connect  
or disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
Example: A large DER offsetting a large load, experiences a  
loss of load resulting in the DER reaching its UL limit of  
110% (132V) at the point of interconnection, utility  
distribution equipment which was compensating for low  
voltage prior to the inadvertent export event was set for 5%  
raise taking the distribution system to 115% or 138V, which  
would not be allowed to exist for 30 seconds by UL 1741 or  
any other industry standard.  
Solution: Adjusted duration to 2 seconds to be consistent  
with industry standards for loss of export control, provide  
carveout for faster operation to limit potential need for  
upgrades, and add clarification on liability for failure to  
control export to as agreed to in agreements.  
R 460.982 Modification of the interconnection application.  
Rule 82. (1) At any point after an interconnection application is considered accepted  
but before the signing of an interconnection agreement, the applicant, the electric utility,  
or the affected system owner may propose modifications to the interconnection  
application that may improve the costs and benefits of the interconnection, or that  
improve the ability of the electric utility to accommodate the interconnection. The  
applicant shall submit to the electric utility, in writing, all proposed modifications to any  
information provided in the interconnection application and the electric utility shall  
perform an evaluation to determine whether the proposed modification is a material  
modification and provide the results to the applicant within 10 business days.  
(2) The electric utility shall not be required to accept or implement a modification to the  
electric utility’s distribution system or generation assets that is proposed by an applicant or  
affected system operator.  
(3) The applicant may request a 1-hour consultation to discuss the results of the material  
modification review.  
(4) Neither the electric utility nor the affected system operator may unilaterally modify  
an accepted interconnection application. If the electric utility evaluates DERs using  
individual studies, the timelines specific to that interconnection application must be  
placed on hold while the proposed modification is being evaluated by the electric utility.  
(5) For a proposed modification which the electric utility has determined is a material  
modification and that further study is required, the applicant shall select 1 of the  
following options:  
(a) Withdraw the modification.  
(b) Withdraw the application.  
(c) Propose a different modification to the interconnection application for electric  
utility review pursuant to subrule (1) of this rule to determine whether the modification is  
material.  
Exhibit A  
43  
(d) If the electric utility offers an expedited study of the application with the proposed  
material modification, the applicant may request the expedited study. If the electric  
utility offers an expedited study, the process of performing an expedited study must be  
described in the electric utility’s interconnection procedures.  
(e) Initiate informal mediation pursuant to R 460.904  
(f) Initial formal mediation pursuant to R460.906  
(g) File a complaint pursuant to R 792.10439 to R 792.10446.  
(6) The applicant shall notify the electric utility of its selection pursuant to subrule (5) of  
this rule within 10 business days of receiving the electric utility notification of the results  
or the modification may be considered withdrawn.  
(7) For a proposed modification which the electric utility has determined is a material  
modification, but which does not require further study, the electric utility shall continue  
processing the interconnection application according to these rules.  
(8) Any modification to the interconnection application that could affect the operation  
of the distribution system, including but not limited to, changes to machine data,  
equipment configuration, or the interconnection site of the DER, not agreed to in writing  
by the electric utility and the applicant may be treated by the electric utility as a  
withdrawal of the interconnection application requiring submission of a new  
interconnection application.  
(9) At any point prior to the execution of an interconnection agreement, changes to  
ownership will cause the interconnection application to be put on hold until the new  
owner signs all necessary agreements and documents. An electric utility may not be  
found in violation of these rules related to the processing of the interconnection  
application during such a transfer of ownership.  
(10) The electric utility’s interconnection procedures must provide a procedure for  
performing a material modification review.  
R 460.984 Modifications to the DER.  
Rule 84. After the execution of the interconnection agreement, the applicant shall notify  
the electric utility of any plans to modify the DER. The electric utility shall review the  
proposed modification to determine if the modification is considered a material  
modification. If the electric utility determines that the modification is a material  
modification, the electric utility shall notify the applicant, in writing of its determination  
and the applicant shall submit a new application and application fee along with all  
supporting materials that are reasonably requested by the electric utility. The applicant  
may not begin any material modification to the DER until an interconnection agreement  
incorporating the material modification is fully executed. Nothing in these rules shall be  
construed to foreclose an electric utility’s right to test, study, examine, and if appropriate  
in the judgment of the electric utility not connect or disconnect a DER that threatens the  
reliability of electric service or the safety of customers, utility employees, or the general  
public. An electric utility shall not be prevented from testing, studying, or examining a  
proposed or interconnected DER that threatens the reliability of electric service or the  
safety of customers, utility employees, or the general public and any electric utility action  
pursuant to this right tolls any applicable deadlines under these rules until the matter is  
resolved.  
Exhibit A  
44  
R 460.986 Insurance.  
Rule 86. (1) An applicant interconnecting a level 1 or 2 project to the distribution  
system of an electric utility may not be required by the electric utility to obtain any  
additional liability insurance.  
(2) An electric utility shall not require an applicant interconnecting a level 1 or 2 project  
to name the electric utility as an additional insured party.  
(3) For a level 3 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $1,000,000.  
(4) For a level 4 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $2,000,000.  
(5) For a level 5 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $3,000,000.  
(6) For level 3, 4, and 5 projects, the electric utility may describe in its interconnection  
procedures required terms and conditions which must be specified in the general liability  
insurance.  
R 460.988 Easements and rights-of-way.  
Rule 88. If an electric utility line extension is required to accommodate an  
interconnection, the applicantelectric utility is responsible for providing and obtaining  
easements or rights-of-way. The applicant is responsible for the cost of providing and  
obtaining easements or rights-of-way.  
Commented [A81]: Concern: This is not consistent with  
current tariff where customers provide easements.  
Solution: Applicants should obtain easements according to  
specifications provided by the utility.  
R 460.990 Interconnection penalties.  
Rule 90. Pursuant to section 10e of 1939 PA 3, MCL 460.10e, an electric utility shall  
take all necessary steps to ensure that DERs are connected to the distribution systems  
within their operational control. If the commission finds, after notice and hearing, that an  
electric utility has prevented or unduly delayed the ability of a DER greater than 100 kW  
to connect to the distribution system of the electric utility, the commission may order  
remedies designed to make whole the applicant proposing the DER, including, but not  
limited to, reasonable attorney fees. If the electric utility violates this rule, the  
commission may order fines of not more than $50,000 per day, commensurate with the  
demonstrated impact of the violation.  
R 460.991 Business day exclusions.  
Rule 91. An electric utility shall notify the commission and all applicants that have in-  
process applications when timelines are being extended due to a day in which electric  
service is interrupted for 10% or more of an electric utility’s customers pursuant to R  
460.901a(k). The electric utility shall also notify the commission and all applicants that  
have in-process applications when application processing resumes.  
R 460.992 Electric utility annual reports.  
Exhibit A  
45  
Rule 92. An electric utility shall file an annual interconnection report on a date and in a  
format determined by the commission.  
PART 3. DISTRIBUTED GENERATION PROGRAM STANDARDS  
R 460.1001 Application process.  
Rule 101. (1) An electric utility shall file initial distributed generation program tariff  
sheets in the first rate case filed after June 1, 2018.  
(2) Within calendar 30 days of a commission order approving an electric utility’s initial  
distributed generation tariff, or within 30 calendar days of the effective date of these  
rules, whichever is later, an alternative electric supplier serving customers in that electric  
utility’s service territory shall file an updated distributed generation program plan  
applicable to its customers in the affected electric utility’s service territory.  
(3) An electric utility and an alternative electric supplier shall annually file a legacy net  
metering program report and, if applicable, a distributed generation program report not  
later than March 31 of each year.  
(4) An electric utility and an alternative electric supplier shall maintain records of all  
applications and up-to-date records of all eligible electric generators participating in the  
legacy net metering program and distribution generation program.  
(5) Selection of customers for participation in the legacy net metering program or  
distributed generation program must be based on the order in which the applications are  
received.  
(6) An electric utility or alternative electric supplier shall not refuse to provide or  
discontinue electric service to a customer solely because the customer participates in the  
legacy net metering program or distributed generation program.  
(7) The legacy net metering program and distributed generation program provided by  
electric utilities and alternative electric suppliers must be designed for a period of not less  
than 10 years and limit each applicant to generation capacity designed to meet up to  
100% of the customer’s electricity consumption for the previous 12 months.  
(a) The generation capacity must be determined by an estimate of the expected annual  
kWh output of the generator or generators as determined in an electric utility’s  
interconnection procedures and specified on an electric utility's legacy net metering  
program or distributed generation program tariff sheet or in the alternative electric  
supplier’s legacy net metering program or distributed generation program plan. For  
projects in which energy export controls are implemented pursuant to section R 460.980  
and utilized to limit the export to 100% of the customer’s electricity consumption for the  
previous 12 months, an electric utility shall not add the storage capacity to generation  
capacity for the purpose of the study. If a customer has multiple inverters capable of  
exporting to the distribution grid, the inverters must be configured in a way that prevents  
the cumulative maximum export at any given time to exceed the approved amount in the  
customer’s application.  
(b) A customer’s electric consumption must be determined by 1 of the following  
methods:  
Exhibit A  
46  
(i) The customer’s annual energy consumption, measured in kWh, during the previous  
12-month period.  
(ii) If there is no data, incomplete data, or incorrect data for the customer’s energy  
consumption or the customer is making changes on-site that will affect total  
consumption, the electric utility or alternative electric supplier and the customer shall  
mutually agree on a method to determine the customer’s electric consumption.  
(c) A net metering or distributed generation customer using an energy storage device in  
conjunction with an eligible electric generator shall not design or operate the energy storage  
device in a manner that results in the customer’s electrical output exceeding 100% of the  
customer’s electricity consumption for the previous 12 months. The addition of an energy  
storage device to an existing approved legacy net metering program system or distributed  
generation program system is considered a material modification. The electric utility  
interconnection procedures must include details describing how energy storage equipment  
may be integrated into an existing legacy net metering program system without impacting  
the 10-year grandfathering period or participation in the distributed generation program.  
(8) An applicant shall notify the electric utility of plans for any material modification to  
the project. An applicant shall re-apply for interconnection pursuant to part 2 of these  
rules, R 460.911 to R 460.992, and submit revised legacy net metering program or  
distributed generation program application forms and associated fees. An applicant may  
be eligible to continue participation in the legacy net metering program or distributed  
generation program when a material modification is made to a customer’s previously  
approved system and it does not violate the requirements of subrule (7) of this rule or R  
460.1026. An applicant shall not begin any material modification to the project until the  
electric utility has approved the revised application, including any necessary system  
impact study or facilities study. The application must be processed pursuant to part 2 of  
these rules, R 460.911 to R 460.992.  
(9) Nothing in these rules shall be construed to foreclose an electric utility’s right to test,  
study, examine, and if appropriate in the judgment of the electric utility not connect or  
disconnect a DER that threatens the reliability of electric service or the safety of  
customers, utility employees, or the general public. An electric utility shall not be  
prevented from testing, studying, or examining a proposed or interconnected DER that  
threatens the reliability of electric service or the safety of customers, utility employees, or  
the general public and any electric utility action pursuant to this right tolls any applicable  
deadlines under these rules until the matter is resolved.  
R 460.1004 Legacy net metering program application and fees.  
Rule 104. (1) An electric utility or alternative electric supplier may use an online legacy  
net metering program application process. An electric utility or alternative electric  
supplier not using an online application process, may utilize a uniform legacy net  
metering program application form which must be approved by the commission. An  
electric utility’s legacy net metering program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the legacy net metering program shall concurrently submit a completed  
legacy net metering program application and interconnection application or indicate on  
Exhibit A  
47  
the legacy net metering program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968.  
(a) Where a legacy net metering program application is accompanied by an associated  
interconnection application, an electric utility shall complete its review of the legacy net  
metering program application in parallel with processing the interconnection application  
pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, the electric utility shall notify the customer whether  
the legacy net metering program application is accepted, and provide an opportunity for  
the customer to resolve any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application, or the electric utility may consider the legacy  
net metering program application withdrawn without refund of the application fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.946 fast track initial review, the electric utility shall determine whether  
the appropriate meter or meters, is installed for the legacy net metering program.  
(b) When a legacy net metering program application is filed with an already in-progress  
interconnection application, the utility may process the legacy net metering application in  
parallel with the interconnection application pursuant to part 2 of these rules, R 460.911  
to R 460.992, and subrule (2)(a) of this rule, if practicable, or adopt the review process  
pursuant to subrule (2)(c) of this rule.  
(c) When a legacy net metering program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the legacy net metering program application in parallel with the interconnection  
application, or when the legacy net metering application is filed subsequent to the  
customer receiving authorization to operate its eligible generator in parallel pursuant to R  
460.968, the electric utility shall process the legacy net metering program application  
pursuant to both of the following:  
(i) The electric utility shall review the legacy net metering program application and  
determine whether to accept the application pursuant to the timelines in R 460.936(6) and  
(7) within 10 business days. The timelines in R 460.936(7)(a) apply to electric utility  
notifications. The electric utility shall provide the customer an opportunity to resolve any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
deficiency within the timelines pursuant to R. 460.936(7)(b), the electric utility may  
consider the legacy net metering application withdrawn without refund of the application  
fees.  
(ii) Within 10 business days of notifying the customer that the legacy net metering  
application has been accepted, the electric utility shall determine whether the appropriate  
meter is installed for the legacy net metering program.  
(d) If a customer approved for participation in the legacy net metering program requires  
a new or additional meter or meters, the electric utility shall arrange with the customer to  
install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit the  
legacy net metering program credit to be applied to the account no more than 10 business  
days after the necessary meter is installed and all necessary steps in R 460.966 are  
completed.  
Exhibit A  
48  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed legacy net metering program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The electric utility shall process the legacy net metering program application  
according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit the legacy net  
metering program credit to be applied to the account.  
(4) If a legacy net metering program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the deficiency  
within the timelines pursuant to R. 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the legacy net metering application withdrawn without  
refund of the application fees.  
(5) If a customer’s application for the legacy net metering program is approved, the  
customer shall have a completed and approved installation within 6 months from the date  
the customer’s application is considered complete, or the electric utility or alternative  
electric supplier may terminate the application without refund and shall have no further  
responsibility with respect to the application.  
(6) Customers participating in a legacy net metering program approved by the  
commission before the commission establishes a tariff pursuant to section 6a(14) of 1939  
PA 3, MCL 460.6a, may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment.  
(7) The legacy net metering program application fee for electric utilities and alternative  
electric suppliers may not exceed $50. The fee must be specified on the electric utility’s  
legacy net metering tariff sheet or in the alternative electric supplier's legacy net metering  
program plan.  
R 460.1006 Distributed generation program application and fees.  
Rule 106. (1) An electric utility or alternative electric supplier may use an online  
distributed generation program application process. An electric utility or alternative  
electric supplier not using an online application process may utilize a uniform distributed  
generation program application form that must be approved by the commission. An  
electric utility’s distributed generation program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the distributed generation program shall concurrently submit a completed  
distributed generation program application and interconnection application or indicate on  
the distributed generation program application the date that the customer applied for  
Exhibit A  
49  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968.  
(a) When a distributed generation program application is accompanied by an associated  
interconnection application, an electric utility may complete its review of the distributed  
generation program application concurrently, before, or after processing the  
interconnection application pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, an electric utility shall notify the customer whether  
the distributed generation program application is accepted, and provide an opportunity for  
the customer to remedy any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the electric utility may consider the  
distributed generation program application withdrawn without refund of the application  
fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.946 fast track initial review, the electric utility shall determine whether  
the appropriate meter is installed for the distributed generation program.  
(b) If a distributed generation program application is filed with an already in-progress  
interconnection application, the electric utility may process the distributed generation  
program application in parallel with the interconnection application pursuant to part 2 of  
these rules, R 460.911 to R 460.992, and subrule (2)(a) of this rule, if practicable, or  
adopt the review process pursuant to subrule (2)(c) of this rule.  
(c) If a distributed generation program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the distributed generation program application in parallel with the  
interconnection application or the distributed generation application is filed subsequent to  
the customer receiving authorization to operate its eligible generator in parallel pursuant  
to R 460.968, the electric utility shall process the distributed generation program  
application pursuant to all of the following:  
(i) The electric utility has 10 business days to review the distributed generation  
program application and determine whether to accept the application pursuant to the  
timelines in R 460.936(6) and (7). The timelines in R 460.936(7)(a) apply to utility  
notifications. The electric utility shall provide the customer an opportunity to remedy any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
application deficiencies within the timelines in R 460.936(7)(b), the electric utility may  
consider the distributed generation program application withdrawn without refund of the  
application fees.  
(ii) Within 10 business days of providing notification to the customer that the  
distributed generation program application has been accepted, the electric utility shall  
determine whether the appropriate meter, or meters, is installed for the distributed  
generation program.  
(d) If a customer approved for participation in the distributed generation program  
requires a new or additional meter or meters, the electric utility shall arrange with the  
customer to install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit  
distributed generation program credit to be applied to the account no more than 10  
Exhibit A  
50  
business days after the necessary meter is installed and all necessary steps in R 460.966  
are completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed distributed generation program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The alternative electric supplier shall process the distributed generation program  
application according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit distributed generation  
program credit to be applied to the account.  
(4) If a distributed generation program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the distributed generation program application withdrawn  
without refund of the application fees.  
(5) If a customer’s distributed generation program application is approved, the customer  
shall have a completed and approved installation within 6 months from the date the  
customer’s application is considered complete, or the electric utility or alternative electric  
supplier may consider the application withdrawn without refund and shall have no further  
responsibility with respect to the application.  
(6) The distributed generation program application fee for electric utilities and  
alternative electric suppliers shall not exceed $50. The electric utility shall specify the fee  
on the electric utility’s distributed generation program tariff sheet or in the alternative  
electric supplier’s distributed generation program plan.  
(7) The customer shall pay all interconnection costs pursuant to part 2 of these rules, R  
460.911 to R 460.992, which include all electric utility costs associated with the  
customer’s interconnection that are not a distributed generation program application fee,  
excluding meter costs as described in R 460.1012 and R 460.1014.  
R 460.1008 Legacy net metering program and distributed generation program size.  
Rule 108. (1) If an electric utility or alternative electric supplier reaches the program  
sizes as defined in section 173(3) of the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1173 or a voluntarily expanded program above the  
requirements defined in section 173(3) of the clean and renewable energy and energy  
waste reduction act, 2008 PA 295, MCL 460.1173, as determined by combining both the  
distributed generation program and the legacy net metering program customer  
enrollments, the electric utility or alternative electric supplier shall notify the  
commission.  
Exhibit A  
51  
(2) The electric utility or alternative electric supplier shall notify the commission of its  
plans to either close the program to new applicants or expand the program.  
(3) The electric utility shall file corresponding revised legacy net metering program or  
distributed generation program tariff sheets.  
(4) The alternative electric supplier shall file a revised legacy net metering program plan  
or distributed generation program plan.  
R 460.1010 Generation and legacy net metering program or distributed generation  
program equipment.  
Rule 110. New legacy net metering program or distributed generation program  
equipment and its installation must meet all current local and state electric and  
construction code requirements, and other standards as specified in part 2 of these rules,  
R 460.911 to R 460.992.  
R 460.1012 Meters for legacy net metering program.  
Rule 112. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility may determine the customer’s net usage using the customer’s  
existing meter if it is capable of reverse registration or may install a single meter with  
separate registers measuring power flow in each direction. If the electric utility uses the  
customer’s existing meter, the electric utility shall test and calibrate the meter to assure  
accuracy in both directions. If the customer’s meter is not capable of reverse registration  
and if meter upgrades or modifications are required, the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to the legacy net metering program customer. The cost of the meter or  
meter modification is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for the meter provided by the electric utility  
to similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter, if requested by the customer, at  
cost.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, the electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide this functionality, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a legacy net metering program customer. The cost of the meter or  
meters is considered a cost of operating the legacy net metering program.  
Exhibit A  
52  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for meters provided by the electric utility to  
similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter is  
considered a cost of operating the legacy net metering program.  
(3) For a customer with a generation system capable of generating more than 150 kWac,  
the electric utility shall utilize a meter or meters capable of measuring the flow of energy  
in both directions and the generator output. If meter upgrades are necessary to provide  
this functionality, the customer shall pay the cost of providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a legacy net metering program participant or the legacy net  
metering program.  
R 460.1014 Meters for distributed generation program.  
Rule 114. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility shall determine the customer’s power flow in each direction  
using the customer's existing meter if it is capable of measuring and recording power  
flow in each direction. If the customer’s meter is not capable of measuring and recording  
the customer’s power flow in each direction and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring and recording the customer’s power flow in each  
direction at no additional charge to the distributed generation program customer. The cost  
of the meter or meter modification is considered a cost of operating the distributed  
generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring and recording the power flow in each direction to  
customers at cost. Only the incremental cost above the cost for the meter provided by the  
electric utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter at cost, if requested by the  
customer.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring and recording power flow in each direction and the generator output. If the  
customer’s meter is not capable of measuring and recording the customer’s power flow in  
each direction along with the generator output, and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a distributed generation program customer. If the electric utility  
provides the upgraded meter at no additional charge to the customer, the cost of the meter  
is considered a cost of operating the distributed generation program.  
Exhibit A  
53  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above the cost for the meter provided by the electric  
utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter shall be  
considered a cost of operating the distributed generation program.  
(3) For a customer with a methane digester generation system capable of generating  
more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide such functionality, the customer shall pay the cost of  
providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a distributed generation program customer or the distributed  
generation program.  
R 460.1016 Billing and credit for legacy net metering program customers taking service  
under true net metering.  
Rule 116. (1) Legacy net metering program customers with a system capable of  
generating 20 kWac or less qualify for true net metering. For customers qualifying for  
true net metering, the net of the bidirectional flow of kWh across the customer  
interconnection with the electric utility distribution system during the billing period or  
during each time-of-use pricing period within the billing period, including excess  
generation, shall be credited at the full retail rate.  
(2) The credit for excess generation, if any, shall appear on the next bill. Any excess  
credit not used to offset current charges must be carried forward for use in subsequent  
billing periods.  
R 460.1018 Billing and credit for legacy net metering program customers taking service  
under modified net metering.  
Rule 118. (1) Legacy net metering program customers with a system capable of  
generating more than 20 kWac qualify for modified net metering. A negative net metered  
quantity during the billing period or during each time-of-use pricing period within the  
billing period reflects net excess generation for which the customer is entitled to receive  
credit. Standby charges for customers on an energy rate schedule must equal the retail  
distribution charge applied to the imputed customer usage during the billing period. The  
imputed customer usage is calculated as the sum of the metered on-site generation and  
the net of the bidirectional flow of power across the customer interconnection during the  
billing period. The commission shall establish standby charges for customers on demand-  
based rate schedules that provide an equivalent contribution to electric utility system  
costs. Standby charges may not be applied to customers with systems capable of  
generating 150 kWac or less.  
Exhibit A  
54  
(2) The credit for excess generation must appear on the next bill. Any excess kWh not  
used to offset current charges must be carried forward for use in subsequent billing  
periods.  
(3) A customer qualifying for modified net metering shall not have legacy net metering  
program credits applied to distribution charges.  
(4) The credit per kWh for kWh delivered into the electric utility’s distribution system  
must be either of the following as determined by the commission:  
(a) The monthly average real-time locational marginal price for energy at the  
commercial pricing node within the electric utility’s distribution service territory or for a  
legacy net metering program customer on a time-based rate schedule, the monthly  
average real time locational marginal price for energy at the commercial pricing node  
within the electric utility’s distribution service territory during the time-of-use pricing  
period.  
(b) The electric utility’s or alternative electric supplier’s power supply component,  
excluding transmission charges, of the full retail rate during the billing period or time-of-  
use pricing period.  
R 460.1020 Billing and credit for distributed generation program customers.  
Rule 120. As part of an electric utility’s rate case filed after June 1, 2018, the  
commission shall approve a tariff for a distributed generation program under the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to  
460.1211. A tariff established under this rule does not apply to customers participating in  
a legacy net metering program under the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1001 to 460.1211, before the date that the  
commission establishes a tariff under this rule, who continue to participate in the program  
at their current site or facility as described by R 460.1026.  
R 460.1022 Renewable energy credits.  
Rule 122. (1) An eligible electric generator shall own any renewable energy credits  
granted for electricity generated under the legacy net metering program and distributed  
generation program.  
(2) An electric utility may purchase or trade renewable energy credits from a legacy net  
metering program or distributed generation program customer if agreed to by the  
customer.  
(3) The commission may develop a program for aggregating renewable energy credits  
from legacy net metering program and distributed generation program customers.  
R 460.1024 Penalties.  
Rule 124. Upon a complaint or on the commission’s own motion, if the commission  
finds after notice and hearing that an electric utility has not complied with a provision or  
order issued under part 5 of the clean and renewable energy and energy waste reduction  
act, 2008 PA 295, MCL 460.1171 to 460.1185, the commission shall order remedies and  
Exhibit A  
55  
penalties as necessary to make whole a customer or other person who has suffered  
damages as a result of the violation.  
R 460.1026 Legacy net metering grandfathering clause.  
Rule 126. A customer participating in a legacy net metering program approved by the  
commission before the commission establishes the initial distributed generation program  
tariff pursuant to R 460.1020 may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment. “Initial  
enrollment,” as used in this rule, means the date a customer or site initially enrolled in a  
legacy net metering program as described in the electric utility’s tariff. A customer  
participating in a legacy net metering program who increases the nameplate capacity of  
its generation system after the effective date of an electric utility’s distributed generation  
program tariff is no longer eligible to participate in the legacy net metering program.  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own motion, to )  
promulgate rules governing electric interconnection )  
reconciliation of its power supply cost recovery  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
)
)
)
)
Case No. U-20890  
PROOF OF SERVICE  
ESTELLA R. BRANSON states that on June 27, 2022, she served a copy of the DTE Electric  
Company’s Comments in the above captioned matter, via electronic mail, upon the person listed on the  
attached service list.  
ESTELLA R. BRANSON  
MPSC Case No. U-20890  
Service List  
Page 1  
ALJ Dennis Mack  
mackd2@michigan.gov  
holwerdab@michigan.gov  
scampbell@clarkhill.com  
ian.burgess@cmsenergy.com  
jmathew1@ford.com  
Benjamin J. Holwerda (MPSC Staff)  
Stephen A. Campbell (ABATE)  
Ian F. Burgess Consumers Energy Company  
Jacob Mathews (Ford)  
Gary Melow Michigan Biomass  
Daniel Dundas (MEGA)  
gary.melow@michiganbiomass.com  
dan@megautilities.org  
Laura Sherman (MIEIBC)  
laura@mieibc.org  
Nakhia Crossley (Sunrun Inc.)  
Will Kenworthy (Vote Solar)  
steven.rymsha@sunrun.com  
will@votesolar.org;  
Gemotion Distribution  
Service List  
ITC  
kadarkwa@itctransco.com  
Energy Michigan  
Cloverland  
sejackinchuk@varnumlaw.com  
awallin@cloverland.com  
Cloverland  
bmalaski@cloverland.com  
Cloverland  
mheise@cloverland.com  
Village of Baraga  
vobmgr@UP.NET  
Linda Brauker  
braukerL@MICHIGAN.GOV  
info@VILLAGEOFCLINTON.ORG  
jgraham@HOMEWORKS.ORG  
mkappler@HOMEWORKS.ORG  
psimmer@HOMEWORKS.ORG  
frucheyb@DTEENERGY.COM  
mpsc.filings@CMSENERGY.COM  
jim.vansickle@SEMCOENERGY.COM  
kay8643990@YAHOO.COM  
Village of Clinton  
Tri-County Electric Co-Op  
Tri-County Electric Co-Op  
Tri-County Electric Co-Op  
Citizens Gas Fuel Company  
Consumers Energy Company  
SEMCO Energy Gas Company  
Superior Energy Company  
Upper Michigan Energy Resources Corporation vickie.nugent@wecenergygroup.com  
Upper Peninsula Power Company  
Upper Peninsula Power Company  
Midwest Energy Coop  
Midwest Energy Coop  
Alger Delta Cooperative  
Cherryland Electric Cooperative  
Great Lakes Energy Cooperative  
Great Lakes Energy Cooperative  
Stephenson Utilities Department  
Ontonagon County Rural Elec  
Presque Isle Electric & Gas Cooperative,  
INC.  
jlarsen@uppco.com  
estocking@uppco.com  
dave.allen@TEAMMIDWEST.COM  
bob.hance@teammidwest.com  
tharrell@ALGERDELTA.COM  
tanderson@cherrylandelectric.coop  
bscott@GLENERGY.COM  
sculver@glenergy.com  
kmarklein@STEPHENSON-MI.COM  
debbie@ONTOREA.COM  
ddemaestri@PIEG.COM  
MPSC Case No. U-20890  
Service List  
Page 2  
Thumb Electric  
dbraun@TECMI.COOP  
Bishop Energy  
AEP Energy  
CMS Energy  
Just Energy Solutions  
Constellation Energy  
Constellation Energy  
Constellation New Energy  
DTE Energy  
rbishop@BISHOPENERGY.COM  
mkuchera@AEPENERGY.COM  
todd.mortimer@CMSENERGY.COM  
igoodman@commerceenergy.com  
david.fein@CONSTELLATION.COM  
kate.stanley@CONSTELLATION.COM  
kate.fleche@CONSTELLATION.COM  
mpscfilings@DTEENERGY.COM  
bgorman@FIRSTENERGYCORP.COM  
rarchiba@FOSTEROIL.COM  
First Energy  
My Choice Energy  
Calpine Energy Solutions  
Santana Energy  
greg.bass@calpinesolutions.com  
rabaey@SES4ENERGY.COM  
Spartan Renewable Energy, Inc. (Wolverine  
Power Marketing Corp)  
City of Escanaba  
cborr@WPSCI.COM  
gpirkola@escanaba.org  
City of Crystal Falls  
Lisa Felice  
crystalfallsmgr@HOTMAIL.COM  
felicel@MICHIGAN.GOV  
Michigan Gas & Electric  
City of Gladstone  
Integrys Group  
mmann@USGANDE.COM  
mpolega@GLADSTONEMI.COM  
dan@megautilities.org  
Lisa Gustafson  
Interstate Gas Supply Inc  
Thomas Krichel  
lrgustafson@CMSENERGY.COM  
daustin@IGSENERGY.COM  
krichel@DLIB.INFO  
Bay City Electric Light & Power  
Marquette Board of Light & Power  
Premier Energy Marketing LLC  
City of Marshall  
Doug Motley  
Marc Pauley  
cityelectric@BAYCITYMI.ORG  
jreynolds@MBLP.ORG  
bschlansker@PREMIERENERGYLLC.COM  
ttarkiewicz@CITYOFMARSHALL.COM  
d.motley@COMCAST.NET  
mpauley@GRANGERNET.COM  
ElectricDept@PORTLAND-MICHIGAN.ORG  
kd@alpenapower.com  
City of Portland  
Alpena Power  
Liberty Power  
Wabash Valley Power  
Wolverine Power  
dbodine@LIBERTYPOWERCORP.COM  
leew@WVPA.COM  
tking@WPSCI.COM  
Lowell S.  
ham557@GMAIL.COM  
Realgy Energy Services  
Volunteer Energy Services  
Hillsdale Board of Public Utilities  
Michigan Gas Utilities/Upper Penn Power  
/Wisconsin  
Direct Energy  
Direct Energy  
Direct Energy  
Direct Energy  
BusinessOffice@REALGY.COM  
jeinstein@volunteerenergy.com  
cmcarthur@HILLSDALEBPU.COM  
mrzwiers@INTEGRYSGROUP.COM  
Teresa.ringenbach@directenergy.com  
christina.crable@directenergy.com  
angela.schorr@directenergy.com  
ryan.harwell@directenergy.com  
johnbistranin@realgy.com  
Realgy Corp.  
MPSC Case No. U-20890  
Service List  
Page 3  
Katie Abraham, MMEA  
Indiana Michigan Power Company  
Santana Energy  
kabraham@mpower.org  
mgobrien@aep.com  
mvorabouth@ses4energy.com  
suzy@megautilities.org  
MEGA  
MEGA  
tanya@meagutilities.org  
ITC Holdings  
general@itctransco.com  
Dickinson Wright  
Xcel Energy  
Matthew Peck  
Consumers Energy  
MidAmerican Energy Services, LLC  
MidAmerican Energy Services, LLC  
MidAmerican Energy Services, LLC  
Northern States Power  
Midwest Energy Coop  
Midwest Energy Coop  
Midwest Energy Coop  
Consumers Energy  
Consumers Energy  
DTE Energy  
DTE Energy  
Xcel Energy  
Great Lakes Energy  
Michigan Public Power Agency  
Michigan Gas Utilities Corporation  
American Transmission Company  
American Transmission Company  
Phil Forner  
lpage@dickinsonwright.com  
Deborah.e.erwin@xcelenergy.com  
mmpeck@fischerfranklin.com  
CANDACE.GONZALES@cmsenergy.com  
JHDillavou@midamericanenergyservices.com  
JCAltmayer@midamericanenergyservices.com  
LMLann@midamericanenergyservices.com  
karl.j.hoesly@xcelenergy.com  
kerri.wade@teammidwest.com  
dixie.teague@teammidwest.com  
meghan.tarver@teammidwest.com  
sarah.jorgensen@cmsenergy.com  
Michael.torrey@cmsenergy.com  
adella.crozier@dteenergy.com  
karen.vucinaj@dteenergy.com  
Michelle.Schlosser@xcelenergy.com  
dburks@glenergy.com  
kabraham@mpower.org  
shannon.burzycki@wecenergygroup.com  
kerdmann@atcllc.com  
handrew@atcllc.com  
phil@allendaleheating.com  
Timothy Lundgren  
Laura Chappelle  
Amanda Wood  
tlundgren@potomaclaw.com  
lchappelle@potomaclaw.com  
Amanda@misostates.org  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own motion, to )  
promulgate rules governing electric interconnection )  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
)
)
Case No.U-20890  
___________________________________________)  
Introduction  
Although the Michigan Energy Innovation Business Council (“Michigan EIBC”) does not agree  
with the arguments made by Consumers Energy Company and DTE Electric Company in a Joint  
Petition for Rehearing (“Joint Petition”) filed in this Docket on April 14, 2022, Michigan EIBC  
appreciates the opportunity to respond to the issues raised in the Joint Petition and to comment  
on the revised version of the MIXDG rules as proposed by the Commission in its March 17,  
2022 Order (“final MIXDG rules”). Overall, Michigan EIBC is broadly supportive of the revised  
version of the MIXDG rules proposed by the Commission and believes that these standards will  
help enable the safe, but timely, interconnection of distributed energy resources (“DERs”) in  
Michigan. Given that these rules have not been updated in more than a decade and given the  
changes that the electric grid has experienced over that time, it is critical that the Commission is  
able to provide improved guidance, timelines, and standards to meet the needs of the modern  
grid.  
Michigan EIBC has been deeply involved in the Commission’s process over the last four years to  
update the state’s interconnection standards. In addition to participating throughout the  
workgroup process and submitting comments as appropriate, Michigan EIBC submitted  
comments and a redline of the draft MIXDG rules on November 1, 2021. Among the issues  
raised by Michigan EIBC in those comments/redline and consistently throughout the workgroup  
process were issues highlighted in the Joint Petition including those related to limited-export  
controls and standard fees. Responses to the concerns raised, as well as other comments on the  
proposed revised MIXDG rules, are outlined below.  
Limited-Export Controls  
In general, as stated in previous comments to the Commission, Michigan EIBC strongly believes  
that the MIXDG rules should include specific standards and definitions to allow for power-  
limited export DERs. The use of energy storage is growing significantly in Michigan among  
residential and commercial customers, and we anticipate increasing interest in distribution-  
connected storage as well. It is important that the interconnection standards spell out how storage  
will be treated and evaluated during the interconnection screening and study process, as is done  
in the final MIXDG rules. Furthermore, Michigan EIBC encourages the Commission to bear in  
mind that limitations on energy exports from DERs will be influenced by implementation of the  
Federal Energy Regulatory Commission’s (“FERC”) Order No. 2222. This rule will enable  
DERs to participate alongside traditional resources in the regional organized wholesale markets  
through aggregations, opening U.S. organized wholesale markets to new sources of energy and  
grid services. As FERC itself explains, the rule “will help provide a variety of benefits including  
lower costs for consumers through enhanced competition, more grid flexibility and resilience,  
and more innovation within the electric power industry.”1 Clearly FERC Order No. 2222  
envisions energy export from DERs.  
It is important to note that in the absence of clear Commission rules, as is currently the case,  
limited-export DERs are not treated consistently across the state. Michigan EIBC members work  
with customers who have encountered significant roadblocks for behind-the-meter solar plus  
storage systems with limited export. Specifically, in some cases, customer interconnection  
requests have been denied because the total capacity of a solar plus storage system is greater than  
100 percent of the customers’ annual electricity consumption despite the export (as limited by  
the inverter or power control system) of the solar plus storage system being far less than that  
amount. We expect this will also be a challenge for front-of-the-meter distribution connected  
storage. It is important to recognize that export from DC coupled solar plus storage systems is  
1 Federal Energy Regulatory Commission. “FERC Order No. 2222: Fact Sheet.” September 17, 2020. Available at:  
https://www.ferc.gov/media/ferc-order-no-2222-fact-sheet.  
limited by the inverter (and therefore, the total potential output is not the sum of the capacity of  
the solar system and the storage system). Similarly, in AC coupled systems, energy storage  
systems will have their own inverters which can limit export.  
Throughout the process to develop the final MIXDG rules, Michigan EIBC recommended that  
the Commission include specific limited-export standards for the utilities to follow as detailed in  
the 2019 Model Interconnection Rules from the Interstate Renewable Energy Council (“IREC”).  
These model rules follow guidance provided by FERC Order 845, which allows an  
interconnection customer to request service at a lower level than the nameplate generating  
facility capacity with the proper control technologies in place.  
Consumers Energy and DTE Electric claim in their Joint Petition that “proposed Rules R  
460.920 and R 460.980 appear designed to foreclose these electric utility legal rights and  
threaten the safety and reliability of the electric system in Michigan . . .”2 The utilities appear to  
be concerned specifically about R 460.980, subsection 4(e), which reads:  
(e) DERs may utilize, a Nationally Recognized Testing Laboratory Certified  
Power Control System and inverter system that results in the DER disconnecting  
from the distribution system, ceasing to energize the distribution system or halting  
energy production within 2 seconds if the period of continuous inadvertent export  
exceeds 30 seconds. Failure of the control or inverter system for more than 30  
seconds, resulting from loss of control or measurement signal, or loss of control  
power, must result in the DER entering an operational mode where no energy is  
exported across the point of common coupling to the distribution system.3  
If a power control system does experience a short period of inadvertent export, the utilities argue  
in their Joint Petition that “[the] proposed rules effectively allow 32 seconds of dangerous  
operation until the project needs to come back into compliance. This short amount of time can  
cause a transformer to fail catastrophically (potentially including a fire) and seriously impact  
2 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. pp. 7-8.  
3 Michigan Public Service Commission Order. Case No. U-20890. March 17, 2022. p. 44.  
power quality to adjacent customers (potentially including appliance failures).”4 For a number of  
reasons, as outlined below, this argument is false and should be rejected.  
First, in general, the maximum amount of inadvertent export from a limited-export system for a  
short period of time is not sufficient to cause damage to conductors or thermal impacts.  
According to the Storage Interconnection Committee of the Building a Technically Reliable  
Interconnection Evolution for Storage (“BATRIES”) Project Team, which conducted testing of  
power control systems, most are able to respond very quickly (i.e., within 10 seconds).5 For  
example, of the 59 power control system devices on the California Energy Commission’s  
approved solar equipment list, as of October 2021, all but one have an inadvertent export  
response time of 10 seconds or less.6 Simply from a thermodynamics perspective, these potential  
short periods of inadvertent export cannot cause catastrophic thermal failures as suggested by the  
utilities. As stated by the BATRIES Project Team, “thermal impacts were not modeled for  
inadvertent export because both their level (110% max) and duration (typically 2-10 seconds)  
were below any known thresholds for concern.”7 This is also true because utility infrastructure is  
designed to safely be operated in overload conditions, especially for these very short time  
periods, to ensure grid flexibility in meeting unexpected needs. For example, ISO-NE Capacity  
Rating Procedure requires infrastructure to be designed and rated for overloading operations for  
15-minute emergencies and durations up to 12 hours.8  
Second, the standards proposed by the Commission for limited-export in the final MIXDG rules  
are aligned with national certifications and codes from UL, the Institute of Electrical and  
Electronics Engineers (“IEEE”) and the National Electrical Code (“NEC”). Currently, the UL  
1741 Certification Requirement Decision (“CRD”) for power control systems requires a response  
4 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. p. 8.  
5 Building a Technically Reliable Interconnection Evolution for Storage (BATRIES) Project Team. Storage  
Interconnection Team. “Toolkit & Guidance for the Interconnection of Energy Storage & Solar-Plus-Storage.”  
March 2022. Available at: https://energystorageinterconnection.org/resources/batries-toolkit/.  
6 California Energy Commission. “Inverter and Energy Storage System PCS List.” Oct. 21, 2021. Available at:  
https://solarequipment.energy.ca.gov/Home/DownloadtoExcel?filename=PowerControlSystem.  
7 Building a Technically Reliable Interconnection Evolution for Storage (BATRIES) Project Team. Storage  
Interconnection Team. “Toolkit & Guidance for the Interconnection of Energy Storage & Solar-Plus-Storage.”  
March 2022. Available at: https://energystorageinterconnection.org/resources/batries-toolkit/. pp. 82-83.  
8 ISO-NE. “Capacity Rating Procedures by the System Design Task Force.” Corrected October 2004. Available at:  
https://www.iso-ne.com/static-assets/documents/rules_proceds/isone_plan/pp07/capacity_rating_procedures.pdf.  
time of under 30 seconds to instances of inadvertent export. Similarly, the NEC, which is a  
standard for safety related to fires, includes a requirement that any inadvertent export is limited  
to less than 30 seconds. A similar situation can be found in the IEEE 1547-2018 standard, which  
requires in section 4.6.1 that a DER “shall be capable of disabling the permit service setting and  
shall cease to energize the Area EPS and trip in no more than 2 s.”9 Section 4.6.2 goes on to  
indicate that “The DER shall limit its active power output to not greater than the active power  
limit set point in no more than 30 s or in the time it takes for the primary energy source to reduce  
its active power output to achieve the requirements of the active power limit set point, whichever  
is greater.”10 In general, IEEE standards are developed by consensus and reflect the accepted best  
practice at the time of adoption. IEEE 1547-2018 was developed by a working group of more  
than 100 experts, and balloted by a pool of more than 300 voters, which was balanced across  
user communities, including electric utilities. An approval rate of at least 75% was required, with  
an answer provided to all comments. As such, it is clear that these standards reflect consensus,  
reasonable, best practices.  
Third, the standards proposed by the Commission for limited-export in the final MIXDG rules  
are aligned with the Model Interconnection Procedures from IREC.11 Moreover, Michigan EIBC  
is unaware of any state jurisdictions that have gone through a formal energy storage  
interconnection rulemaking process and have not adopted rules to enable limited-export  
allowances. While terminology may vary within the actual rules across different jurisdictions,  
Illinois recently adopted rules allowing for limited-export12, 13 and similar rules are pending in  
New Mexico, Connecticut, Massachusetts, Vermont, and Puerto Rico. Furthermore, limited-  
export allowances and standards have been established within interconnection rules using a  
variety of approaches in New York, Maryland, Colorado, Arizona, Nevada, Minnesota,  
9 IEEE Standards Association. “IEEE Standard for Interconnection and Interoperability of Distributed Energy  
Resources with Associated Electric Power Systems Interfaces.” 2018. Available at:  
https://web.nit.ac.ir/~shahabi.m/M.Sc%20and%20PhD%20materials/DGs%20and%20MicroGrids%20Course/Stand  
ards/IEEE%20Std%201547/IEEE%20Std%201547™-2018.pdf.  
10 Ibid.  
11 Interstate Renewable Energy Council. “Model Interconnection Procedures.” 2019. Available at:  
https://irecusa.org/resources/irec-model-interconnection-procedures-2019/.  
12 Illinois Commerce Commission. Docket 20-0700. Final Order. May 25, 2022. Available at:  
https://www.icc.illinois.gov/docket/P2020-0700/documents/324414.  
13 Misbrener, K. “Illinois rule changes will simplify solar + storage interconnection.” Solar Power World. Available  
at: https://www.solarpowerworldonline.com/2022/06/illinois-rule-changes-will-simplify-solar-storage-  
interconnection/.  
California and Hawaii. In Hawaii, for example, limited-export standards have been in place since  
2016. Despite the incredibly high penetration of DERs in Hawaii, Hawaiian Electric has not filed  
comments or discussed with stakeholders any record of thermal impacts or reported safety  
concerns related to inadvertent export from systems with limited-export controls.  
Overall, it is clear both that multiple states have adopted or are adopting rules similar to what the  
Commission contemplates and to which Consumers Energy and DTE Electric object, and  
regardless of what rules a state adopts, the safety and technical standards still apply. For these  
reasons, Consumers Energy and DTE Electric’s “safety arguments” should be seen for what they  
are — an attempt to dissuade the Commission from adopting meaningful updates to its  
interconnection rules that will advance customers’ energy independence and resiliency.  
Standard Fees  
In general, as stated in previous comments to the Commission, Michigan EIBC believes that fees  
for the pre-application reports, simplified track (see comments below), non-export track, and fast  
track should be established uniformly by the Commission. It is well-established that  
interconnection applicants should pay the full costs of any required in-depth studies, but  
reasonable initial fee caps should also be established by the Commission. The final MIXDG  
rules establish reasonable fees for pre-application reports, non-export track, and fast track as well  
as initial fee caps for more in-depth studies. However, the utilities argue in their Joint Petition  
that “[there] is a problem with the fees that the MIXDG rules use for actions and studies required  
by the rules. . .”14  
The initial fees established in the final MIXDG rules for the pre-application report ($300), non-  
export track ($100 + $1/kWac), and fast track initial review ($100 + $1/kWac for certified DERs  
and $100 + $2/kWac for non-certified DERs) are aligned with those in the Model  
Interconnection Procedures established by IREC.15 As such, similar standard fees have been  
14 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. p. 18.  
15 Interstate Renewable Energy Council. “Model Interconnection Procedures.” 2019. Available at:  
https://irecusa.org/resources/irec-model-interconnection-procedures-2019/.  
established by other states including, for example Illinois,16 New Mexico,17 Pennsylvania,18 and  
Utah.19 The reviews required by the utilities for the pre-application report, non-export track, and  
fast track initial review are relatively limited in scope. For example, in the final MIXDG rules,  
according to R 460.932, “[the] pre-application report may include only existing and readily  
available data. A request for a pre-application report does not obligate an electric utility to  
conduct a study or other analysis of the proposed DER if data is not readily available.” Similarly,  
for the initial fast track review, the utility is required only to review the DER using a limited  
number of relatively simple initial review screens (R 460.946). There is no clear reason why  
Michigan’s utilities should have significantly higher costs than other Midwest utilities to conduct  
these initial reviews or, if they do currently have higher costs, why efficiencies could not be  
found to decrease costs.  
The fees, as outlined in the final MIXDG rules, for the pre-application report, non-export track,  
and fast track initial review are reasonable and should serve as reasonable limits on what a utility  
may collect. However, as outlined below, according to R 460.926 (4), an electric utility “that  
expects to incur costs greater than the fees listed in subrule (2) or initial fee caps listed in subrule  
(3) of this rule in the evaluation of an interconnection application may file a request for a waiver  
pursuant to R 460.910.”20 A determination as to whether such a waiver is warranted would likely  
be made by the Commission under an expedited proceeding and without the level of stakeholder  
participation that occurs during a contested case proceeding. Given the language in R 460.926, it  
is unclear whether a utility would have to prove, via the provision of actual expenses, that their  
costs exceed those listed in the final MIXDG rules to obtain a waiver. As such, Michigan EIBC  
16 Illinois Joint Committee on Administrative Rules. Title 83: Public Utilities, Chapter 1: Illinois Commerce  
Commission, Subchapter c: Electric Utilities, Part 466 Electric Interconnection of Distributed Generation Facilities.  
Available at: https://www.ilga.gov/commission/jcar/admincode/083/08300466sections.html.  
17 New Mexico Commission of Public Records. Title 17: Public Utilities and Utility Services, Chapter 9: Electric  
Services, Part 568: Interconnection of Generating Facilities with a Rated Capacity up to and Including 10 MW  
Connecting to a Utility System. Available at: https://www.srca.nm.gov/parts/title17/17.009.0568.html.  
18 Commonwealth of Pennsylvania. Pennsylvania Code. Title 52, Chapter 69. Available at:  
https://www.pacodeandbulletin.gov/Display/pacode?file=/secure/pacode/data/052/chapter69/s69.2104.html&d=redu  
ce#:~:text=§%2069.2104.-  
,Interconnection%20application%20fees.,relating%20to%20interconnection%20standards)%3A.  
19 Utah Admin. Code 746-312-13. Available at: https://casetext.com/regulation/utah-administrative-code/public-  
service-commission/title-r746-administration/rule-r746-312-electrical-interconnection/section-r746-312-13-  
interconnection-fees-and-charges.  
20 Michigan Public Service Commission Order. Case No. U-20890. March 17, 2022.  
does not believe that a utility should be allowed to petition for a waiver of the fees listed in R  
460.926 subrule (2) for the pre-application report, non-export track, and fast track initial review  
without a clear showing with evidence (e.g., through a contested case process) that reasonable  
utility processes to undertake these reviews cost more than the established fees.  
Material Modifications  
In their Joint Petition, the utilities state that changes to the definition of “material modification”  
in the final MIXDG rules “presents the [utilities] with a virtually infinite number of illegal,  
unsafe, and unreliable configurations with no apparent recourse.”21 Specifically, the Joint  
Petition notes concerns with the addition of a statement in R 460.901b(n) that “[replacing] a  
component with another component that has near-identical characteristics does not constitute a  
material modification.” Michigan EIBC strongly encourages the Commission to reject these  
arguments and retain the language in R 460.901b(n), including the description of the required  
review to determine that a modification is material, in the final MIXDG rules.  
Throughout the development of the MIXDG rules, Michigan EIBC provided comments  
emphasizing the importance of ensuring that fair, thorough reviews are conducted to determine  
whether or not a modification is “material” in nature. It is critical, as is done in the final MIXDG  
rules, that the Commission spell out clearly in the rules what types of changes are material and  
what types of changes are not material. This is especially important for projects that go through  
the study track, given that the time between initial application and approved interconnection  
agreement can be quite long. As a result, equipment or parts included in an initial application  
may no longer be available. If that is the case, it is critical that an applicant be able to substitute a  
“near-identical” component from a different manufacturer, and that such an allowance be clearly  
indicated in the rules.  
Separately, it is critical in the legacy net metering (“LNM”) and distributed generation (“DG”)  
section of the MIXDG rules that the addition of energy storage to an existing DG system does  
21 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. p. 13.  
not result in an applicant being terminated from the LNM or DG program. The final rules state in  
R 460.1001 (7)(c) that:  
The addition of an energy storage device to an existing approved legacy net metering  
program system or distributed generation program system is considered a material  
modification. The electric utility interconnection procedures must include details  
describing how energy storage equipment may be integrated into an existing legacy net  
metering program system without impacting the 10-year grandfathering period or  
participation in the distributed generation program.22  
It appears that the intention of the Commission is to avoid the situation where a rooftop solar  
customer in the LNM or DG program with multiple years still left on their agreement is removed  
from the program when that customer adds an on-site energy storage system. However, if the  
addition of an energy storage device to an existing LNM or DG program system is considered a  
material modification (as stated in the final MIXDG rules), it is likely that a utility would require  
a customer adding an energy storage device to file a new interconnection application, which  
could trigger removal from the LNM or DG program. However, given that these systems would  
be export-limited with an inverter or power supply controller, the addition of storage will not  
increase the generation capacity of the customer’s electric generator. As such, based on a plain  
reading of section 183 of Public Act 342, it would be illegal to remove the customer against their  
will from the LNM or DG program prior to the end of the grandfathering period.23 This will  
become more critical toward the end of 2022 as installations near the DG program caps for both  
DTE Electric and Consumers Energy. If the relevant DG cap has been reached, a customer who  
needs to reapply when adding a storage system may find the DG program closed and then may  
not only not be able to add their storage device, but also, may be unable to continue to use their  
existing solar panels. If the Commission retains the language in R 460.1001 (7)(c), it is critical  
that the Commission also clearly confirm that utility procedures must ensure that customers are  
not harmed.  
22 Michigan Public Service Commission Order. Case No. U-20890. March 17, 2022. p. 49.  
23 Public Act 342 of 2016. Section 183. Available at: https://www.legislature.mi.gov/documents/2015-  
2016/publicact/htm/2016-PA-0342.htm.  
Simplified Track  
In the final MIXDG rules as proposed, the Commission deleted the simplified track, which was a  
set of limited screens to evaluate level 1 or level 2 projects. Throughout the process to develop  
the MIXDG rules, Michigan EIBC advocated for and supported the addition of the simplified  
track. Although the screens in the simplified track were a subset of those included in the fast  
track, by selecting the screens most critical to evaluate small projects, the simplified track would  
enable a faster, more streamlined evaluation of the smallest on-site generators that are very  
unlikely to require additional study.  
Michigan EIBC strongly recommends that the Commission retain the simplified track in the  
MIXDG rules. In addition to the ability to streamline projects, the simplified track also required  
that the fee for the simplified track plus any LNM or DG program application fee could not  
together exceed a total of $50. However, with the deletion of the simplified track (as is done in  
the final MIXDG rules), level 1 and 2 projects would instead go through fast track, which has a  
fee of $100 + $1/kWac. There is no language in the final MIXDG rules to ensure that a customer  
would not be charged both a LNM or DG program application fee of $50 plus a fast track fee of  
$100 + $1/kWac. A customer with a 50 kW level 2 project applying for interconnection under  
the DG program would have paid $50 in total under the previous version of the MIXDG rules.  
With the elimination of the simplified track, that same customer may have to pay a $50  
application fee for the DG program plus a $150 fee for the fast track, for a total of $200. In  
addition to the ability to streamline and quickly review level 1 and 2 projects, the retention of the  
simplified track would provide clear, reasonable, and standard fees for customers. Moreover,  
increased fees for level 1 customers do nothing to help ensure that middle- and lower-income  
customers can access DERs. It is these customers who could often benefit most from the long-  
term savings provided by DERs.  
Interconnection Penalties  
Michigan EIBC observes that the interconnection penalties provided for in R 460.990 only apply  
to DERs greater than 100 kW. Smaller systems are more frequently associated with smaller  
customers, who are less likely to have the resources to protect their right to interconnect under  
the MIXDG rules. Allowing an electric utility to impede interconnection for smaller systems  
without consequences sends the wrong message to utilities and treats smaller customers as  
second-class customers. Michigan EIBC recommends that the Commission revise R 460.990 to  
remove 100 kW limitation on the availability of penalties as follows:  
R 460.990 Interconnection penalties.  
Rule 90. Pursuant to section 10e of 1939 PA 3, MCL 460.10e, an electric utility  
shall take all necessary steps to ensure that DERs are connected to the distribution  
systems within their operational control. If the commission finds, after notice and  
hearing, that an electric utility has prevented or unduly delayed the ability of a  
DER greater than 100 kW to connect to the distribution system of the electric  
utility, the commission may order remedies designed to make whole the applicant  
proposing the DER, including, but not limited to, reasonable attorney fees. If the  
electric utility violates this rule, the commission may order fines of not more than  
$50,000 per day, commensurate with the demonstrated impact of the violation.  
Recommended Clarifications  
As the Commission considers further comments on the MIXDG rules, Michigan EIBC suggests  
certain clarifications to improve the rules and facilitate interconnection.  
First, related to informal mediation under R 460.904, rule 4(3) provides that the parties to an  
interconnection dispute may request informal mediation by a Commission interconnection  
ombudsperson. The rule, however, does not specify any timeframe by when such informal  
mediation must occur. Because time is often important to the interconnection process and the  
MIXDG rules require other dispute resolution steps that may be needed before an  
interconnection dispute is resolved, Michigan EIBC suggests that the Commission require an  
initial meeting with the ombudsperson within 10 days of the request for informal mediation  
being submitted. The absence of such language may unnecessarily prolong the resolution of an  
interconnection dispute. Specifically, Michigan EIBC recommends that Rule 4(3) be revised as  
follows:  
(3) In the event that parties are unable to resolve the dispute privately, the parties  
may, by mutual agreement, make a written request for informal mediation to the  
commission staff. The informal mediation shall commence within 10 days of  
submission of the written request and be conducted by an interconnection  
ombudsperson who shall be a member of the commission staff and designated by  
the commission. Both parties may choose to have attorneys or appropriate  
representation present.  
Second, related to R 460.906 and the provisions governing formal mediation, rule 6(1) provides  
that if “the parties have been unable to resolve a dispute through the informal mediation process  
under R 460.904, the parties shall then attempt to resolve the dispute in the following manner:”  
This language implies that informal mediation is required, but R 460.904 clearly characterizes  
informal mediation as voluntary after the direct discussion and informal negotiation required  
under Rule 4(2). Because time is often important in interconnection, Michigan EIBC agrees with  
treating informal mediation as an optional step in the dispute resolution process. To remedy this  
inconsistency with R 460.904, Michigan EIBC recommends revising Rule 6(1) of R 406.906 to  
read as:  
(1) If the parties have been unable to resolve a dispute through either the  
required direct discussion or informal negotiation or the voluntary informal  
mediation process under R 460.904, the parties shall then attempt to resolve the  
dispute in the following manner:  
Third, we recommend a revision related to R 460.910, which provides for waivers. As written,  
Rule 10 is ambiguous as to which party has the burden of demonstrating the necessity of a  
waiver, the duration of any waiver, and the circumstances under which a waiver may be granted.  
Michigan EIBC proposes deleting the existing Rule 10 and replacing it with the following:  
R 460.910 Waivers  
Rule 10. (1) The Commission may, on application of an electric utility, customer,  
alternative electric supplier, or interconnection customer, or on its own motion,  
grant a temporary or permanent waiver from 1 or more provisions of these rules in  
situations in which the Commission finds that:  
(a) the provision from which the waiver is granted is not statutorily mandated;  
(b) there is good cause for the waiver, and it is in the public interest; and  
(c) the provision from which the waiver is granted would, as applied in the  
presented situation, be unreasonable or unnecessarily burdensome.  
(2) The burden of proof in establishing a right to a waiver shall be on the party  
seeking the waiver.  
(3) An applicant for a waiver may request expeditious processing.  
Fourth, related to interconnection applications under R 460.936, rule 36(7)(b) sets forth the  
electric utility’s obligation to provide a written list of deficiencies in an interconnection  
application and how such deficiencies are to be addressed. Importantly, however, the rule does  
not prevent the utility from later adding to the list new, unrelated deficiencies. To prevent a  
utility from unnecessarily prolonging the interconnection process, the Commission should clarify  
the rule to confirm the utility’s obligation to provide a comprehensive list of deficiencies within  
10 days of submission of an interconnection application. Michigan EIBC proposes the following  
modification of Rule 36(7)(b):  
(b) If the application is incomplete or non-conforming, the electric utility shall  
provide to the applicant a written list of all deficiencies with the notification. The  
applicant shall have 60 business days from the date of electric utility notification  
to submit the necessary information and may provide up to 2 submissions during  
this time period. After each submission of information, the electric utility shall  
have 10 business days to notify the applicant that the interconnection application  
is either accepted or rejected due to continuing deficiencies. A utility may not  
identify additional deficiencies beyond those originally identified. If the  
applicant does not meet the timelines required by this rule, the utility may  
withdraw the application.  
Michigan EIBC’s final recommendation is related to the requirement in R 460.938 that an  
electric utility publish on its website a list of interconnection requests it has received. As written,  
the rule seems to suggest that in a month in which no changes have occurred, no update  
whatsoever is required to the list. In such situations, it would not be clear whether the lack of an  
update is due to the lack of any changes or the failure to update the list as required. To avoid any  
confusion, Michigan EIBC recommends that the rule require a utility to at least update the list to  
indicate that no changes have occurred since the prior month. Michigan EIBC suggests the  
following language to reflect this:  
(1) An electric utility shall maintain a publicly available interconnection list,  
which is available in a sortable spreadsheet format. The sortable spreadsheet must  
be provided to the public upon request. An electric utility that has received not  
less than 100 complete interconnection applications in a year shall publish this list  
on the electric utility’s website. The public interconnection list must be updated  
monthly. If unless no changes to the spreadsheet have occurred in that month, a  
note to that effect must be clearly indicated on the spreadsheet. The date of  
the most recent update must be clearly indicated.  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own motion, to )  
promulgate rules governing electric interconnection )  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
)
)
Case No.U-20890  
___________________________________________)  
Introduction  
Although the Michigan Energy Innovation Business Council (“Michigan EIBC”) does not agree  
with the arguments made by Consumers Energy Company and DTE Electric Company in a Joint  
Petition for Rehearing (“Joint Petition”) filed in this Docket on April 14, 2022, Michigan EIBC  
appreciates the opportunity to respond to the issues raised in the Joint Petition and to comment  
on the revised version of the MIXDG rules as proposed by the Commission in its March 17,  
2022 Order (“final MIXDG rules”). Overall, Michigan EIBC is broadly supportive of the revised  
version of the MIXDG rules proposed by the Commission and believes that these standards will  
help enable the safe, but timely, interconnection of distributed energy resources (“DERs”) in  
Michigan. Given that these rules have not been updated in more than a decade and given the  
changes that the electric grid has experienced over that time, it is critical that the Commission is  
able to provide improved guidance, timelines, and standards to meet the needs of the modern  
grid.  
Michigan EIBC has been deeply involved in the Commission’s process over the last four years to  
update the state’s interconnection standards. In addition to participating throughout the  
workgroup process and submitting comments as appropriate, Michigan EIBC submitted  
comments and a redline of the draft MIXDG rules on November 1, 2021. Among the issues  
raised by Michigan EIBC in those comments/redline and consistently throughout the workgroup  
process were issues highlighted in the Joint Petition including those related to limited-export  
controls and standard fees. Responses to the concerns raised, as well as other comments on the  
proposed revised MIXDG rules, are outlined below.  
Limited-Export Controls  
In general, as stated in previous comments to the Commission, Michigan EIBC strongly believes  
that the MIXDG rules should include specific standards and definitions to allow for power-  
limited export DERs. The use of energy storage is growing significantly in Michigan among  
residential and commercial customers, and we anticipate increasing interest in distribution-  
connected storage as well. It is important that the interconnection standards spell out how storage  
will be treated and evaluated during the interconnection screening and study process, as is done  
in the final MIXDG rules. Furthermore, Michigan EIBC encourages the Commission to bear in  
mind that limitations on energy exports from DERs will be influenced by implementation of the  
Federal Energy Regulatory Commission’s (“FERC”) Order No. 2222. This rule will enable  
DERs to participate alongside traditional resources in the regional organized wholesale markets  
through aggregations, opening U.S. organized wholesale markets to new sources of energy and  
grid services. As FERC itself explains, the rule “will help provide a variety of benefits including  
lower costs for consumers through enhanced competition, more grid flexibility and resilience,  
and more innovation within the electric power industry.”1 Clearly FERC Order No. 2222  
envisions energy export from DERs.  
It is important to note that in the absence of clear Commission rules, as is currently the case,  
limited-export DERs are not treated consistently across the state. Michigan EIBC members work  
with customers who have encountered significant roadblocks for behind-the-meter solar plus  
storage systems with limited export. Specifically, in some cases, customer interconnection  
requests have been denied because the total capacity of a solar plus storage system is greater than  
100 percent of the customers’ annual electricity consumption despite the export (as limited by  
the inverter or power control system) of the solar plus storage system being far less than that  
amount. We expect this will also be a challenge for front-of-the-meter distribution connected  
storage. It is important to recognize that export from DC coupled solar plus storage systems is  
1 Federal Energy Regulatory Commission. “FERC Order No. 2222: Fact Sheet.” September 17, 2020. Available at:  
https://www.ferc.gov/media/ferc-order-no-2222-fact-sheet.  
limited by the inverter (and therefore, the total potential output is not the sum of the capacity of  
the solar system and the storage system). Similarly, in AC coupled systems, energy storage  
systems will have their own inverters which can limit export.  
Throughout the process to develop the final MIXDG rules, Michigan EIBC recommended that  
the Commission include specific limited-export standards for the utilities to follow as detailed in  
the 2019 Model Interconnection Rules from the Interstate Renewable Energy Council (“IREC”).  
These model rules follow guidance provided by FERC Order 845, which allows an  
interconnection customer to request service at a lower level than the nameplate generating  
facility capacity with the proper control technologies in place.  
Consumers Energy and DTE Electric claim in their Joint Petition that “proposed Rules R  
460.920 and R 460.980 appear designed to foreclose these electric utility legal rights and  
threaten the safety and reliability of the electric system in Michigan . . .”2 The utilities appear to  
be concerned specifically about R 460.980, subsection 4(e), which reads:  
(e) DERs may utilize, a Nationally Recognized Testing Laboratory Certified  
Power Control System and inverter system that results in the DER disconnecting  
from the distribution system, ceasing to energize the distribution system or halting  
energy production within 2 seconds if the period of continuous inadvertent export  
exceeds 30 seconds. Failure of the control or inverter system for more than 30  
seconds, resulting from loss of control or measurement signal, or loss of control  
power, must result in the DER entering an operational mode where no energy is  
exported across the point of common coupling to the distribution system.3  
If a power control system does experience a short period of inadvertent export, the utilities argue  
in their Joint Petition that “[the] proposed rules effectively allow 32 seconds of dangerous  
operation until the project needs to come back into compliance. This short amount of time can  
cause a transformer to fail catastrophically (potentially including a fire) and seriously impact  
2 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. pp. 7-8.  
3 Michigan Public Service Commission Order. Case No. U-20890. March 17, 2022. p. 44.  
power quality to adjacent customers (potentially including appliance failures).”4 For a number of  
reasons, as outlined below, this argument is false and should be rejected.  
First, in general, the maximum amount of inadvertent export from a limited-export system for a  
short period of time is not sufficient to cause damage to conductors or thermal impacts.  
According to the Storage Interconnection Committee of the Building a Technically Reliable  
Interconnection Evolution for Storage (“BATRIES”) Project Team, which conducted testing of  
power control systems, most are able to respond very quickly (i.e., within 10 seconds).5 For  
example, of the 59 power control system devices on the California Energy Commission’s  
approved solar equipment list, as of October 2021, all but one have an inadvertent export  
response time of 10 seconds or less.6 Simply from a thermodynamics perspective, these potential  
short periods of inadvertent export cannot cause catastrophic thermal failures as suggested by the  
utilities. As stated by the BATRIES Project Team, “thermal impacts were not modeled for  
inadvertent export because both their level (110% max) and duration (typically 2-10 seconds)  
were below any known thresholds for concern.”7 This is also true because utility infrastructure is  
designed to safely be operated in overload conditions, especially for these very short time  
periods, to ensure grid flexibility in meeting unexpected needs. For example, ISO-NE Capacity  
Rating Procedure requires infrastructure to be designed and rated for overloading operations for  
15-minute emergencies and durations up to 12 hours.8  
Second, the standards proposed by the Commission for limited-export in the final MIXDG rules  
are aligned with national certifications and codes from UL, the Institute of Electrical and  
Electronics Engineers (“IEEE”) and the National Electrical Code (“NEC”). Currently, the UL  
1741 Certification Requirement Decision (“CRD”) for power control systems requires a response  
4 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. p. 8.  
5 Building a Technically Reliable Interconnection Evolution for Storage (BATRIES) Project Team. Storage  
Interconnection Team. “Toolkit & Guidance for the Interconnection of Energy Storage & Solar-Plus-Storage.”  
March 2022. Available at: https://energystorageinterconnection.org/resources/batries-toolkit/.  
6 California Energy Commission. “Inverter and Energy Storage System PCS List.” Oct. 21, 2021. Available at:  
https://solarequipment.energy.ca.gov/Home/DownloadtoExcel?filename=PowerControlSystem.  
7 Building a Technically Reliable Interconnection Evolution for Storage (BATRIES) Project Team. Storage  
Interconnection Team. “Toolkit & Guidance for the Interconnection of Energy Storage & Solar-Plus-Storage.”  
March 2022. Available at: https://energystorageinterconnection.org/resources/batries-toolkit/. pp. 82-83.  
8 ISO-NE. “Capacity Rating Procedures by the System Design Task Force.” Corrected October 2004. Available at:  
https://www.iso-ne.com/static-assets/documents/rules_proceds/isone_plan/pp07/capacity_rating_procedures.pdf.  
time of under 30 seconds to instances of inadvertent export. Similarly, the NEC, which is a  
standard for safety related to fires, includes a requirement that any inadvertent export is limited  
to less than 30 seconds. A similar situation can be found in the IEEE 1547-2018 standard, which  
requires in section 4.6.1 that a DER “shall be capable of disabling the permit service setting and  
shall cease to energize the Area EPS and trip in no more than 2 s.”9 Section 4.6.2 goes on to  
indicate that “The DER shall limit its active power output to not greater than the active power  
limit set point in no more than 30 s or in the time it takes for the primary energy source to reduce  
its active power output to achieve the requirements of the active power limit set point, whichever  
is greater.”10 In general, IEEE standards are developed by consensus and reflect the accepted best  
practice at the time of adoption. IEEE 1547-2018 was developed by a working group of more  
than 100 experts, and balloted by a pool of more than 300 voters, which was balanced across  
user communities, including electric utilities. An approval rate of at least 75% was required, with  
an answer provided to all comments. As such, it is clear that these standards reflect consensus,  
reasonable, best practices.  
Third, the standards proposed by the Commission for limited-export in the final MIXDG rules  
are aligned with the Model Interconnection Procedures from IREC.11 Moreover, Michigan EIBC  
is unaware of any state jurisdictions that have gone through a formal energy storage  
interconnection rulemaking process and have not adopted rules to enable limited-export  
allowances. While terminology may vary within the actual rules across different jurisdictions,  
Illinois recently adopted rules allowing for limited-export12, 13 and similar rules are pending in  
New Mexico, Connecticut, Massachusetts, Vermont, and Puerto Rico. Furthermore, limited-  
export allowances and standards have been established within interconnection rules using a  
variety of approaches in New York, Maryland, Colorado, Arizona, Nevada, Minnesota,  
9 IEEE Standards Association. “IEEE Standard for Interconnection and Interoperability of Distributed Energy  
Resources with Associated Electric Power Systems Interfaces.” 2018. Available at:  
https://web.nit.ac.ir/~shahabi.m/M.Sc%20and%20PhD%20materials/DGs%20and%20MicroGrids%20Course/Stand  
ards/IEEE%20Std%201547/IEEE%20Std%201547™-2018.pdf.  
10 Ibid.  
11 Interstate Renewable Energy Council. “Model Interconnection Procedures.” 2019. Available at:  
https://irecusa.org/resources/irec-model-interconnection-procedures-2019/.  
12 Illinois Commerce Commission. Docket 20-0700. Final Order. May 25, 2022. Available at:  
https://www.icc.illinois.gov/docket/P2020-0700/documents/324414.  
13 Misbrener, K. “Illinois rule changes will simplify solar + storage interconnection.” Solar Power World. Available  
at: https://www.solarpowerworldonline.com/2022/06/illinois-rule-changes-will-simplify-solar-storage-  
interconnection/.  
California and Hawaii. In Hawaii, for example, limited-export standards have been in place since  
2016. Despite the incredibly high penetration of DERs in Hawaii, Hawaiian Electric has not filed  
comments or discussed with stakeholders any record of thermal impacts or reported safety  
concerns related to inadvertent export from systems with limited-export controls.  
Overall, it is clear both that multiple states have adopted or are adopting rules similar to what the  
Commission contemplates and to which Consumers Energy and DTE Electric object, and  
regardless of what rules a state adopts, the safety and technical standards still apply. For these  
reasons, Consumers Energy and DTE Electric’s “safety arguments” should be seen for what they  
are — an attempt to dissuade the Commission from adopting meaningful updates to its  
interconnection rules that will advance customers’ energy independence and resiliency.  
Standard Fees  
In general, as stated in previous comments to the Commission, Michigan EIBC believes that fees  
for the pre-application reports, simplified track (see comments below), non-export track, and fast  
track should be established uniformly by the Commission. It is well-established that  
interconnection applicants should pay the full costs of any required in-depth studies, but  
reasonable initial fee caps should also be established by the Commission. The final MIXDG  
rules establish reasonable fees for pre-application reports, non-export track, and fast track as well  
as initial fee caps for more in-depth studies. However, the utilities argue in their Joint Petition  
that “[there] is a problem with the fees that the MIXDG rules use for actions and studies required  
by the rules. . .”14  
The initial fees established in the final MIXDG rules for the pre-application report ($300), non-  
export track ($100 + $1/kWac), and fast track initial review ($100 + $1/kWac for certified DERs  
and $100 + $2/kWac for non-certified DERs) are aligned with those in the Model  
Interconnection Procedures established by IREC.15 As such, similar standard fees have been  
14 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. p. 18.  
15 Interstate Renewable Energy Council. “Model Interconnection Procedures.” 2019. Available at:  
https://irecusa.org/resources/irec-model-interconnection-procedures-2019/.  
established by other states including, for example Illinois,16 New Mexico,17 Pennsylvania,18 and  
Utah.19 The reviews required by the utilities for the pre-application report, non-export track, and  
fast track initial review are relatively limited in scope. For example, in the final MIXDG rules,  
according to R 460.932, “[the] pre-application report may include only existing and readily  
available data. A request for a pre-application report does not obligate an electric utility to  
conduct a study or other analysis of the proposed DER if data is not readily available.” Similarly,  
for the initial fast track review, the utility is required only to review the DER using a limited  
number of relatively simple initial review screens (R 460.946). There is no clear reason why  
Michigan’s utilities should have significantly higher costs than other Midwest utilities to conduct  
these initial reviews or, if they do currently have higher costs, why efficiencies could not be  
found to decrease costs.  
The fees, as outlined in the final MIXDG rules, for the pre-application report, non-export track,  
and fast track initial review are reasonable and should serve as reasonable limits on what a utility  
may collect. However, as outlined below, according to R 460.926 (4), an electric utility “that  
expects to incur costs greater than the fees listed in subrule (2) or initial fee caps listed in subrule  
(3) of this rule in the evaluation of an interconnection application may file a request for a waiver  
pursuant to R 460.910.”20 A determination as to whether such a waiver is warranted would likely  
be made by the Commission under an expedited proceeding and without the level of stakeholder  
participation that occurs during a contested case proceeding. Given the language in R 460.926, it  
is unclear whether a utility would have to prove, via the provision of actual expenses, that their  
costs exceed those listed in the final MIXDG rules to obtain a waiver. As such, Michigan EIBC  
16 Illinois Joint Committee on Administrative Rules. Title 83: Public Utilities, Chapter 1: Illinois Commerce  
Commission, Subchapter c: Electric Utilities, Part 466 Electric Interconnection of Distributed Generation Facilities.  
Available at: https://www.ilga.gov/commission/jcar/admincode/083/08300466sections.html.  
17 New Mexico Commission of Public Records. Title 17: Public Utilities and Utility Services, Chapter 9: Electric  
Services, Part 568: Interconnection of Generating Facilities with a Rated Capacity up to and Including 10 MW  
Connecting to a Utility System. Available at: https://www.srca.nm.gov/parts/title17/17.009.0568.html.  
18 Commonwealth of Pennsylvania. Pennsylvania Code. Title 52, Chapter 69. Available at:  
https://www.pacodeandbulletin.gov/Display/pacode?file=/secure/pacode/data/052/chapter69/s69.2104.html&d=redu  
ce#:~:text=§%2069.2104.-  
,Interconnection%20application%20fees.,relating%20to%20interconnection%20standards)%3A.  
19 Utah Admin. Code 746-312-13. Available at: https://casetext.com/regulation/utah-administrative-code/public-  
service-commission/title-r746-administration/rule-r746-312-electrical-interconnection/section-r746-312-13-  
interconnection-fees-and-charges.  
20 Michigan Public Service Commission Order. Case No. U-20890. March 17, 2022.  
does not believe that a utility should be allowed to petition for a waiver of the fees listed in R  
460.926 subrule (2) for the pre-application report, non-export track, and fast track initial review  
without a clear showing with evidence (e.g., through a contested case process) that reasonable  
utility processes to undertake these reviews cost more than the established fees.  
Material Modifications  
In their Joint Petition, the utilities state that changes to the definition of “material modification”  
in the final MIXDG rules “presents the [utilities] with a virtually infinite number of illegal,  
unsafe, and unreliable configurations with no apparent recourse.”21 Specifically, the Joint  
Petition notes concerns with the addition of a statement in R 460.901b(n) that “[replacing] a  
component with another component that has near-identical characteristics does not constitute a  
material modification.” Michigan EIBC strongly encourages the Commission to reject these  
arguments and retain the language in R 460.901b(n), including the description of the required  
review to determine that a modification is material, in the final MIXDG rules.  
Throughout the development of the MIXDG rules, Michigan EIBC provided comments  
emphasizing the importance of ensuring that fair, thorough reviews are conducted to determine  
whether or not a modification is “material” in nature. It is critical, as is done in the final MIXDG  
rules, that the Commission spell out clearly in the rules what types of changes are material and  
what types of changes are not material. This is especially important for projects that go through  
the study track, given that the time between initial application and approved interconnection  
agreement can be quite long. As a result, equipment or parts included in an initial application  
may no longer be available. If that is the case, it is critical that an applicant be able to substitute a  
“near-identical” component from a different manufacturer, and that such an allowance be clearly  
indicated in the rules.  
Separately, it is critical in the legacy net metering (“LNM”) and distributed generation (“DG”)  
section of the MIXDG rules that the addition of energy storage to an existing DG system does  
21 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing. Case No. U-20890.  
April 14, 2022. p. 13.  
not result in an applicant being terminated from the LNM or DG program. The final rules state in  
R 460.1001 (7)(c) that:  
The addition of an energy storage device to an existing approved legacy net metering  
program system or distributed generation program system is considered a material  
modification. The electric utility interconnection procedures must include details  
describing how energy storage equipment may be integrated into an existing legacy net  
metering program system without impacting the 10-year grandfathering period or  
participation in the distributed generation program.22  
It appears that the intention of the Commission is to avoid the situation where a rooftop solar  
customer in the LNM or DG program with multiple years still left on their agreement is removed  
from the program when that customer adds an on-site energy storage system. However, if the  
addition of an energy storage device to an existing LNM or DG program system is considered a  
material modification (as stated in the final MIXDG rules), it is likely that a utility would require  
a customer adding an energy storage device to file a new interconnection application, which  
could trigger removal from the LNM or DG program. However, given that these systems would  
be export-limited with an inverter or power supply controller, the addition of storage will not  
increase the generation capacity of the customer’s electric generator. As such, based on a plain  
reading of section 183 of Public Act 342, it would be illegal to remove the customer against their  
will from the LNM or DG program prior to the end of the grandfathering period.23 This will  
become more critical toward the end of 2022 as installations near the DG program caps for both  
DTE Electric and Consumers Energy. If the relevant DG cap has been reached, a customer who  
needs to reapply when adding a storage system may find the DG program closed and then may  
not only not be able to add their storage device, but also, may be unable to continue to use their  
existing solar panels. If the Commission retains the language in R 460.1001 (7)(c), it is critical  
that the Commission also clearly confirm that utility procedures must ensure that customers are  
not harmed.  
22 Michigan Public Service Commission Order. Case No. U-20890. March 17, 2022. p. 49.  
23 Public Act 342 of 2016. Section 183. Available at: https://www.legislature.mi.gov/documents/2015-  
2016/publicact/htm/2016-PA-0342.htm.  
Simplified Track  
In the final MIXDG rules as proposed, the Commission deleted the simplified track, which was a  
set of limited screens to evaluate level 1 or level 2 projects. Throughout the process to develop  
the MIXDG rules, Michigan EIBC advocated for and supported the addition of the simplified  
track. Although the screens in the simplified track were a subset of those included in the fast  
track, by selecting the screens most critical to evaluate small projects, the simplified track would  
enable a faster, more streamlined evaluation of the smallest on-site generators that are very  
unlikely to require additional study.  
Michigan EIBC strongly recommends that the Commission retain the simplified track in the  
MIXDG rules. In addition to the ability to streamline projects, the simplified track also required  
that the fee for the simplified track plus any LNM or DG program application fee could not  
together exceed a total of $50. However, with the deletion of the simplified track (as is done in  
the final MIXDG rules), level 1 and 2 projects would instead go through fast track, which has a  
fee of $100 + $1/kWac. There is no language in the final MIXDG rules to ensure that a customer  
would not be charged both a LNM or DG program application fee of $50 plus a fast track fee of  
$100 + $1/kWac. A customer with a 50 kW level 2 project applying for interconnection under  
the DG program would have paid $50 in total under the previous version of the MIXDG rules.  
With the elimination of the simplified track, that same customer may have to pay a $50  
application fee for the DG program plus a $150 fee for the fast track, for a total of $200. In  
addition to the ability to streamline and quickly review level 1 and 2 projects, the retention of the  
simplified track would provide clear, reasonable, and standard fees for customers. Moreover,  
increased fees for level 1 customers do nothing to help ensure that middle- and lower-income  
customers can access DERs. It is these customers who could often benefit most from the long-  
term savings provided by DERs.  
Interconnection Penalties  
Michigan EIBC observes that the interconnection penalties provided for in R 460.990 only apply  
to DERs greater than 100 kW. Smaller systems are more frequently associated with smaller  
customers, who are less likely to have the resources to protect their right to interconnect under  
the MIXDG rules. Allowing an electric utility to impede interconnection for smaller systems  
without consequences sends the wrong message to utilities and treats smaller customers as  
second-class customers. Michigan EIBC recommends that the Commission revise R 460.990 to  
remove 100 kW limitation on the availability of penalties as follows:  
R 460.990 Interconnection penalties.  
Rule 90. Pursuant to section 10e of 1939 PA 3, MCL 460.10e, an electric utility  
shall take all necessary steps to ensure that DERs are connected to the distribution  
systems within their operational control. If the commission finds, after notice and  
hearing, that an electric utility has prevented or unduly delayed the ability of a  
DER greater than 100 kW to connect to the distribution system of the electric  
utility, the commission may order remedies designed to make whole the applicant  
proposing the DER, including, but not limited to, reasonable attorney fees. If the  
electric utility violates this rule, the commission may order fines of not more than  
$50,000 per day, commensurate with the demonstrated impact of the violation.  
Recommended Clarifications  
As the Commission considers further comments on the MIXDG rules, Michigan EIBC suggests  
certain clarifications to improve the rules and facilitate interconnection.  
First, related to informal mediation under R 460.904, rule 4(3) provides that the parties to an  
interconnection dispute may request informal mediation by a Commission interconnection  
ombudsperson. The rule, however, does not specify any timeframe by when such informal  
mediation must occur. Because time is often important to the interconnection process and the  
MIXDG rules require other dispute resolution steps that may be needed before an  
interconnection dispute is resolved, Michigan EIBC suggests that the Commission require an  
initial meeting with the ombudsperson within 10 days of the request for informal mediation  
being submitted. The absence of such language may unnecessarily prolong the resolution of an  
interconnection dispute. Specifically, Michigan EIBC recommends that Rule 4(3) be revised as  
follows:  
(3) In the event that parties are unable to resolve the dispute privately, the parties  
may, by mutual agreement, make a written request for informal mediation to the  
commission staff. The informal mediation shall commence within 10 days of  
submission of the written request and be conducted by an interconnection  
ombudsperson who shall be a member of the commission staff and designated by  
the commission. Both parties may choose to have attorneys or appropriate  
representation present.  
Second, related to R 460.906 and the provisions governing formal mediation, rule 6(1) provides  
that if “the parties have been unable to resolve a dispute through the informal mediation process  
under R 460.904, the parties shall then attempt to resolve the dispute in the following manner:”  
This language implies that informal mediation is required, but R 460.904 clearly characterizes  
informal mediation as voluntary after the direct discussion and informal negotiation required  
under Rule 4(2). Because time is often important in interconnection, Michigan EIBC agrees with  
treating informal mediation as an optional step in the dispute resolution process. To remedy this  
inconsistency with R 460.904, Michigan EIBC recommends revising Rule 6(1) of R 406.906 to  
read as:  
(1) If the parties have been unable to resolve a dispute through either the  
required direct discussion or informal negotiation or the voluntary informal  
mediation process under R 460.904, the parties shall then attempt to resolve the  
dispute in the following manner:  
Third, we recommend a revision related to R 460.910, which provides for waivers. As written,  
Rule 10 is ambiguous as to which party has the burden of demonstrating the necessity of a  
waiver, the duration of any waiver, and the circumstances under which a waiver may be granted.  
Michigan EIBC proposes deleting the existing Rule 10 and replacing it with the following:  
R 460.910 Waivers  
Rule 10. (1) The Commission may, on application of an electric utility, customer,  
alternative electric supplier, or interconnection customer, or on its own motion,  
grant a temporary or permanent waiver from 1 or more provisions of these rules in  
situations in which the Commission finds that:  
(a) the provision from which the waiver is granted is not statutorily mandated;  
(b) there is good cause for the waiver, and it is in the public interest; and  
(c) the provision from which the waiver is granted would, as applied in the  
presented situation, be unreasonable or unnecessarily burdensome.  
(2) The burden of proof in establishing a right to a waiver shall be on the party  
seeking the waiver.  
(3) An applicant for a waiver may request expeditious processing.  
Fourth, related to interconnection applications under R 460.936, rule 36(7)(b) sets forth the  
electric utility’s obligation to provide a written list of deficiencies in an interconnection  
application and how such deficiencies are to be addressed. Importantly, however, the rule does  
not prevent the utility from later adding to the list new, unrelated deficiencies. To prevent a  
utility from unnecessarily prolonging the interconnection process, the Commission should clarify  
the rule to confirm the utility’s obligation to provide a comprehensive list of deficiencies within  
10 days of submission of an interconnection application. Michigan EIBC proposes the following  
modification of Rule 36(7)(b):  
(b) If the application is incomplete or non-conforming, the electric utility shall  
provide to the applicant a written list of all deficiencies with the notification. The  
applicant shall have 60 business days from the date of electric utility notification  
to submit the necessary information and may provide up to 2 submissions during  
this time period. After each submission of information, the electric utility shall  
have 10 business days to notify the applicant that the interconnection application  
is either accepted or rejected due to continuing deficiencies. A utility may not  
identify additional deficiencies beyond those originally identified. If the  
applicant does not meet the timelines required by this rule, the utility may  
withdraw the application.  
Michigan EIBC’s final recommendation is related to the requirement in R 460.938 that an  
electric utility publish on its website a list of interconnection requests it has received. As written,  
the rule seems to suggest that in a month in which no changes have occurred, no update  
whatsoever is required to the list. In such situations, it would not be clear whether the lack of an  
update is due to the lack of any changes or the failure to update the list as required. To avoid any  
confusion, Michigan EIBC recommends that the rule require a utility to at least update the list to  
indicate that no changes have occurred since the prior month. Michigan EIBC suggests the  
following language to reflect this:  
(1) An electric utility shall maintain a publicly available interconnection list,  
which is available in a sortable spreadsheet format. The sortable spreadsheet must  
be provided to the public upon request. An electric utility that has received not  
less than 100 complete interconnection applications in a year shall publish this list  
on the electric utility’s website. The public interconnection list must be updated  
monthly. If unless no changes to the spreadsheet have occurred in that month, a  
note to that effect must be clearly indicated on the spreadsheet. The date of  
the most recent update must be clearly indicated.  
General Offices:  
One Energy Plaza  
Jackson, MI 49201  
LEGAL DEPARTMENT  
SHAUN M. JOHNSON  
Senior Vice President  
and General Counsel  
Tel:  
Fax:  
(517) 788-0550  
(517) 768-3644  
Robert W. Beach  
Don A. D’Amato  
Gary A. Gensch, Jr.  
Matthew D. Hall  
Georgine R. Hyden  
Katie M. Knue  
Robert F. Marvin  
Jason M. Milstone  
Rhonda M. Morris  
Deborah A. Moss*  
Maxwell K. Multer  
Chantez L. Pattman  
Michael C. Rampe  
Scott J. Sinkwitts  
Theresa A.G. Staley  
Maribeth Tabaka  
Janae M. Thayer  
Anne M. Uitvlugt  
Aaron L. Vorce  
*Washington Office:  
1730 Rhode Island Ave. N.W. Tel:  
Suite 1007  
(202) 778-3340  
(202) 778-3355  
MELISSA M. GLEESPEN  
Vice President, Corporate  
Secretary and Chief  
Washington, DC 20036  
Fax:  
Compliance Officer  
Writer’s Direct Dial Number: (517) 788-0698  
Writer’s E-mail Address: gary.genschjr@cmsenergy.com  
KELLY M. HALL  
Vice President and Deputy  
General Counsel  
June 27, 2022  
Emerson J. Hilton  
Adam C. Smith  
Bret A. Totoraitis  
Assistant General Counsel  
Ms. Lisa Felice  
Executive Secretary  
Attorney  
Michigan Public Service Commission  
7109 West Saginaw Highway  
Post Office Box 30221  
Lansing, MI 48909  
RE: MPSC Case No. U-20890 – In the matter, on the Commission's own motion, to  
promulgate rules governing electric interconnection and distributed generation and  
to rescind legacy interconnection and net metering rules.  
Dear Ms. Felice:  
Enclosed for electronic filing in the above-captioned proceeding, please find Consumers Energy  
Company’s Comments on Proposed Rule Changes.  
This is a paperless filing and is therefore being filed only in PDF.  
Sincerely,  
Gary A. Gensch, Jr.  
S T A T E O F M I C H I G A N  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter of the Commission’s own motion, )  
to promulgate rules governing electric  
interconnection and distributed generation  
and to rescind legacy interconnection and  
net metering rules.  
)
)
)
)
)
Case No. U-20890  
CONSUMERS ENERGY COMPANY’S COMMENTS  
ON PROPOSED RULE CHANGES  
I.  
INTRODUCTION  
On March 17, 2022 the Michigan Public Service Commission (“MPSC” or the  
“Commission”) issued an Order responding to the comments and approving a revised version of  
the Interconnection and Distribution Generation Standards (“MIXDG Rules”) for adoption in  
Case No. U-20890. On April 14, 2022, Consumers Energy Company (“Consumers Energy” or the  
“Company”) and DTE Electric Company (“DTE Electric”) filed a joint petition for rehearing of  
the March 17 Order pursuant to Mich Admin Code, R 792.10437, regarding the MIXDG Rules  
(“Joint Petition for Rehearing”). On May 12, 2022, the Commission granted the Joint Petition for  
Rehearing and indicated that it would provide a second public hearing and opportunity to comment  
on the MIXDG Rules. On May 26, 2022 the Commission issued its Order and Notice of Hearing  
in Case No. U-20890 (“May 26, 2022 Order”) regarding the promulgation of the MIXDG Rules  
and recission of the legacy Electric Interconnection and Net Metering Standards, Mich Admin  
Code, R.460.601a et seq, which were adopted in the May 26, 2009 Order in Case No. U-15787.  
The May 26, 2022 Order scheduled a public hearing for June 22, 2022, to allow presentations by  
interested persons, and set a final deadline for written comments at 5:00 pm on June 27, 2022.  
1
Consumers Energy participated in ten stakeholder sessions addressing potential  
Interconnection Rules, and five stakeholder meetings addressing potential Distributed Generation  
rules, hosted by MPSC Staff between December 2018 and March 2020, as directed by the  
Commission in the November 8, 2018 order in Case No. U-20344. Consumers Energy provided  
feedback in response to two draft rule sets in strawman proposals on August 28, 2019, and May 1,  
2020, respectively. Consumers Energy also provided comments in response to the Commission’s  
September 9, 2021 Order in Case No. U-20890.  
In filing these comments in response to the most recent draft of the proposed MIXDG  
Rules, pursuant to the May 26, 2022 Order, Consumers Energy reiterates its positions and  
recommendations previously expressed in its comments provided as feedback to strawman  
proposals on August 28, 2019 and May 1, 2020, and its November 1, 2021 comments in the  
U-20890 docket, and provides additional comments below.  
II.  
COMMENTS  
A.  
Note on Consumers Energy and DTE Electric Joint Petition for  
Rehearing  
The Company would like to express its appreciation to the Commission for granting the  
Joint Petition for Rehearing. In the following comments, Consumers Energy will highlight and  
expand upon several areas of significant concern that necessitate the reversal of much of the  
language and new definitions added to the MIXDG Rules in the March 17, 2022 Commission  
Order. If not corrected, these issues will at a minimum result in confusion and disagreements  
between utilities and applicants for years to come and have the potential to result in safey and  
reliability concerns to the electric grid as more customers are interconnected over time.  
In the alternative, should the Commission elect not to reinstate the language from the  
version of the MIXDG Rules included as Exhibit B to the Commission’s September 9, 2021 Order  
2
in this docket (“September 9, 2021 Proposed Rules”) as discussed below, where applicable  
Consumers Energy has also included proposed revisions to the recently revised language in the  
MIXDG Rules that would reduce the risk of both safety concerns and confusion of interpretation.  
In addition to the comments below, Consumers Energy has included a redlined version of  
the May 26, 2022 MIXDG Rules revisions as Attachment A.  
B.  
R 460.980 – Concerns with Load Offsets and System Protections  
The revised version of the MIXDG Rules and definitions reflected in the May 26, 2022  
Order requires utilities to study a Distributed Energy Resource (“DER”) assuming that the owner  
will maintain the current load for the lifespan of the DER. The language in R 460.980(4)(a)-(c)  
could be interpreted by applicants as indicating that if their generation is small relative to their  
load, that there would not be the possibility of flowback, and they do not need to utilize any  
protection.  
This is a safey and reliability concern because the utility has no control over a customer’s  
load, and how it may change over time. If a customer with a large system significantly reduces  
load, this increases the amount of flowback to the system that cannot be studied during  
interconnection. If export capacity increases because minimum load is gone, this could lead to  
equipment failures and voltage issues. It is not prudent for the utility to study the impact of a DER  
assuming the current (or future) owner will maintain the minimum load for the lifespan of the  
DER. The best remedy for this safety and reliability concern is to revert the language in R 460.980  
to the language captured in R 460.980 of the September 9, 2021 Proposed Rules, which would  
include the removal of R 460.980(4)(a)-(c).  
If the Commission maintains the requirement in R 460.980 that the utility must study the  
DER based on load, the Commission should remove the statement in R 460.980(4)(c) that  
protective functions are not required. Consumers Energy is concerned with R 460.980(4)(c)  
3
because the current rules could be interpreted such that no protective relaying is required beyond  
reverse power protection and minimum import relaying. There are other types of relaying that  
may be required for the protection of the system, such as fault protective and anti-islanding  
relaying. If R 460.980(4)(c) is maintained in its current form, then the specific protection functions  
will need to be specified to clarify that this references R 460.980(4)(a) and (b) only so that it is  
clear utilities are not precluded from requiring additional standard interconnection protection  
relaying defined in the utility interconnection procedures.  
C.  
R 460.901a-b and R 460.980 – New Definitions, Rules Allow Battery  
Generation to be Expanded Without Study  
The currently proposed MIXDG Rules added new definitions, including Limited Export  
(R 460.901b(k)) and Ongoing Operating Capacity (R 460.901b(x)). The rules also revised the  
definition of Material Modification (R 460.901b(n)). These changes in tandem with new language  
in R 460.980 Capacity of the DER result in permitting battery storage and generation to be  
expanded as long as the export value remains the same, which is a concern for the safety and  
reliability of the system.  
R 460.980(1) states that “If the interconnection application requests an increase in  
capacity for an existing DER, the electric utility shall evaluate the application based on the new  
ongoing operating capacity of the DER” (emphasis added). The language in R 460.980(4)  
requires that “If a DER uses any configuration or operating mode in this subrule to limit the export  
of electrical power across the point of common coupling, then the generating capacity shall be  
only the amount capable of being exported not including any inadvertent export” (emphasis  
added).  
These new definitions and rules operate together to effectively deny a utility’s ability to  
consider the actual size of a proposed interconnection both during the application process and after  
4
the application process if the applicant increases nameplate capacity, but the export value is  
unchanged. The actual size of the interconnection is no longer defined by the actual generation  
equipment installed, and the utility is not able to consider this in the screening process or perform  
a more detailed study. This is exacerbated by the potentially overlooked impact of level  
determination which may cause a project to bypass a necessary study for a generator of a given  
size. This is a safety and reliability concern because the maximum capacity of an interconnection  
could be far greater than the export-limited capacity and would dangerously overload the system  
if export-limiting failed. In order to avoid this safety and reliability concern, the Commission  
should revert R 460.980 to the previous language in the September 9, 2021 Proposed Rules.  
Additionally, definitions for “Limited Export,” (R 460.901b(k)), “Ongoing Operating Capacity”  
(R 460.901b(x)), “Aggregate Capacity” (R 460.901a(d)), “Export Capacity” (R 460.901a(bb)), and  
“Generating Capacity” (R 460.901a(gg)), should be removed from the Rules to eliminate the  
potential confusion and safety concern associated with studying a proposed interconnection at its  
Ongoing Operating Capacity. The definition for “Material Modification” in R 460.901b(n) should  
also be revised to mirror the definition provided in the September 9, 2021 Propossed Rules as  
reflected in the Company’s attached redline. The recently revised version of this definition  
included in the May 26, 2022 Order replaced the term “nameplate rating” with “generating  
capacity.”  
Furthermore, the ability of a generator to use a DER’s limited export to use the non-export  
track could function in a way that creates confusion and could render this track useless. If a  
developer is changing the nameplate size of its system, it is unclear how this track would apply.  
For example, if a generator has 1 MW of aggregate nameplate capacity and 500 kW load, it is  
5
unclear whether this would result in the generator considered to have negative 500 kW of capacity.  
Further clarification is necessary and may result in further Company concern.  
D.  
R 460.980 Capacity of the DER - Concern with Technical Items Defined  
in Rules, Language Regarding Third-Party Certification of Devices  
As indicated on page 8 of the Joint Petition for Rehearing, the revised Rules allow for 30  
seconds of “Inadvertent Export” by an interconnected project before it must be brought into  
compliance in R 460.980. This is a significant amount of time during which a transformer could  
fail catastrophically, cause a fire, and impact power quality for other customers. This safety  
concern is exacerbated by the fact that the proposed rules do not allow a utility to consider the  
actual size of a proposed interconnection both during the application process and after the  
application process if the applicant increases nameplate capacity, but the export value is  
unchanged. This means a customer could have a significant amount of nameplate capacity beyond  
its “ongoing operating capacity” that could be inadvertently exported for up to 30 seconds under  
the current draft rules.  
The best way to rectify this safety and reliability concern is to remove R 460.980(4)(e)  
from the MIXDG Rules and restore the September 9, 2021 Proposed Rules version of R 460.980,  
which would include the removal of R 460.980(4). Additionally, the definition of “Inadvertent  
Export” should be removed. In the alternative, if the Commission elects not to remove R  
460.980(4)(e) and the Inadvertent Export definition, the Commission should adjust the language  
as reflected in Consumers Energy’s attached redline of the MIXDG Rules to permit utilities to  
define the allowable time for “inadvertent export” in their Interconnection and Distributed  
Generation Procedures. This revision would be consistent with UL 1741 CRD for PCS, which  
provides that “the maximum open loop response shall be less than or equal to 30 seconds. Faster  
PCS response times are allowed and may be required to meet specific utility requirements.” The  
6
30 seconds of inadvertent export is a maximum boundary, and the standard is explicit in allowing  
utilies to define the appropriate response time to inadvertent export. If the Commission elects to  
maintain R 460.980(4)(e) in the MIXDG Rules, then Consumers Energy requests this language be  
updated as described to ensure consistency with UL 1741 CRD for PCS.  
Another concern is the language in R 460.980(4)(e) that permits a DER to utilize “a  
nationally recognized testing laboratory certified power control system and inverter system that  
results in the DER disconnecting from the distribution system. . . ” (emphasis added). This  
language may lead to confusion and misinterpetation of UL 1741 CRD for PCS. UL 1741 CRD  
for PCS is a standard for certifying that a device functions to limit export, but this certification  
does not include information on tripping or ceasing to energize. This language in R 460.980(4)(e)  
appears to assume that the UL 1741 CRD for PCS certification of a device automatically means  
that the device is certified to “disconnect[ ] from the distribution system” when inadvertent export  
occurs – but this is not correct. UL 1741 CRD for PCS certification does not indicate that a  
certified inverter will disconnect from the system or have additional protection from failure when  
inadvertent export occurs.  
To correct this, Consumers Energy reiterates its recommendation that R 460.980(4) should  
be removed from the Rules. If the Commission elects not to do so, the Commission should strike  
the language in R 460.980(4)(e) that is not included in UL 1741 CRD for PCS.  
E.  
R 460.901 (a-b) Definitions – Lack of Clarity  
The addition of four intertwining definitions (Aggregate Capacity in R 460.901a(d), Export  
Capacity in R 460.901a(bb), Generating Capacity in R 460.901a(gg), and Ongoing Operating  
Capacity in R 460.901b(x)) included in the MIXDG Rules broadly impact the rules and are of  
concern to the Company. These recently added definitions alter what has been considered the  
baseline for determining project capacity for the duration of the working groups held to discuss  
7
the development of updated Interconnection and Distributed Generation Rules and now leave a  
great deal of ambiguity. Most importantly, the level definitions (R 460.901b(e-i)) were written  
with an understanding of only one capacity definition, and it is now unclear which of the above  
definitions applies for determining the project level. This in turn adds confusion about track  
selection, screening, and study implications. In light of the ambiguity introduced at this stage of a  
lengthy process, Consumers Energy strongly recommends the removal of these added definitions.  
F.  
R 460.946(4)(b) – Daytime Loading Concerns  
The current proposed R 460.946(4)(b) would require an electric utility to “consider 100%  
of applicable loading, if available, instead of 15% of line section peak load for level 1 and level 2  
DER,” and also require utilities with 1,000,000 or more customers to collect daytime loading data  
by January 2023, or as otherwise defined in their procedures. Consumers Energy is concerned  
with this requirement because remote access to daytime loadings is not readily available on all line  
sections and the data will be dynamic as meters are exchanged or line sections changed. The  
dynamic nature of the data will require constant re-calculation to remain valid. Additionally, the  
requirement to provide this data in an expedited fashion would also result in significant expense  
to develop this capability. Utilities should only be required to consider using applicable loading  
as the data becomes available as part of normal business practices. The Company recommends  
that the Commission remove the language associated with this requirement as indicated in the  
Company’s redline.  
G.  
R 460.946, R 460.950 Concerns with Time to Study Proposed  
Interconnections, Allowing for Additional Screens  
The revised Rules no longer allow utilities to include additional screens in the review  
process to ensure the safety of a project in R 460.946. If the screens currently included in the  
Rules are not sufficient and more study is needed, under the current proposed Rules utilities may  
8
not have enough time to perform a Facilities Study to further study the project. Future changes or  
revelations in technology that are not foreseen could require additional screens. If utilities do not  
have the flexibility in the future, a project could be inadequately reviewed in too short of a time  
frame under the screens/studies outlined in the Rules, while still posing a safety concern that would  
be best addressed under an additional utility screen. This need for flexibility is demonstrated, for  
example, in R 460.946(4)(b) Fast Track; Initial Review. This screen requires the utility to compare  
a DER’s capacity against daytime loading for Level 1 and 2 applicants. This screen is only looking  
at daytime loading, which would make sense for solar DERs, but may not accurately contemplate  
non-solar inverter based resources that are certified devices. Examples include wind resources,  
hybrid resource, and possible future Electric Vehicle (“EV”) Programs.  
The Company requests this flexibility be included again in the rules by reinstating language  
from the September 9, 2021 Proposed Rules permitting this flexibility to address issues that may  
not be seen now. The reinstated language is captured in the Company’s redline of the proposed  
MIXDG Rules under R 460.950 Fast track: supplemental review and R 460.946 Fast track; initial  
review.  
Additionally, the Rules no longer permit a utility to perform screens for Level 1 and Level  
2 non-export DER applications in R 460.946 in several circumstances. Consumers Energy is  
concerned that excluding Level 1 and/or Level 2 applications from screening inhibits utilities from  
exercising the flexibility to review smaller projects that may be aggregated, and in aggregate could  
pose safety and reliability concerns to the system. For this reason, Consumers Energy requests the  
corresponding language in 460.946(4)(b), (d), and (e) be removed as reflected in the Company’s  
redline.  
9
H.  
R 460.942 Non-Export Track Review - Concerns with Time to Study  
Proposed Interconnections  
Consumers Energy realized while reviewing the revised MIXDG Rules for implementation  
that the R 460.942 non-export track review will need to be modified to provide clarity that a project  
that passess screens which may still be a safety concern may undergo a facilities study.  
Specificially, R 460.942(4)(a) is conditioned upon “no interconnection facilities, distribution  
upgrades, further study, or application modifications” (emphasis added), but the greater  
non-export track process only addresses further study and application modification requirements.  
Including such language would be consistent with R 460.946(5) in the fast track; initial review.  
The current language in R 460.942 makes it unclear if utilities will have sufficient time to study  
proposed interconnections or have the ability to perform a more detailed facilities study if safety  
concerns are present. It is unclear if this difference between the non-export track and fast track  
was intentional. Given the difference between the fast track and non-export track review,  
depending on the procedural review track of a given project, the Rules may not provide sufficient  
time for the utility to complete a facility study of a project in the non-export track if needed.  
While the Company understands the desire for a speedy review process, to ensure safety  
and reliability of the system, it is critical that this is balanced against a need to have sufficient time  
to study applications. Newly added language regarding export-limiting, inverter safety, and  
system protections creates additional challenges in ensuring the safety of proposed projects, and  
these concerns are further heightened when coupled with current timelines and screening  
limitations. As technology continues to advance, it is important that utilities have the ability to  
review new and unique configurations to ensure safety of personnel and the system.  
The Company recommends that the MIXDG Rule language is made consistent between  
the fast track and non-export track study regarding the ability to transition the study to a Facilities  
10  
Study. These recommended updates are included in R 460.942 in Consumers Energy’s redlined  
copy of the MIXDG Rules.  
Additionally, in R 460.942 Non-export track review, the Company recommends the  
removal of language permitting screens to be used to waive interconnection faclities, distribution  
upgrades, or application modifications. The Company notes that these screens are meant to  
determine project eligibility for the non-export track, and not to waive the aforementioned items.  
I.  
Additional Comments  
In R 460.942(1), the language in the first sentence was revised in the most recent draft of  
the Rules to state that “Interconnection applications for DERs that will limit injection of electric  
energy…are eligible for evaluation under the non-export track.” The Company recommends that  
this language be adjusted to state that ““Interconnection applications for DERs that will not inject  
electric energy…are eligible for evaluation under the non-export track” as reflected in the  
Company’s redline. This change is necessary because applications that limit injection are eligible  
under the fast-track process, whereas the non-export track was created for applications that will  
not inject - i.e. non-export.  
In R 460.942(4), the Company’s redline reflects recommended changes to the last sentence.  
As indicated in the redline comments in the margin, the non-export track review screens are meant  
to determine project elgibility for the non-export track and should not be used to waive  
interconnection facilities, distribution upgrades, or application modificatons.  
If the Commission does not remove language from R 460.946(4)(b) as reflected in the  
Company’s redline comments, Consumers Energy requests further clarifiation of language stating  
that “the electric utility shall consider 100% of applicable loading, if available, instead of 15% of  
line section peak load for level 1 and 2 DER.” The Company believes that the first value should  
be 33% rather than 100%. The “15% of line section peak load for level 1 and 2 DER” appears to  
11  
be referring to the anti-islanding screen. If that is correct, this 15% threshold comes from  
calculating minimum load based on 45% of peak load multiplied by the 33% anti-islanding ratio  
typically applied to synchronous generators. Multiplying the two percentages (45% and 33%)  
arrives at 15%. Based on this technical derivation, Consumers Energy believes the value of  
“100%” should be adjusted to “33%” as reflected in the Company’s redlined comments.  
Lastly, beyond comments included above on R 460.980 Capacity of the DER, if the  
Commission elects not to revert the section to the language included in the September 9, 2021  
Proposed Rules, the Company has included additional comments in its redline for consideration to  
update language in R 460.980(4).  
Respectfully submitted,  
CONSUMERS ENERGY COMPANY  
12  
ATTACHMENT A  
Attachment A  
Page 1 of 50  
DEPARTMENT OF LICENSING AND REGULATORY AFFAIRS  
PUBLIC SERVICE COMMISSION  
INTERCONNECTION AND DISTRIBUTED GENERATION STANDARDS  
Filed with the secretary of state on  
These rules take effect immediately upon filing with the secretary of state unless adopted  
under section 33, 44, or 45a(9) of the administrative procedures act of 1969, 1969 PA  
306, MCL 24.233, 24.244, or 24.245a. Rules adopted under these sections become  
effective 7 days after filing with the secretary of state.  
(By authority conferred on the public service commission by section 7 of 1909 PA 106,  
MCL 460.557, section 5 of 1919 PA 419, MCL 460.55, sections 4, 6, and 10e of 1939 PA  
3, MCL 460.4, 460.6, and 460.10e, and section 173 of the clean and renewable energy  
and energy waste reduction act, 2008 PA 295, MCL 460.1173)  
R 460.901a, R 460.901b, R 460.902, R 460.904, R 460.906, R 460.908, R 460.910, R  
460.911, R 460.920, R 460.922, R 460.924, R 460.926, R 460.928, R 460.930, R  
460.932, R 460.934, R 460.936, R 460.938, R 460.940, R 460.942, R 460.944, R  
460.946, R 460.948, R 460.950, R 460.952, R 460.954, R 460.956, R 460.958, R  
460.960, R 460.962, R 460.964, R 460.966, R 460.968, R 460.970, R 460.974, R  
460.976, R 460.978, R 460.980, R 460.982, R 460.984, R 460.986, R 460.988, R  
460.990, R 460.991, R 460.992, R 460.1001, R 460.1004, R 460.1006, R 460.1008, R  
460.1010, R 460.1012, R 460.1014, R 460.1016, R 460.1018, R 460.1020, R 460.1022, R  
460.1024, and R 460.1026 are added to the Michigan Administrative Code, as follows:  
PART 1. GENERAL PROVISIONS  
R 460.901a Definitions; A-I.  
Rule 1a. As used in these rules:  
(a) “AC” means alternating current at 60 Hertz.  
(b) “Affected system” means another electric utility’s distribution system, a municipal  
electric utility’s distribution system, the transmission system, or transmission system-  
connected generation which may be affected by the proposed interconnection.  
(c) “Affiliate” means that term as defined in R 460.10102(1)(a).  
(d) “Aggregate capacity” or “aggregate generation capacity” means the aggregated  
ongoing operating capacities of all DERs across multiple points of common coupling,  
within a defined portion of the distribution system.  
(e) “Alternative electric supplier” means that term as defined in section 10g of 1939 PA  
3, MCL 460.10g.  
April 7, 2022  
Attachment A  
Page 2 of 50  
2
(f) “Alternative electric supplier distributed generation program plan” means a  
document supplied by an alternative electric supplier that provides detailed information to  
an applicant about the alternative electric supplier's distributed generation program.  
(g) “Alternative electric supplier legacy net metering program plan” means a document  
supplied by an alternative electric supplier that provides detailed information to an  
applicant about the alternative electric supplier's legacy net metering program.  
(h) “Applicant” means the person or entity submitting an interconnection application, a  
legacy net metering program application, or a distributed generation program application.  
An applicant is not required to be an existing customer of an electric utility. An electric  
utility is considered an applicant when it submits an interconnection application for a  
DER that is not a temporary DER.  
(i) “Application” means an interconnection application, a legacy net metering program  
application, or a distributed generation program application.  
(j) “Area network” means a location on the distribution system served by multiple  
transformers interconnected in an electrical network circuit.  
(k) “Business day” means Monday through Friday, starting at 12:00:00 a.m. and ending  
at 11:59:59 p.m., excluding electric utility holidays and any day in which electric service  
is interrupted for 10% or more of an electric utility’s customers. A list of electric utility  
holidays shall be provided in the electric utility’s interconnection procedures.  
(l) “Calendar day” means every day including Saturdays, Sundays, and holidays.  
(m) “Certified” means an inverter-based system has met acceptable safety and  
reliability standards by a nationally recognized testing laboratory in conformance with  
IEEE 1547.1-2020 and the UL 1741 September 28, 2021 edition except that prior to  
January 1, 2023, inverter-based systems which conform to the UL 1741SA September 7,  
2016 edition are acceptable.  
(n) “Commission” means the Michigan public service commission.  
(o) “Commissioning test” means the test and verification procedure that is performed  
on a device or combination of devices forming a system to confirm that the device or  
system, as designed, delivered, and installed, meets the interconnection and  
interoperability requirements of IEEE 1547-2018. A commissioning test must include  
visual inspections and may include, as applicable, an operability and functional  
performance test and functional tests to verify interoperability of a combination of  
devices forming a system.  
(p) “Conforming” means the information in an interconnection application is consistent  
with the general principles of distribution system operation and DER characteristics.  
(q) “Customer” means a person or entity who receives electric service from an electric  
utility’s distribution system or a person who participates in a legacy net metering or  
distributed generation program through an alternative electric supplier or electric utility.  
(r) “DC” means “direct current.”  
(s) “Distributed energy resource” or “DER” means a source of electric power and its  
associated facilities that is connected to a distribution system. DER includes both  
generators and energy storage devices capable of exporting active power to a distribution  
system.  
(t) “Distributed generation program” means the distributed generation program  
approved by the commission and included in an electric utility’s tariff pursuant to section  
Attachment A  
Page 3 of 50  
3
6a(14) of 1939 PA 3, MCL 460.6a, or established in an alternative electric supplier  
distributed generation program plan.  
(u) “Distribution system” means the structures, equipment, and facilities owned and  
operated by an electric utility to deliver electricity to end users, not including  
transmission and generation facilities that are subject to the jurisdiction of the federal  
energy regulatory commission.  
(v) “Distribution upgrades” mean the additions, modifications, or improvements to the  
distribution system necessary to accommodate a DER’s connection to the distribution  
system.  
(w) “Electric utility” means any person or entity whose rates are regulated by the  
commission for selling electricity to retail customers in this state. For purposes of R  
460.901a through R 460.992 only, “electric utility” includes cooperative electric utilities  
that are member regulated as provided in section 4 of the electric cooperative member-  
regulation act, 2008 PA 167, MCL 460.34.  
(x) “Electrically coincident” means that 2 or more proposed DERs associated with  
pending interconnection applications have operating characteristics and nameplate  
capacities which require that distribution upgrades will be necessary if the DERs are  
installed in electrical proximity with each other on a distribution system.  
(y) “Electrically remote” means a proposed DER is not electrically coincident with a  
DER that is associated with a pending interconnection application.  
(z) “Eligible electric generator” means a methane digester or renewable energy system  
with a generation capacity limited to a customer’s electric need and that does not exceed  
either of the following:  
(i) 150 kWac of aggregate generation at a single site for a renewable energy system.  
(ii) 550 kWac of aggregate generation at a single site for a methane digester.  
(aa) “Energy storage device” means a device that captures energy produced at one time,  
stores that energy for a period of time, and delivers that energy as electricity for use at a  
future time. For purposes of these rules, an energy storage device may be considered a  
DER.  
(bb) “Export capacity” means the maximum possible simultaneous generation of the  
DER, and is calculated as the maximum amount of export as permitted by limiting the  
amount of the DER’s export at the point of common coupling.  
(cc) “Facilities study” means a study to specify and estimate the cost of the equipment,  
engineering, procurement, and construction work if distribution upgrades or  
interconnection facilities are required.  
(dd) “Fast track” means the procedure used for evaluating a proposed interconnection  
that makes use of screening processes, as described in R 460.944 to R 460.950.  
(ee) “Force majeure event” means an act of God; labor disturbance; act of the public  
enemy; war; insurrection; riot; fire, storm, or flood; explosion, breakage, or accident to  
machinery or equipment; an emergency order, regulation or restriction imposed by  
governmental, military, or lawfully established civilian authorities; or another cause  
beyond a party’s control. A force majeure event does not include an act of negligence or  
intentional wrongdoing.  
(ff) “Full retail rate” means the power supply and distribution components of the cost of  
electric service. Full retail rate does not include a system access charge, service charge,  
or other charge that is assessed on a per meter, premise, or customer basis.  
Attachment A  
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(gg) “Generating capacity” means the maximum nameplate rating of a DER in  
alternating current, except that where this capacity is limited by any of the methods of  
limiting electrical export, generating capacity shall be the net capacity as limited though  
the use of such methods not including inadvertent export.  
(hh) “Good standing” means an applicant has paid in full all undisputed bills rendered  
by the interconnecting electric utility and any alternative electric supplier in a timely  
manner and none of these bills are in arrears.  
(ii) “Governmental authority” means any federal, state, local, or other governmental  
regulatory or administrative agency, court, commission, department, board, or other  
governmental subdivision, legislature, rulemaking board, tribunal, or other governmental  
authority having jurisdiction over the parties, their respective facilities, or the respective  
services they provide, and exercising or entitled to exercise any administrative, executive,  
police, or taxing authority or power; provided, however, that this term does not include  
the applicant, interconnection customer, electric utility, or any affiliate thereof.  
(jj) “GPS” means global positioning system.  
(kk) “Grid network” means a configuration of a distribution system or an area of a  
distribution system in which each customer is supplied electric energy at the secondary  
voltage by more than 1 transformer.  
(ll) “High voltage distribution” means those parts of a distribution system that operate  
within a voltage range specified in the electric utility’s interconnection procedures. For  
purposes of these rules, the term “subtransmission” means the same as high voltage  
distribution.  
(mm) “IEEE” means institute of electrical and electronics engineers.  
(nn) “IEEE 1547-2018” means “IEEE Standard for Interconnection and Interoperability  
of Distributed Energy Resources with Associated Electric Power Systems Interfaces,” as  
adopted by reference in R 460.902.  
(oo) “IEEE 1547.1-2020” means IEEE “Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces,” as adopted by reference in R 460.902.  
(pp) “Inadvertent export” means the potential condition in which a normally non-  
exporting or limited-exporting DER experiences an unscheduled export that does not  
exceeds the limited-export value limitations in terms of magnitude or for less than the  
duration as specified in UL 1741 CRD for PCS.  
(qq) “Independent system operator” means an independent, federally-regulated entity  
established to coordinate regional transmission in a non-discriminatory manner and to  
ensure the safety and reliability of the transmission and distribution systems.  
(rr) “Initial review” means the fast track initial review screens described in R 460.946.  
(ss) “Interconnection” means the process undertaken by an electric utility to construct  
the electrical facilities necessary to connect a DER with a distribution system so that  
parallel operation can occur.  
(tt) “Interconnection agreement” means an agreement containing the terms and  
conditions governing the electrical interconnection between the electric utility and the  
applicant or interconnection customer. Where construction of interconnection facilities or  
distribution upgrades are necessary, the agreement shall specify timelines, cost estimates,  
and payment milestones for construction of facilities and distribution upgrades to  
interconnect a DER into the distribution system, and shall identify design, procurement,  
Commented [A1]: The Company’s first preference and  
recommendation is for the deletion of this definition per  
Consumers Energy’s comments. If the Commission elects  
not to remove this definition, the edit shown is recommended  
with the following comment:  
The UL 1741 CRD for PCS does not specify a magnitude  
limitation above the limited-export value. For certification,  
it specifies the time that the unscheduled export must fall  
below the power limited value. The standard states the time  
frame is 30 seconds unless defined by the utility. For  
example, a 20kW DER power limited to 10kW could pass  
certification if it had a 20kW inadvertent export for less than  
the timeframe defined in the standard.  
Attachment A  
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installation, and construction requirements associated with installation of the DER.  
Standard level 1, 2, and 3 interconnection agreements and level 4 and 5 interconnection  
agreements are types of interconnection agreements.  
(uu) “Interconnection coordinator” means a person or persons designated by the electric  
utility who shall serve as the point of contact from which general information on the  
application process and on the affected system or systems can be obtained through  
informal request by the applicant or interconnection customer.  
(vv) “Interconnection customer” means the person or entity, which may include the  
electric utility, responsible for ensuring a DER is operated and maintained in compliance  
with all local, state, and federal laws, as well as with all rules, standards, and  
interconnection procedures.  
(ww) “Interconnection facilities” mean any equipment required for the sole purpose of  
connecting a DER with a distribution system.  
(xx) “Interconnection procedures” mean the requirements that govern project  
interconnection adopted by each electric utility and approved by the commission.  
(yy) “Interconnection study agreement” means an agreement between an applicant and  
an electric utility for the electric utility to study a proposed DER.  
R 460.901b Definitions; J-Z.  
Rule 1b. As used in these rules:  
(a) “kW” means kilowatt.  
(b) “kWac” means the electric power, in kilowatts, associated with the alternating  
current output of a DER at unity power factor.  
(c) “kWh” means kilowatt-hours.  
(d) “Legacy net metering program” means the true net metering or modified net  
metering programs in place prior to commission approval of a distributed generation  
program tariff pursuant to section 6a(14) of 1939 PA 3, MCL 460.6a, and prior to the  
establishment of an alternative electric supplier distributed generation plan.  
(e) “Level 1” means a certified project of 20 kWac or less.  
(f) “Level 2” means a certified project of greater than 20 kWac and not more than 150  
kWac.  
(g) “Level 3” means a project of 150 kWac or less that is not certified, or a project  
greater than 150 kWac and not more than 550 kWac.  
(h) “Level 4” means a project of greater than 550 kWac and not more than 1 MWac.  
(i) “Level 5” means a project of greater than 1 MWac.  
(j) “Level 4 and 5 interconnection agreement” means an interconnection agreement  
applicable to level 4 and 5 interconnection applications.  
(k) “Limited export” means the exporting capability of a DER whose generating  
capacity is limited by the use of any configuration or operating mode.  
(l) “Low voltage distribution” means those parts of a distribution system that operate  
with a voltage range specified in the electric utility’s interconnection procedures.  
(m) “Mainline” means a conductor that serves as the three-phase backbone of a low  
voltage distribution circuit.  
(n) “Material modification” means a modification to the DER generating  
capacitynameplate rating, electrical size of components, bill of materials, machine data,  
Attachment A  
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6
equipment configuration, or the interconnection site of the DER at any time after  
receiving notification by the electric utility of a complete interconnection application.  
Replacing a component with another component that has near-identical characteristics  
does not constitute a material modification. For the proposed modification to be  
considered material, it shall have been reviewed and been determined to have or  
anticipated to have a material impact on 1 or more of the following:  
(i) The cost, timing, or design of any equipment located between the point of common  
coupling and the DER.  
(ii) The cost, timing, or design of any other application.  
(iii) The electric utility’s distribution system or an affected system.  
(iv) The safety or reliability of the distribution system.  
(o) “Methane digester” means a renewable energy system that uses animal or  
agricultural waste for the production of fuel gas that can be burned for the generation of  
electricity or steam.  
(p) “Modified net metering” means an electric utility billing method that applies the  
power supply component of the full retail rate to the net of the bidirectional flow of kWh  
across the customer interconnection with the electric utility’s distribution system during a  
billing period or time-of-use pricing period.  
(q) “MW” means megawatt.  
(r) “MWac” means the electric power, in megawatts, associated with the alternating  
current output of a DER at unity power factor.  
(s) “Nameplate capacity” means the maximum active power, in kWac or MWac, at  
which a DER is capable of sustained operation.  
(t) “Nameplate rating” means all of the following at which a DER is capable of  
sustained operation:  
(i) Nominal voltage (V).  
(ii) Current (A).  
(iii) Maximum active power (kWac).  
(iv) Apparent power (kVA).  
(v) Reactive power (kvar).  
(u) “Nationally recognized testing laboratory” means any testing laboratory recognized  
by the accreditation program of the United States Department of Labor Occupational  
Safety and Health Administration.  
(v) “Network protector” means those devices associated with a secondary network used  
to automatically disconnect a transformer when reverse power flow occurs.  
(w) “Non-export track” means the procedure for evaluating a proposed interconnection  
that will not inject electric energy into an electric utility’s distribution system, as  
described in R 460.942.  
(x) “Ongoing operating capacity” means the actual simultaneous generating capacity,  
taking into account the operational differences of load offset and export. If the  
contribution of energy storage to the total contribution is limited by programing of the  
maximum active power output, use of a power control system, use of a power relay, or  
some other mutually agreed upon, on-site limiting element, only the capacity that is  
designed to inject electricity to the utility’s distribution system, other than inadvertent  
exports and fault contribution, will be used within certain technical screens and  
evaluations.  
Attachment A  
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7
(y) “Parallel operation” means the operation, for longer than 100 milliseconds, of a DER  
while connected to the energized distribution system.  
(z) “Party” or “parties” means an electric utility, applicant, or interconnection customer.  
(aa) “Point of common coupling” means the point where the DER connects with the  
electric utility’s distribution system.  
(bb) “Power control system” means systems or devices which electronically limit or  
control steady state currents to a programmable limit and certified under UL 1741 CRD  
for PCS by a nationally recognized testing laboratory.  
(cc) “Radial supply” means a configuration of a distribution system or an area of a  
distribution system in which each customer can only be supplied electric energy by 1  
substation transformer and distribution line at a time.  
(dd) “Readily available” means no creation of data is required, and little or no  
computation or analysis of data is required.  
(ee) “Reasonable efforts” mean, with respect to an action required to be attempted or  
taken by a party under these interconnection rules, efforts that are as timely as possible  
and consistent with those a party would take to protect its own interests.  
(ff) “Regional transmission operator” means a voluntary organization of electric  
transmission owners, transmission users, and other entities approved by the federal  
energy regulatory commission to efficiently coordinate electric transmission planning,  
expansion, operation, and use on a regional and interregional basis.  
(gg) “Renewable energy credit” means a credit granted pursuant to the commission's  
renewable energy credit certification and tracking program in section 41 of the clean and  
renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1041.  
(hh) “Renewable energy resource” means that term as defined in section 11(i) of the  
clean and renewable energy and energy waste reduction act, 2008 PA 295, MCL  
460.1011.  
(ii) “Renewable energy system” means that term as defined in section 11(k) of the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1011.  
(jj) “Secondary network” means those areas of a distribution system that operate at a  
secondary voltage level and are networked.  
(kk) “Site” means a contiguous site, regardless of the number of meters at that site. A  
site that would be contiguous but for the presence of a street, road, or highway is  
considered to be contiguous for the purposes of these rules.  
(ll) “Spot network” means a location on the distribution system that uses 2 or more  
inter-tied transformers to supply an electrical network circuit, such as a network circuit in  
a large building.  
(mm) “Standard level 1, 2, and 3 interconnection agreement” means the statewide  
interconnection agreement approved by the commission and applicable to levels 1, 2 and  
3 interconnection applications. A cover sheet including modifications to address any  
special operating conditions may be added.  
(nn) “Study track” means the procedure used for evaluating a proposed interconnection  
as described in R 460.952 to R 460.962.  
(oo) “Supplemental review” means the fast track supplemental review screens described  
in R 460.950.  
(pp) “System impact study” means a study to identify and describe the impacts to the  
electric utility’s distribution system that would occur if the proposed DER were  
Attachment A  
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interconnected exactly as proposed and without any modifications to the electric utility’s  
distribution system. A system impact study also identifies affected systems.  
(qq) “Temporary DER” means a DER that is installed on the distribution system by the  
electric utility with the intention of not operating at the site permanently.  
(rr) “True net metering” means an electric utility billing method that applies the full  
retail rate to the net of the bidirectional flow of kWh across the customer interconnection  
with the electric utility’s distribution system, during a billing period or time-of-use  
pricing period.  
(ss) “UL” means underwriters laboratory.  
(tt) “UL 1741” means the September 28, 2021 edition of “Standard for Inverters,  
Converters, Controllers and Interconnection System Equipment for Use With Distributed  
Energy Resources,” as adopted by reference in R 460.902.  
(uu) "UL 1741 CRD for PCS" means the Certification Requirement Decision for Power  
Control Systems for the standard titled Inverters, Converters, Controllers and  
Interconnection System Equipment for Use With Distributed Energy Resources, March 8,  
2019, as adopted by reference in R 460.902(b).  
R 460.902 Adoption of standards by reference.  
Rule 2. (1) The standards specified in these rules are adopted by reference as follows:  
(a) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, September 28, 2021  
edition, is available from Underwriters Laboratories at the internet website:  
https://standardscatalog.ul.com/ProductDetail.aspx?productId=UL1741 at a cost of  
$798.00 at the time of adoption of these rules.  
(b) UL 1741 Standard for Inverters, Converters, Controllers and Interconnection  
System Equipment for Use With Distributed Energy Resources, January 28, 2010 edition,  
is available from Underwriters Laboratories at the internet  
website: https://standardscatalog.ul.com/ProductDetail.aspx?productId=UL1741 at a  
cost of $716.00 at the time of adoption of these rules.  
(c) ANSI C84.1 – 2016 Electric Power Systems and Equipment – Voltage Ratings (60  
Hz), June 9, 2016, is available from the American National Standards Institute, Inc. at the  
internet website https://webstore.ansi.org/ at a cost of $111.24 at the time of adoption of  
these rules.  
(d) The following standards adopted by reference are available from IEEE at the  
internet website https://standards.ieee.org at the time of adoption of these rules.  
(i) The IEEE 1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating  
Installations on Power Systems, October 30, 2015, is available at a cost of $99.00 -  
$147.00 at the time of adoption of these rules.  
(ii) The IEEE 1547 - 2018, IEEE Standard for Interconnection and Interoperability of  
Distributed Energy Resources with Associated Electric Power System Interfaces, April 6,  
2018, is available at a cost of $149.00 - $224.00 at the time of adoption of these rules.  
(iii) The IEEE 1547.1-2020 IEEE Standard Conformance Test Procedures for  
Equipment Interconnecting Distributed Energy Resources with Electric Power Systems  
and Associated Interfaces, May 21, 2020, is available at a cost of $197.00 - $296.00 at the  
time of adoption of these rules.  
Attachment A  
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9
(iv) The IEEE 519-2014 IEEE Recommended Practice and Requirements for  
Harmonic Control in Electric Power Systems, June 11, 2014, is available at a cost of  
$52.00 - $66.00 at the time of adoption of these rules.  
(2) The commission has copies of the standards specified in subrule (1) of this rule  
available for review at its offices located at 7109 W. Saginaw Hwy., Lansing, Michigan  
48917-1120. The mailing address is Michigan Public Service Commission, P.O. Box  
30221, Lansing, Michigan 48909-0221.  
R 460.904 Informal mediation.  
Rule 4. (1) The parties shall attempt to resolve all disputes arising out of the  
interconnection process, as defined by R 460.901a through R 460.992, according to the  
provisions of this rule.  
(2) Prior to formal mediation under R 460.906, the parties shall attempt to resolve any  
conflict without commission intervention through direct discussion and informal  
negotiation.  
(3) In the event that parties are unable to resolve the dispute privately, the parties may,  
by mutual agreement, make a written request for informal mediation to the commission  
staff. The informal mediation shall be conducted by an interconnection ombudsperson  
who shall be a member of the commission staff and designated by the commission. Both  
parties may choose to have attorneys or appropriate representation present.  
(4) During informal mediation, the parties shall discuss relevant facts pertaining to the  
dispute and the relief being sought. The interconnection ombudsperson and relevant  
commission staff shall be present to facilitate the discussion and provide guidance among  
the parties. Parties shall operate in good faith and use best efforts to resolve the dispute.  
(5) If a resolution is reached by the end of the meeting or meetings, the parties may draft  
a resolution of the dispute.  
(6) If the parties reach impasse and are unable to resolve the dispute, the parties shall  
proceed to the formal mediation process described in R 460.906.  
R 460.906 Formal mediation.  
Rule 6. (1) If the parties have been unable to resolve a dispute through the informal  
mediation process under R 460.904, the parties shall then attempt to resolve the dispute in  
the following manner:  
(a) The complaining party shall file a written notice of dispute with the commission.  
The notice of dispute must state the specific grounds for the dispute, sufficient facts to  
support the allegations, the relief requested, and must contain all information, testimony,  
exhibits, or other documents and information within the party’s possession on which the  
party intends to rely to support the party’s position.  
(b) The complaining party shall give notice that it is invoking the procedures in this  
rule. The complaining party shall send the notice to the non-complaining party’s email  
address and file the notice with the commission.  
(c) The non-complaining party shall acknowledge the notice of dispute within 10  
business days of its receipt and identify a representative with the authority to make  
decisions on its behalf with respect to the dispute.  
Attachment A  
Page 10 of 50  
10  
(d) An administrative law judge shall serve as the mediator in these proceedings. The  
administrative law judge may request and receive assistance from commission staff.  
(e) Within 60 business days from the date the non-complaining party acknowledges the  
dispute, the mediator shall issue a recommended settlement.  
(f) Within 5 business days after the date the recommended settlement is issued, each  
party shall file with the commission a written acceptance or rejection of the  
recommended settlement. If the parties accept the recommendation, then the  
recommendation shall become an order. If a party rejects or fails to respond within 5  
business days to the recommended settlement, then the dispute may proceed to a  
contested case hearing before the commission as provided in R 792.10415.  
(2) Nothing in these rules precludes a disputing party from filing a formal complaint  
with the commission, either instead of or after pursuing informal mediation or formal  
mediation pursuant to these rules.  
(3) The initiation of any form of dispute resolution by a party tolls any applicable  
deadlines under these rules until the dispute is resolved.  
R 460.908 Timelines for electric utilities serving fewer than 1,000,000 in-state customers.  
Rule 8. An electric utility serving fewer than 1,000,000 in-state customers shall have an  
additional 10 business days to comply with the timelines in R 460.911 to R 460.1026.  
This rule does not apply to applicants or interconnection customers.  
R 460.910 Waivers.  
Rule 10. An electric utility, customer, alternative electric supplier, applicant, or  
interconnection customer may apply to the commission for a waiver from 1 or more  
provisions of these rules and may request expeditious processing. The commission may  
grant a waiver upon a showing of good cause and a finding that the waiver is in the public  
interest.  
PART 2. INTERCONNECTION STANDARDS  
R 460.911 Applicability.  
Rule 11. These rules apply to all interconnection applications filed on or after the  
effective date of these rules. The electric utility shall complete work on any  
interconnection study agreement executed prior to the effective date of these rules  
pursuant to the terms and conditions of that interconnection study agreement. Any new  
studies or other additional work must be completed pursuant to these rules. An electric  
utility or an alternative electric supplier shall not restrict access to interconnection for  
level 1, level 2, and level 3 DERs that are not participants in the legacy net metering or  
distributed generation programs.  
Attachment A  
Page 11 of 50  
11  
R 460.920 Electric utility interconnection procedures.  
Rule 20. (1) An electric utility shall file applications for approval of interconnection  
procedures and forms within 30 business days of the effective date of these rules.  
(2) The commission shall issue its order approving, rejecting, or modifying the proposed  
interconnection procedures and forms within 360 calendar days of the effective date of  
these rules. If the commission finds the procedures and forms proposed by the electric  
utility to be inadequate or unacceptable, the commission may either adopt procedures and  
forms proposed by another person in the proceeding or modify and accept the procedures  
and forms proposed by the electric utility.  
(3) Until the commission accepts, rejects, or modifies an electric utility’s  
interconnection procedures and forms, the electric utility may use the proposed  
interconnection procedures and forms when processing interconnection applications with  
the exception of fixed fees and fee caps. An electric utility shall only charge fees that  
comply with the requirements of R 460.926 until the commission accepts, rejects, or  
modifies the proposed interconnection procedures and forms unless the commission  
approves different fees pursuant to R 460.926(4).  
(4) Two or more electric utilities may file a joint application proposing interconnection  
procedures for use by the joint applicants. The proposed interconnection procedures must  
ensure compliance with these rules.  
(5) The proposed interconnection procedures must, at a minimum, include all of the  
following:  
(a) All necessary applications, forms, and relevant template agreements.  
(b) A schedule of all applicable fixed fees and fee caps.  
(c) Voltage ranges for high voltage distribution and low voltage distribution.  
(d) Required initial review screens.  
(e) Required supplemental review screens.  
(f) The process for conducting system impact studies and facilities studies on DERs  
when there is an affected system issue.  
(g) Testing and certification requirements of DER telecommunications, cybersecurity,  
data exchange, and remote control operation.  
(h) Parallel operation requirements.  
(i) A method to estimate the expected annual kWh output of the generator or  
generators.  
(j) Acceptable methods or standards for power-limited export DERs in compliance with  
allowances in R 460.980.  
(k) A cost allocation methodology for study track DERs.  
(l) An evaluation of an interconnection application for a project that includes single or  
multiple types of DERs at a site for which the applicant seeks a single point of common  
coupling.  
(m) Details describing how an energy storage device may be integrated into an existing  
legacy net metering program system without impacting the 10-year grandfathering period  
or participation in the distributed generation program.  
Attachment A  
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12  
(n) For electric utilities that are member-regulated electric cooperatives, a procedure for  
fairly processing applications in instances in which the number of applications exceed the  
capacity of the electric cooperative to timely meet the deadlines in these rules.  
(o) Examples of modifications that are not material modifications.  
(p) The procedure for performing a material modification review to determine if a  
modification is material.  
(q) Any required terms and conditions which must be specified in the general liability  
insurance for level 3, 4, and 5 projects.  
(r) A list of the electric utility’s holidays.  
(s) If an electric utility uses an alternative process pursuant to R 460.956, a description  
of that process.  
(6) An electric utility shall obtain commission approval to revise its interconnection  
procedures.  
R 460.922 Online applications and electronic submission.  
Rule 22. (1) An electric utility shall allow pre-application report requests,  
interconnection applications, and interconnection agreements to be submitted  
electronically, such as, through the electric utility’s website or via email.  
(2) An electric utility shall dedicate a page on its website or direct customers to a linked  
website with information on these rules. The relevant information available to an  
applicant or interconnection customer via a website must include all of the following:  
(a) These rules and interconnection procedures in an electronically searchable format.  
(b) The electric utility’s applications and all associated forms in a format that allows for  
electronic entry of data.  
(c) Sample documents including, at a minimum, a 1-line diagram with required labels.  
(d) Contact information for the electric utility’s DER interconnection coordinator,  
including an email address and a phone number.  
(e) Directions for the submission of applications.  
R 460.924 Communications.  
Rule 24. (1) An electric utility shall designate 1 or more interconnection coordinators.  
The telephone number and e-mail address of the interconnection coordinator or  
coordinators must be made available on the electric utility’s website. The interconnection  
coordinator or coordinators must be available to provide reasonable assistance to the  
applicant or interconnection customer but is not responsible to directly answer or resolve  
all of the issues that may arise in the interconnection process.  
(2) An applicant may designate an application agent. An application agent may serve as  
the single point of contact for the applicant and may coordinate with the electric utility on  
the applicant’s behalf. Designation of an application agent does not absolve the applicant  
from signing interconnection documents or from complying with the requirements in  
these rules and the interconnection agreement.  
(3) An electric utility must be indemnified by the applicant and its application agent  
with respect to assistance provided by an interconnection coordinator or coordinators.  
Attachment A  
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13  
R 460.926 Fees.  
Rule 26. (1) After the effective date of these rules, fees for the pre-application report,  
the non-export track and the fast track shall be established as listed in subrule (2) of this  
rule. Initial fees for the study track shall not exceed initial fee caps as established in  
subrule (3) of this rule. Fees must remain in effect until interconnection procedures are  
approved by the commission under R 460.920.  
(2) The fee amounts for the pre-application report, non-export track, and fast track for  
all levels of DERs are as follows:  
(a) The pre-application report fee may not exceed $300.  
(b) The non-export track fee may not exceed $100 + $1/kWac for certified DERs and  
$100 + $2/kWac for non-certified DERs.  
(c) The fast track initial review fee is $100 + $1/kWac for certified DERs and $100 +  
$2/kWac for non-certified DERs.  
(d) Any applicable legacy net metering program application fee pursuant to R  
460.1004(7) or distributed generation program application fee pursuant to R 460.1006(6),  
together, may not exceed a total of $50.  
(3) The initial fee caps for a fast track supplemental review and the study track for all  
levels of DERs are as follows:  
(a) The fee for a fast track supplemental review including all review screens may not  
exceed $1,000.  
(b) The study track fee for interconnection application review and the scoping meeting  
may not exceed $300.  
(c) The system impact study fee may not exceed $10,000.  
(d) The facilities study fee may not exceed $15,000.  
(4) The fees listed in subrule (2) and initial fee caps listed in subrule (3) of this rule,  
must be displayed prominently on the electric utility’s interconnection website.  
(5) An electric utility that expects to incur costs greater than the fees listed in subrule  
(2) or initial fee caps listed in subrule (3) of this rule in the evaluation of an  
interconnection application may file a request for a waiver pursuant to R 460.910.  
R 460.928 Fee and fee cap modifications.  
Rule 28. (1) An electric utility shall include in its proposed interconnection procedures  
fixed fees to replace the fees specified in R 460.926(2)(a), (b), and (c), and add any  
other fixed fees the electric utility considers necessary.  
(2) An electric utility shall include in its proposed interconnection procedures adjusted  
fee caps to replace the initial fee caps specified in R 460.926(3)(a), (b), (c), and (d), and  
add any other fee caps the electric utility considers necessary. An electric utility may  
charge actual costs up to the fee caps.  
(3) The fixed fees must be specific to level size and be based on estimates of reasonable  
costs to perform the applicable service or study. The fee caps must be specific to level  
size and be based on a reasonable range of costs for performing the applicable study.  
(4) The most recently approved fixed fees and fee caps must be listed in the electric  
utility’s interconnection procedures and displayed prominently on the electric utility’s  
interconnection website.  
Attachment A  
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(5) The fixed fees and fee caps that are approved for inclusion in the electric utility’s  
interconnection procedures by the commission may be reviewed at any time by the  
electric utility and adjusted, if necessary, subject to commission review and approval.  
(6) Any modification of fees may not be applicable to fees already paid.  
(7) An electric utility that expects to incur costs greater than its prevailing fee caps in  
the evaluation of an interconnection application may file a request for a waiver pursuant  
to R 460.910.  
R 460.930 Pre-application report request form.  
Rule 30. (1) An applicant shall submit a completed pre-application report request form  
and the required fee for a pre-application report on a proposed level 4 or level 5 DER.  
(2) The pre-application report request form must include all of the following  
information:  
(a) Project contact information, including name, address, phone number, and email  
address.  
(b) Project location, as accurately as can be identified, which may be given by any of  
the following:  
(i) Street address with nearby cross streets and town.  
(ii) An aerial map with location clearly marked.  
(iii) GPS coordinates.  
(c) Account number, meter number, structure number, or other equivalent information  
identifying the proposed point of common coupling, if available.  
(d) Whether the DER is any of the following:  
(i) Solar.  
(ii) Wind.  
(iii) Cogeneration.  
(iv) Storage.  
(v) Solar with storage.  
(vi) Other type of DER.  
(e) Capacity of the DER types in alternating current kW and kVA, and kWh for  
storage.  
(f) Whether the DER configuration is single or 3-phase.  
(g) Whether the DER will be a stand-alone generator, meaning no onsite load other than  
station service.  
(h) Whether the DER will be certified.  
(i) Whether new service is requested. If there is existing service, the customer account  
number and site minimum and maximum current or proposed electric loads in kW, if  
available, must be included, and how the load is expected to change must be specified.  
(j) Whether the location is new construction.  
R 460.932 Pre-application report.  
Rule 32. (1) Using the information provided in the pre-application report request form  
described in R 460.930, an electric utility shall identify the substation bus, bank, or  
circuit most likely to serve the point of common coupling. This identification by the  
Attachment A  
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electric utility does not necessarily indicate that this would be the circuit to which the  
project ultimately connects.  
(2) An applicant may request additional pre-application reports if information about  
multiple points of common coupling is requested. No more than 10 pre-application  
report requests may be submitted by an applicant and its affiliates during a 1-week  
period. An electric utility may reject additional pre-application report requests.  
(3) The pre-application report must include all of the following information:  
(a) Total capacity, in MW, of substation bus, bank, or circuit based on normal or  
operating ratings likely to serve the proposed point of common coupling.  
(b) Existing aggregate generation capacity, in MW, interconnected to a substation bus,  
bank, or circuit likely to serve the proposed point of common coupling.  
(c) Aggregate capacity, in MW, of generation not yet built but found in previously  
accepted interconnection applications, for a substation bus, bank, or circuit likely to serve  
the proposed point of common coupling.  
(d) Available capacity, in MW, of substation bus, bank, or circuit likely to serve the  
proposed point of common coupling.  
(e) Substation nominal distribution voltage.  
(f) Nominal distribution circuit voltage at the proposed point of common coupling.  
(g) Label, name, or identifier of the distribution circuit on which the proposed point of  
common coupling is located.  
(h) Approximate circuit distance between the proposed point of common coupling and  
the substation.  
(i) The actual or estimated peak load and minimum load data at any relevant line  
section or sections, including daytime minimum load and absolute minimum load, when  
available. If not readily available, the report must indicate whether the generator is  
expected to exceed minimum load on the circuit.  
(j) Whether the point of common coupling is located behind a line voltage regulator and  
whether the substation has a load tap changer.  
(k) Limiting conductor ratings from the proposed point of common coupling to the  
distribution substation.  
(l) Number of phases available at the primary voltage level at the proposed point of  
common coupling, and, if a single phase, distance from the 3-phase circuit.  
(m) Whether the point of common coupling is located on a spot network, area network,  
grid network, radial supply, or secondary network.  
(n) Based on the proposed point of common coupling, the report must indicate whether  
power quality issues may be present on the circuit.  
(o) Whether or not the area has been identified as having a prior affected system.  
(p) Whether or not the site will require a system impact study for high voltage  
distribution based on size, location, and existing system configuration.  
(4) The pre-application report may include only existing and readily available data. A  
request for a pre-application report does not obligate an electric utility to conduct a study  
or other analysis of the proposed DER if data is not readily available. The pre-  
application report must also indicate any information listed in subrule (3) of this rule that  
is not readily available. An electric utility may, at its discretion, return any portion of the  
pre-application report fee because some or all information does not exist.  
Attachment A  
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16  
(5) Pre-application report requests must be processed in the order in which an electric  
utility received the requests.  
(6) An electric utility shall provide the data required in the pre-application report to the  
applicant within 20 business days of receipt of the completed request form and payment  
of the fee. The pre-application report produced by the electric utility is non-binding and  
does not confer any rights on the applicant.  
R 460.934 Site control.  
Rule 34. (1) Documentation of site control must be submitted with the application by  
the applicant.  
(2) For level 3, 4, or 5 DERs, site control may be demonstrated by providing  
documentation that shows any of the following:  
(a) Ownership of, a leasehold interest in, or a right to develop a site for the purpose of  
constructing and operating the DER.  
(b) An enforceable option to purchase or acquire a leasehold site for this purpose.  
(c) A legally binding agreement transferring a present real property right to specified  
real property along with the right to construct and operate a DER on the specified real  
property for a period of time not less than 5 years.  
(3) For level 1 or 2 DERs, proof of site control may be demonstrated by the site owner’s  
signature and contact information on the application.  
(4) An applicant may redact commercially sensitive information from site control  
documents.  
R 460.936 Interconnection applications.  
Rule 36. (1) An electric utility shall provide an interconnection application for an  
applicant to complete, including for those applicants whose DERs will be configured to  
be non-exporting.  
(2) All documents required for a complete interconnection application must be listed on  
the interconnection application. For level 4 and 5 interconnection applications, the list of  
required documents must include a completed pre-application report.  
(3) For interconnection applications with proposed DERs that fall into level 1, an  
applicant shall provide a 1-line diagram and a site diagram.  
(4) For interconnection applications with proposed DERs that fall into levels 2 and 3, an  
applicant shall provide a 1-line diagram that is either sealed by a professional engineer  
licensed in this state or signed by an electrical contractor who is licensed in this state with  
the electrical contractor’s license number noted on the diagram. An applicant shall also  
provide a site diagram.  
(5) For interconnection applications with proposed DERs that fall into levels 4 and 5, an  
applicant shall provide a 1-line diagram that is sealed by a professional engineer who is  
licensed in this state. An applicant shall also provide a site diagram.  
(6) Applications shall be reviewed to assess whether they are complete and conforming  
in the order in which they were received. An application is considered received when an  
electric utility receives the application, the application’s attachments, and the application  
fee. The application must be date-stamped for the first business day when the electric  
Attachment A  
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utility has received the interconnection application, the application attachments, and  
payment of the application fee. An electric utility shall notify the applicant of receipt of  
the application by the end of the third business day following the date of the date stamp.  
(7) The electric utility shall notify the applicant that the interconnection application is  
either complete and conforming, or incomplete, or non-conforming, within 10 business  
days of the date stamp.  
(a) If an interconnection application is determined to be complete and conforming by the  
electric utility, the applicant must be notified that the interconnection application is  
accepted. The electric utility shall also indicate whether the interconnection application  
will be processed using the non-export track, fast track, or study track.  
(b) If the application is incomplete or non-conforming, the electric utility shall provide  
to the applicant a written list of all deficiencies with the notification. The applicant shall  
have 60 business days from the date of electric utility notification to submit the necessary  
information and may provide up to 2 submissions during this time period. After each  
submission of information, the electric utility shall have 10 business days to notify the  
applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this rule,  
the utility may withdraw the application.  
(8) An electric utility shall comply with part 2 of these rules, R 460.911 to R 460.992,  
and its interconnection procedures when interconnecting DERs that it owns and operates  
onto its distribution system, with the exception of temporary DERs.  
(9) An electric utility shall use the same process when processing and studying  
interconnection applications from all applicants, whether the DER is owned or operated  
by the electric utility, its subsidiaries or affiliates, or others, with the exception of  
temporary DERs.  
(10) An electric utility shall review and update interconnection applications periodically  
to reflect new information required to properly review DERs, subject to commission  
review and approval.  
R 460.938 Public interconnection list.  
Rule 38. (1) An electric utility shall maintain a publicly available interconnection list,  
which is available in a sortable spreadsheet format. The sortable spreadsheet must be  
provided to the public upon request. An electric utility that has received not less than  
100 complete interconnection applications in a year shall publish this list on the electric  
utility’s website. The public interconnection list must be updated monthly unless no  
changes to the spreadsheet have occurred in that month. The date of the most recent  
update must be clearly indicated.  
(2) The public interconnection list must include all of the following:  
(a) An application identifier.  
(b) The date that the electric utility received the application.  
(c) The date that the electric utility considered the application to be complete and  
conforming.  
(d) Whether the application is on the non-export track, fast track, or study track.  
(e) The proposed DER nameplate capacity.  
(f) The proposed DER interconnection size level.  
Attachment A  
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(g) The DER technology type.  
(h) The county and township in which the proposed point of common coupling will be  
located.  
(i) The current status of the application’s progress in the interconnection process.  
(j) The labels, names, or identifiers of the distribution circuit and substation.  
R 460.942 Non-export track review.  
Rule 42. (1) Interconnection applications for DERs that will not inject limit injection of  
electric energy into an electric utility’s distribution system are eligible for evaluation  
under the non-export track. Non-export eligibility requires an existing electrical service  
at the applicant’s premise.  
(2) Subject to review and approval by the commission, an electric utility may limit the  
eligibility of the non-export track in its interconnection procedures based on the  
characteristics of its distribution system.  
Commented [A2]: The language was modified from “will  
not inject” to “will limit injection” in the latest revision.  
Applications that limit injection are eligible under the fast-  
track process. The non-export track was created for  
applications that will not inject (non-export). The Company  
recommends the previous language reflected in this edit be  
reinstated.  
(3) Before submitting an interconnection application, a non-export track applicant may  
contact the electric utility for assistance in determining whether a non-export track review  
will be sufficient or the study track is necessary. The electric utility shall provide the  
applicant assistance based on available information. If the applicant chooses to proceed,  
an interconnection application shall be submitted pursuant to R 460.936.  
(4) Within 20 business days after being notified that the application was accepted, the  
electric utility shall perform an initial review by using some or all of the initial review  
screens specified in the electric utility’s interconnection procedures and notify the  
applicant of the results. If an electric utility chooses to perform a review using a subset  
of the initial review screens, the exclusion of 1 or more screens may not be the only basis  
for the electric utility to require interconnection facilities, distribution upgrades, further  
study, or application modifications.  
(5) If the proposed interconnection passes the initial review screens, or if the proposed  
interconnection fails the screens but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant. If a facilities study is not required, the interconnection  
application must proceed under R 460.964 to an interconnection agreement. If a facilities  
study is required, the interconnection application must proceed under R 460.962.  
(6) If the proposed interconnection fails any of the initial review screens, and the electric  
utility does not or cannot determine that the DER may be interconnected consistent with  
safety, reliability, and power quality standards, the electric utility shall notify the  
applicant, provide the applicant with the results of the application of the initial review  
screens, and offer all of the following options:  
Commented [A3]: The Company notes that the screens are  
meant to determine project eligibility for the non-export  
track and the Company recommends that they should not be  
used to waive interconnection facilities, distribution  
upgrades, or application modifications.  
(a) Attend a customer options meeting, as described in R 460.948.  
(b) Proceed to supplemental review under R 460.950.  
(c) Submit within 60 business days from the date of the electric utility notification, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility. The application modifications must mitigate or eliminate the factors  
that caused the interconnection application to fail 1 or more of the initial review screens.  
After each submission of information, the electric utility has 10 business days to notify  
Attachment A  
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the applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this  
subrule, the electric utility may withdraw the application. After the electric utility  
determines the application is accepted, the revised interconnection application must  
proceed under subrule (4) of this rule.  
(d) Withdraw the interconnection application.  
(7) If the applicant does not select a course of action under subrule (6) of this rule within  
10 business days of notice from the electric utility, the electric utility shall withdraw the  
interconnection application.  
(a) If the notification indicates that no interconnection facilities, distribution upgrades,  
further study, or application modifications are required, the electric utility shall provide  
specifications for any equipment the applicant will be required to install within 20  
business days of the applicant being notified. Within 10 business days of receiving the  
equipment specifications, the applicant shall notify the electric utility whether it will  
proceed under R 460.964 to an interconnection agreement or will withdraw the  
application. The applicant’s failure to notify the electric utility within the required time  
period shall result in the interconnection application being withdrawn by the electric  
utility.  
Commented [A4]: R 460.942 does not address what  
happens if interconnection facilities or distribution upgrades  
are required. It is unclear to Consumers Energy why R  
460.942(4)(a) through the end of the section differ from the  
related fast track process in R 460.946(5-7) that appears to  
accomplish the same purpose more thoroughly. The  
Company believes it would be simpler to implement one  
process rather than two separate but similar processes. The  
Company recommends the language in 460.942(4)(a) be  
revised to reflect the fast track process. Please see the  
Company’s recommend edits as reflected in items 5-7 of this  
section.  
(b) If application modification is offered by the electric utility, the applicant shall either  
withdraw the interconnection application or provide a modified application within 60  
business days from the date of electric utility notification, with up to 2 resubmissions  
during this time period to provide a modified application. After each submission of  
information, the electric utility shall notify the applicant within 10 business day that the  
interconnection application is either accepted or rejected due to continuing deficiencies.  
If the applicant does not meet the timelines required by this subrule, the electric utility  
may withdraw the application. When the applicant provides a modified application, the  
electric utility shall follow the procedure specified in subrule (4) of this rule.  
(5) If further study is required, the electric utility shall present options and the applicant  
shall decide whether to proceed to a supplemental review under R 460.950, or to the  
study track under R 460.952, or to withdraw the application. The applicant shall have 20  
business days to decide on a course of action and notify the electric utility. In the  
absence of this notification, the electric utility may withdraw the application within the  
required time period.  
(6) When an applicant changes from a non-exporting system to an exporting system, the  
applicant shall submit a new interconnection application.  
R 460.944 Fast track applicability.  
Rule 44. (1) Level 1, level 2, level 3, and level 4 applications and level 5 applications  
as large as 5 MWac in which the DER is not proposing to interconnect with the electric  
utility’s high voltage distribution system are eligible for the fast track. Applications that  
provide for the use of an energy storage device so the export of power meets the  
requirements of level 1, level 2, level 3, level 4 or level 5 as large as 5 MWac in which  
Commented [A5]: Consumers Energy is concerned about  
the expansion of fast track eligibility above 1 MW. While  
this feels like an expansion of customer eligibility, the  
Company’s experience has indicated it to be highly unlikely  
for a 5 MW project to pass fast track screens for a  
Consumers Energy interconnection. This would result in  
customer frustration as well as wasted time and effort on the  
part of both parties before eventually placing the project in  
the appropriate study track.  
Attachment A  
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the applicant is not proposing to interconnect the DER with the electric utility’s high  
voltage distribution system are also eligible for the fast track.  
(2) An applicant that is eligible for the fast track may forgo the fast track and proceed  
directly to the study track.  
(3) An applicant with an application that is outside the limitations specified in subrule  
(1) of this rule may petition the electric utility to have its application evaluated under fast  
track. The electric utility may approve or reject this request at its discretion.  
(4) In determining fast track eligibility, an electric utility may aggregate all proposed  
new generation on a site regardless of the existence of a shared point of common  
coupling or multiple points of common coupling.  
R 460.946 Fast track; initial review.  
Rule 46. (1) An electric utility shall list in its interconnection procedures the initial  
review screens specified in subrule (4) of this rule. An electric utility may add additional  
details to each of these screens in the interconnection procedures.  
(x) An electric utility may include additional initial review screens in its  
interconnection procedures. In its application requesting approval of interconnection  
procedures, an electric utility shall provide a detailed technical rationale for including  
each additional screen. If an additional screen conflicts with or undermines any of the  
initial review screens specified in subrule (4) of this rule, the rationale must include an  
explanation of how it does so.  
Commented [A6]: The Company recommends this  
previously deleted language that allows utilities to include  
additional screens in its interconnection procedures be  
reinstated.  
(2) The electric utility may waive application of 1, some, or all of the initial review  
screens.  
(3) Within 10 business days after an electric utility receives a complete and conforming  
level 1 or level 2 application and associated payment, or within 20 business days after an  
electric utility receives a complete and conforming level 3, level 4, or level 5 application  
and associated payment, the electric utility shall perform an initial review and notify the  
applicant of the results. The initial review must consist of applying the initial review  
screens selected by the electric utility pursuant to subrule (2) of this rule to the proposed  
DER. The electric utility shall not require a supplemental review or a system impact  
study if the DER passes the applied initial review screens.  
(4) The initial review screens are all of the following:  
Commented [A7]:  
(a) The entire proposed DER, including all aggregated site generation and point or  
points of interconnection, must be located within the electric utility’s service territory.  
(b) For interconnection of a proposed DER to a radial distribution circuit, the  
aggregated generation, including the proposed DER, on the circuit may not exceed 15%  
of the line section annual peak load as most recently measured or calculated if measured  
data is not available. A line section is that portion of an electric utility’s distribution  
system connected to a customer bounded by automatic sectionalizing devices or the end  
of the distribution line. The electric utility shall consider 100% of applicable loading, if  
available, instead of 15% of line section peak load for level 1 and level 2 DER. In the  
event daytime loading data is not available, the data must be collected by January 2023  
for electric utilities with more than 1,000,000 customers in this state, or by a date  
specified in interconnection procedures approved by the commission for electric utilities  
The Company’s first preference is the removal of the  
language stricken in this paragraph.  
If the Commission elects not to strike this language,  
Consumers Energy is assuming the 15% reflect here is  
referencing the anti-islanding screen. The 15% threshold  
comes from calculating min load based on 45% of peak load  
multiplied by the 33% islanding ratio typically applied to  
synch generators (0.45x0.33=0.15). Based on this technical  
derivation, Consumers Energy believes this value should be  
33%.  
The Company requests that the Commission clarify if the  
value should be 33%, not 100%, based on the technical  
derivation of the 15% value?  
Attachment A  
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with fewer than 1,000,000 customers in this state, and shall not consider as part of the  
aggregate generation, for purposes of this screen, DER capacity known to be already  
reflected in the minimum load data. This screen does not apply to level 1 and level 2 non-  
export DER applications.  
(c) For interconnection of a proposed DER to the load side of network protectors, the  
proposed DER must utilize an inverter-based equipment package and, together with the  
aggregated other inverter-based DERs, may not exceed the smaller of 5% of a network’s  
maximum load or 50 kWac.  
Commented [A8]: The Company does not have remote  
access to daytime loadings at all of the substations and line  
reclosers, and it could be some time before that capability is  
realized at all devices. Where DSCADA is not available,  
Consumers Energy would have regulator peak reads and  
real-time reads while physically at the substation, but no  
ability to develop a load profile. Site visits would be required  
to obtain those regulator reads. The Company recommends  
this requirement be removed from the interconnection rules.  
(d) The proposed DER, in aggregation with other DERs on the distribution circuit, may  
not contribute more than 10% to the distribution circuit’s maximum fault current at the  
point on the primary voltage nearest the proposed point of common coupling. This  
screen does not apply to level 1 applications.  
Commented [A9]: Remote access to daytime loadings is  
not available on all line sections and may not be available for  
some time. The Company recommends that utilities should  
only be required to consider using applicable loading as the  
data becomes available as part of normal business practices.  
(e) The proposed DER, in aggregate with other DERs on the distribution circuit, may  
not cause any distribution protective devices and equipment or interconnection customer  
equipment on the system to exceed 87.5% of the short circuit interrupting capability. An  
interconnection may not be proposed for a circuit that already exceeds 87.5% of the short  
circuit interrupting capability. Distribution protective devices and equipment include, but  
are not limited to, substation breakers, fuse cutouts, and line reclosers. This screen does  
not apply to level 1 applications.  
(f) The initial review screen determines the type of interconnection to a primary  
distribution line for the proposed DER, according to the requirements specified in the  
table in this subdivision. This screen includes a review of the type of electrical service  
provided to the applicant, including line configuration and the transformer connection to  
limit the potential for creating over-voltages on the electric utility’s distribution system  
due to a loss of ground during the operating time of any anti-islanding function.  
Commented [A10]: The exclusion of Levels 1 and 2 non-  
export DER removes the ability for utilities to screen for  
safety and reliability issues. Level 1 and 2 non-export  
projects can increase the risk of anti-islanding of existing  
DER and therefore should not be excluded from the screen.  
The Company recommends Level 1 and 2 non-export DER’s  
be included in screens.  
Commented [A11]: Evaluating the risk of islanding using  
applicable loading (e.g. daytime for solar) and unmasking  
load is meant to be evaluated in the supplemental review R  
460.950 (5)(a) due to increased cost and time requirements.  
Commented [A12]: The exclusion of Level 1 removes the  
ability for utilities to screen for safety and reliability issues.  
The Company recommends this language be removed from  
460.946 (4)(d).  
Primary Distribution Line  
Type  
Type of Interconnection to  
Primary Distribution Line  
3-phase or single phase,  
phase-to-phase  
Effectively-grounded 3- phase  
or single-phase, line-to-neutral  
Result  
Commented [A13]: The exclusion of Level 1 removes the  
ability for utilities to screen for safety and reliability issues.  
The Company recommends this language be removed from  
460.946 (4)(e).  
3-phase, 3 wire  
Pass screen  
Pass screen  
3-phase, 4 wire  
(g) If the proposed DER is to be interconnected on single-phase shared secondary, the  
aggregate generation capacity on the shared secondary, including the proposed DER  
export capacity, may not exceed 20 kWac or 65% of the transformer nameplate rating.  
(h) If the proposed DER is single-phase and is to be interconnected on a center tap  
neutral of a 240 volt service, its addition may not create an imbalance between the 2 sides  
of the 240 volt service of more than 20% of the nameplate rating of the service  
transformer.  
(i) If the proposed DER is single-phase and is to be interconnected to a 3-phase service,  
its nameplate rating may not exceed 10% of the service transformer nameplate rating.  
(j) If the proposed DER’s point of common coupling is behind a line voltage regulator,  
the DER’s nameplate rating must be less than 250 kWac. This screen does not include  
substation voltage regulators.  
Attachment A  
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(5) If the proposed interconnection passes the initial review screens, or if the proposed  
interconnection fails the screens but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant. If a facilities study is not required, the interconnection  
application must proceed under R 460.964 to an interconnection agreement. If a facilities  
study is required, the interconnection application must proceed under R 460.962.  
(6) If the proposed interconnection fails any of the initial review screens, and the electric  
utility does not or cannot determine that the DER may be interconnected consistent with  
safety, reliability, and power quality standards, the electric utility shall notify the  
applicant, provide the applicant with the results of the application of the initial review  
screens, and offer all of the following options:  
(a) Attend a customer options meeting, as described in R 460.948.  
(b) Proceed to supplemental review under R 460.950.  
(c) Submit within 60 business days from the date of the electric utility notification, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility. The application modifications must mitigate or eliminate the factors  
that caused the interconnection application to fail 1 or more of the initial review screens.  
After each submission of information, the electric utility has 10 business days to notify  
the applicant that the interconnection application is either accepted or rejected due to  
continuing deficiencies. If the applicant does not meet the timelines required by this  
subrule, the electric utility may withdraw the application. After the electric utility  
determines the application is accepted, the revised interconnection application must  
proceed under subrule (3) of this rule.  
(d) Withdraw the interconnection application.  
(7) If the applicant does not select a course of action under subrule (6) of this rule within  
10 business days of notice from the electric utility, the electric utility shall withdraw the  
interconnection application.  
R 460.948 Fast track; customer options meeting.  
Rule 48. (1) Upon an applicant’s request, the electric utility and the applicant shall  
schedule a customer options meeting between the electric utility and the applicant to  
review possible facility modifications, screen analysis, and related results to determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The customer options meeting must take place within 30 business  
days of the date of notification pursuant to R 460.946(6).  
(2) At the customer options meeting, the electric utility shall offer all of the following  
options:  
(a) Proceed to a supplemental review pursuant to R 460.950.  
(b) Continue evaluating the interconnection application under the study track pursuant  
to R 460.952.  
(c) Submit within 60 business days from the date of the customer options meeting, with  
up to 2 submissions during this time period, a complete and conforming revised  
interconnection application that includes application modifications offered or required by  
the electric utility, which mitigates or eliminates the factors that caused the  
Attachment A  
Page 23 of 50  
23  
interconnection application to fail 1 or more of the initial review screens. After each  
submission of information, the electric utility has 10 business days to notify the applicant  
that the interconnection application is either accepted or rejected due to continuing  
deficiencies. If the applicant does not meet the timelines required by this subrule, the  
electric utility may withdraw the application. After the electric utility accepts the revised  
interconnection application, it must proceed under R 460.946(3).  
(d) Withdraw the interconnection application.  
(3) Following the customer options meeting, the applicant has up to 20 business days to  
decide on a course of action and notify the electric utility. In the absence of this  
notification within the required time, the electric utility shall withdraw the application.  
(4) The customer options meeting may take place in person or via telecommunications.  
R 460.950 Fast track; supplemental review.  
Rule 50. (1) An electric utility shall list in its interconnection procedures the  
supplemental review screens specified in subrule (5) of this rule. An electric utility may  
add additional details to each of these screens in the interconnection procedures.  
(x) An electric utility may include additional supplemental review screens in its  
interconnection procedures. In its application requesting approval of interconnection  
procedures, the electric utility shall provide a detailed technical rationale for the inclusion  
of each supplemental review screen. If an additional screen negates or undermines any of  
the supplemental review screens specified in subrule (5) of this rule, the rationale must  
include an explanation of the technical justification for the additional screen.  
(2) An electric utility may waive application of 1, some, or all of the supplemental  
review screens.  
Commented [A14]: The Company recommends this  
previously deleted language that allows utilities to include  
additional screens in its interconnection procedures be  
reinstated.  
(3) To receive a supplemental review, an applicant shall submit payment of the  
supplemental review fee within 20 business days of agreeing to a supplemental review. If  
payment of the fee has not been received by the electric utility within 25 business days,  
the electric utility shall withdraw the interconnection application.  
(4) Within 30 business days after the applicant pays the applicable supplemental review  
fee or fees, an electric utility shall perform a supplemental review and notify the applicant  
of the results. The supplemental review must consist of applying the initial review  
screens selected by the electric utility pursuant to subrule (2) of this rule to the proposed  
DER. The electric utility shall not require a system impact study if the DER passes the  
applied supplemental review screens.  
(5) The supplemental review screens must include all of the following:  
(a) Minimum load screen. Where 12 months of line section minimum load data,  
including onsite load but not station service load served by the proposed DER, are  
available, can be calculated, can be estimated from existing data, or can be determined  
from a power flow model, the aggregate DER capacity on the line section must be less  
than 100% of the minimum load for all line sections bounded by automatic sectionalizing  
devices upstream of the proposed DER. If minimum load data are not available, or cannot  
be calculated, estimated, or determined, an electric utility shall include the reason or  
reasons that it is unable to calculate, estimate, or determine minimum load in its  
supplemental review results notification under subrules (6) and (7) of this rule. All of the  
following must be applied by the electric utility:  
Attachment A  
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24  
(i) The type of generation used by the proposed DER will be considered when  
calculating, estimating, or determining circuit or line section minimum load relevant for  
the application of the minimum load screen specified in subrule (5)(a) of this rule. Solar  
photovoltaic generation systems with no battery storage must use daytime minimum load.  
All other generation must use absolute minimum load unless an operating schedule is  
provided.  
(ii) When this screen is being applied to a DER that serves some station service load,  
only the net injection of electric energy into the electric utility’s distribution system may  
be considered as part of the aggregate generation.  
(iii) The electric utility shall not consider as part of the aggregate generation, for  
purposes of this supplemental screen, DER capacity known to be already reflected in the  
minimum load data.  
(b) Voltage and power quality screen. In aggregate with existing generation on the line  
section, all of the following conditions must be met:  
(i) The voltage regulation on the line section can be maintained in compliance with  
relevant requirements under all system conditions.  
(ii) The voltage fluctuation is within acceptable limits as defined by the IEEE Standard  
1453-2015, IEEE Recommended Practice for the Analysis of Fluctuating Installations on  
Power Systems.  
(c) Safety and reliability screen. The location of the proposed DER and the aggregate  
generation capacity on the line section may not create impacts to safety or reliability that  
require application of the study track to address. An electric utility shall consider all of  
the following when determining potential impacts to safety and reliability in applying this  
screen:  
(i) Whether the line section has significant minimum loading levels dominated by a  
small number of customers, such as several large commercial customers.  
(ii) Whether the loading along the line section is uniform.  
(iii) Whether the proposed DER is located less than 0.5 electrical circuit miles for less  
than 5 kV or less than 2.5 electrical circuit miles for greater than 5 kV from the  
substation. In addition, whether the line section from the substation to the point of  
common coupling is a mainline rated for normal and emergency ampacity.  
(iv) Whether the proposed DER incorporates a time delay function to prevent  
reconnection of the DER to the distribution system until distribution system voltage and  
frequency are within normal limits for a prescribed time.  
(v) Whether operational flexibility is reduced by the proposed DER, such that transfer  
of the line section or sections of the DER to a neighboring distribution circuit or  
substation may trigger overloads, power quality issues, or voltage issues.  
(vi) Whether the proposed DER employs equipment or systems certified by a  
recognized standards organization to address technical issues including, but not limited  
to, islanding, reverse power flow, or voltage quality.  
(6) If the proposed interconnection passes the supplemental review, or if the proposed  
interconnection fails the review but the electric utility determines that the DER may be  
interconnected consistent with safety, reliability, and power quality standards, the electric  
utility shall notify the applicant and the interconnection application must proceed  
pursuant to both of the following:  
Attachment A  
Page 25 of 50  
25  
(a) If the proposed interconnection requires a facilities study, the interconnection  
application must proceed under R 460.962.  
(b) If the proposed interconnection does not require further study, the interconnection  
application must proceed under R 460.964 to an interconnection agreement.  
(7) If the proposed interconnection fails any of the supplemental review screens or the  
electrical utility is unable to perform a supplemental review screen, and the electric utility  
does not or cannot determine that the DER may be interconnected consistent with safety,  
reliability, and power quality standards, the electric utility shall notify the applicant,  
provide the applicant with the results of the application of the supplemental review  
screens, and offer both of the following options:  
(a) Stop the supplemental review and continue evaluating the proposed interconnection  
under the study track under R 460.952.  
(b) Withdraw the interconnection application.  
(8) For subrules (6) and (7) of this rule, if an applicant does not select a course of action  
within 10 business days of notice from the electric utility, the electric utility shall  
withdraw the interconnection application.  
R 460.952 Study track.  
Rule 52. (1) An electric utility shall use the study track to evaluate an interconnection  
application that has been accepted under R 460.936 if 1 or more of the following  
conditions is met:  
(a) The DER is not eligible for the non-export track or fast track.  
(b) The DER did not pass the initial review screens as part of the fast track and the  
applicant selected the study track option in the customer options meeting.  
(c) The DER did not pass 1 or more supplemental review screens.  
(d) The DER was evaluated under the non-export track and further study is required.  
(e) The DER is eligible for the fast track, but the applicant elected the study track.  
(2) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(a) of this rule, within 10 business days after the electric  
utility notifies the applicant that the interconnection application has been accepted  
pursuant to R 460.936, the electric utility shall provide to the applicant an individual  
study agreement or an agreement for an alternative process pursuant to R 460.956.  
(3) If the interconnection application must be evaluated under the study track because it  
meets the criteria of subrule (1)(b), (c), or (d), of this rule, within 10 business days after  
the applicant has notified the electric utility to proceed to the study track, the electric  
utility shall provide to the applicant an individual study agreement or an agreement for an  
alternative process.  
(4) An electric utility’s interconnection procedures may include a provision for  
determining appropriate milestone payments to include with the system impact study fee  
and facilities study fee.  
R 460.954 Individual study.  
Attachment A  
Page 26 of 50  
26  
Rule 54. (1) An electric utility that is evaluating DERs in the study track individually  
shall process the interconnection applications in the order in which the applications were  
placed into the study track, taking into account withdrawn interconnection applications  
and electrically remote DERs.  
(a) An electrically remote DER in an individual study may be studied on an expedited  
schedule relative to electrically coincident DERs. Electrically remote DERs must be  
studied in the order the interconnection applications were considered complete.  
(2) When an interconnection application is delayed due to an affected system issue,  
informal mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or a  
complaint pursuant to R 792.10439 to R 792.10446, other interconnection applications  
that were placed into the study track on a later date may progress in the order in which  
the interconnection applications were placed into the study track.  
(3) An individual study process must consist of a system impact study pursuant to R  
460.960 and a facilities study pursuant to R 460.962. An electric utility may waive 1 or  
both studies for a particular interconnection application. An electric utility may specify  
additional studies it may perform on an interconnection application in its interconnection  
procedures, provided the electric utility is able to meet all applicable timelines associated  
with an individual study process.  
(4) Interconnection applications that meet all of the following requirements must be  
admitted into an individual study:  
(a) An electric utility determined the application to be complete and conforming.  
(b) An application qualifies for study track pursuant to R 460.952.  
(c) An interconnection application has a pre-application report, when required by R  
460.936(2).  
(d) An applicant has paid all required fees.  
(e) An applicant has signed and returned an individual study agreement.  
R 460.956 Alternative process.  
Rule 56. An electric utility may use a process to study interconnection applications that  
is different from the process described by R 460.954 and R 460.958 to R 460.962. If an  
electric utility elects to use an alternative process, this process must be described in the  
electric utility’s interconnection procedures.  
R 460.958 Scoping meeting for interconnection applications that are to be studied  
individually.  
Rule 58. (1) This rule applies only to interconnection applications proceeding pursuant  
an individual study agreement.  
(2) Upon request of the applicant, the electric utility and the applicant shall schedule a  
scoping meeting between the electric utility and the applicant to discuss the  
interconnection application and review existing fast track results, if any. The scoping  
meeting must take place within 20 business days after the interconnection application is  
considered complete by the electric utility or, if applicable, the fast track has been  
completed and the applicant has elected to continue with the system impact study or  
facilities study.  
Attachment A  
Page 27 of 50  
27  
(3) Scoping meetings are limited to 1 hour per application. Multiple applications by the  
same applicant may be addressed in the same meeting.  
(4) The scoping meeting may occur in-person or via telecommunications.  
(5) During the scoping meeting, the electric utility shall identify and communicate to the  
applicant whether the applicant must proceed to a system impact study, a facilities study,  
or an interconnection agreement and the basis for that decision, and 1 of the following  
must occur:  
(a) If a system impact study must be performed, the interconnection application  
proceeds to R 460.960.  
(b) If a facilities study must be performed, the interconnection application proceeds to  
R 460.962.  
(c) If a system impact study is not required and a facilities study is not required, the  
interconnection application must proceed to R 460.964 for an interconnection agreement.  
R 460.960 System impact study agreement, scope, procedure, and review meeting.  
Rule 60. (1) For all DERs being studied individually, all of the following apply:  
(a) An electric utility shall provide the applicant a system impact study agreement  
within 5 business days of proceeding to this rule.  
(b) A system impact study agreement must include all of the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee including appropriate credit for any studies previously  
completed pursuant to the fast track or non-export track.  
(iii) If necessary, a list of any additional and reasonable technical data needed from the  
applicant to perform the system impact study.  
(iv) A timeline for completion of the system impact study.  
(v) A list of the information that must be provided to the applicant in the system impact  
study report.  
(c) An applicant who has requested a system impact study shall return the completed  
system impact study agreement, provide any additional technical data requested by the  
electric utility, and pay the required fee within 20 business days. An electric utility may  
consider the application withdrawn if the system impact study agreement, payment, and  
required technical data are not returned within 20 business days.  
(d) A system impact study must identify and describe the electric system impacts that  
would result if the proposed DER was interconnected without electric system  
modifications. A system impact study must provide a non-binding good faith list of  
facilities that are required as a result of the application and non-binding estimates of costs  
and time to construct these facilities.  
(e) An electric utility shall explain in its interconnection procedures the process for  
conducting system impact studies on DERs when there is an affected system issue.  
(f) The electric utility shall complete the system impact study and transmit a system  
impact study report to the applicant within 60 business days of the receipt of the signed  
system impact study agreement, payment of the system impact study fee, and any necessary  
technical data. If necessary, the electric utility shall transmit a facilities study agreement to  
the applicant within 60 business days of receipt of the signed system impact study  
agreement, payment of all applicable fees, and any necessary technical data.  
Attachment A  
Page 28 of 50  
28  
(g) An electric utility may request reasonable additional data from the applicant within  
20 business days of beginning the system impact study. The electric utility and the  
applicant shall work together to resolve the additional data request so that the electric  
utility will be able to complete the system impact study within 60 business days as  
specified in subrule (1)(f) of this rule.  
(h) Within 15 business days of receiving the system impact study report, the applicant  
shall notify the electric utility that it plans to pursue a system impact study review  
meeting, proceed to a facilities study pursuant to R 460.962, or withdraw the application.  
If the applicant fails to notify the electric utility within 15 business days, the electric  
utility may consider the application to be withdrawn.  
(i) Upon request by the applicant pursuant to subrule (1)(h) of this rule, the electric  
utility and the applicant shall schedule a system impact study review meeting between the  
electric utility and the applicant to review system impact study results and determine  
what further steps are needed to permit the DER to be connected safely and reliably to the  
distribution system. The system impact study review meeting must take place within 25  
business days of the electric utility receiving notification that the applicant plans to attend  
a system impact study review meeting.  
(j) At the system impact study review meeting, the electric utility shall offer the  
applicant the option to withdraw the interconnection application, and 1 of the following  
options:  
(i) Proceed to a facilities study pursuant to R 460.962.  
(ii) Proceed directly to R 460.964 for an interconnection agreement.  
(k) Following the meeting, the applicant has not more than 45 business days to decide  
on a course of action. If an applicant fails to notify the electric utility within 45 business  
days, the electric utility may consider the application to be withdrawn.  
(l) The system impact study review meeting may occur in-person or via  
telecommunications.  
R 460.962 Facilities study agreement, scope, procedure; review meeting.  
Rule 62. (1) For DERs being studied individually, all of the following apply:  
(a) If construction of facilities is required to provide interconnection and  
interoperability of the DER with the electric utility’s distribution system, the electric  
utility shall provide the applicant a facilities study agreement and the results of the  
applicant’s system impact study pursuant to R 460.960, if applicable. If no system impact  
study was performed, the electric utility shall provide a facilities study agreement within  
10 business days of proceeding to this rule.  
(b) The facilities study agreement must include the following:  
(i) An outline of the scope of the study.  
(ii) The applicable fee including appropriate credit for any studies previously  
completed pursuant to the fast track or non-export track.  
(iii) A timeline for completion of the facilities study.  
(iv) A list of the information that will be provided to the applicant in the facilities study  
report.  
(c) The applicant shall return the signed facilities study agreement and pay the required  
facilities study fee within 20 business days. The electric utility may withdraw the  
Attachment A  
Page 29 of 50  
29  
application if the facilities study agreement and payment are not returned within 20  
business days.  
(d) A facilities study must specify and estimate the cost of the required equipment,  
engineering, procurement, and construction work, including overheads, needed to  
interconnect the DER, and an estimated timeline for the completion of construction. The  
electric utility shall provide cost estimates that are detailed and itemized.  
(e) The electric utility shall explain in its interconnection procedures the process for  
conducting facilities studies on DERs while there is an affected system issue.  
(f) The electric utility shall complete the facilities study and transmit a facilities study  
report to the applicant within 80 business days of the receipt of the signed facilities study  
agreement and payment of the facilities study fee.  
(g) Within 10 business days of receiving a facilities study report from the electric  
utility, the applicant shall select 1 option from the following options:  
(i) Request a facilities study review meeting with the electric utility.  
(ii) Proceed to an interconnection agreement pursuant to R 460.964.  
(iii) Withdraw the interconnection application.  
If the applicant fails to inform the electric utility within 10 business days of its chosen  
course of action, the electric utility may consider the application withdrawn.  
(h) Upon request by the applicant pursuant to subrule (1)(g)(i) of this rule, the electric  
utility and the applicant shall schedule a facilities study review to review the facilities  
study results and determine what further steps are needed to permit the DER to be  
connected safely and reliably to the distribution system. The facilities study review  
meeting must take place within 25 business days of the electric utility receiving  
notification that the applicant will attend a facilities study review meeting.  
(i) At the facilities study review meeting, the electric utility shall offer both of the  
following options:  
(i) Proceed to an interconnection agreement pursuant to R 460.964.  
(ii) Withdraw the interconnection application.  
(j) Following the meeting, the applicant has no more than 20 business days to decide on  
a course of action and notify the electric utility of this course of action. If the applicant  
fails to notify the electric utility within 20 business days, the electric utility may withdraw  
the application.  
(k) The facilities study review meeting may be conducted in-person or via  
telecommunications.  
R 460.964 Interconnection agreement.  
Rule 64. (1) For level 1, 2, or 3 interconnection applications, where no construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
provide its standard level 1, 2, and 3 interconnection agreement, which may include  
modifications to address any special operating conditions, to an applicant within 3  
business days of reaching this stage.  
(2) For level 1, 2, or 3 interconnection applications, where construction of  
interconnection facilities or distribution upgrades is required, an electric utility shall  
provide its standard level 1, 2, and 3 interconnection agreement with modifications to  
address any special operating conditions, required construction activities, construction  
Attachment A  
Page 30 of 50  
30  
milestone timing, and cost to an applicant within 5 business days of reaching this stage.  
The applicant and electric utility shall mutually agree on the timing of construction  
milestones.  
(3) For an applicant with level 1, 2, or 3 interconnection applications, the applicant shall  
sign and return the standard level 1, 2, and 3 interconnection agreement with payment, if  
applicable, within 20 business days of receiving the agreement.  
(a) If the applicant did not sign and return the standard level 1, 2, and 3 interconnection  
agreement and payment, if applicable, within 20 business days, the electric utility shall  
notify the applicant of the missed deadline and grant an extension of 15 business days. If  
the electric utility did not receive the signed standard level 1, 2, and 3 interconnection  
agreement and any applicable payment during the 15-business-day extension, the electric  
utility may consider the interconnection application withdrawn subject to subrule 3(b) of  
this rule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, the  
formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446 within the 20 business days, the outcome of that process must  
establish a time frame for the applicant to return the signed interconnection agreement  
and any applicable payment.  
(4) For level 1, 2, or 3 projects, the electric utility shall countersign and provide a  
completed copy of the standard level 1, 2, and 3 interconnection agreement within 10  
business days of the applicant returning the signed standard level 1, 2, and 3  
interconnection agreement and the interconnection application shall proceed to R  
460.966.  
(5) For level 4 or 5 projects, the electric utility shall provide its level 4 and 5  
interconnection agreement, which may include modifications to address any special  
operating conditions, within 10 business days of reaching this stage. When construction  
of interconnection facilities or distribution upgrades is necessary, the level 4 and 5  
interconnection agreement must contain either timelines for completion of activities and  
estimates of construction costs or a timetable when these requirements can be  
determined. The interconnection agreement must include a payment schedule that  
corresponds to the milestones established and must require the electric utility to refund  
any unspent and unobligated funds if the agreement is terminated.  
(6) For an applicant with level 4 or 5 DERs, the applicant shall sign and return with  
payment, if applicable, a level 4 and 5 interconnection agreement within 30 business  
days.  
(a) If the applicant does not sign and return the level 4 and 5 interconnection agreement  
with payment within 30 business days, an electric utility shall notify the applicant of the  
missed deadline and grant an extension of 15 business days. If the electric utility does not  
receive the signed level 4 and 5 interconnection agreement and payment, if applicable,  
during the 15-business-day extension, the electric utility may consider the interconnection  
application withdrawn, subject to subrule (6)(b) of this rule.  
(b) If the applicant begins either the informal mediation pursuant to R 460.904, formal  
mediation pursuant to R 460.906, or the complaint process pursuant to R 792.10439 to R  
792.10446 within 30 business days, the outcome of that process must establish a time  
frame for the applicant to return the signed interconnection agreement and applicable  
payment. There is a rebuttable presumption in the complaint proceeding that the electric  
Attachment A  
Page 31 of 50  
31  
utility’s standard construction, procurement, installation, design, and cost practices are  
lawful, reasonable, and prudent.  
(i) For study track interconnection applications filed with an electric utility conducting  
individual studies, electrically coincident applications filed after the interconnection  
application must be placed on hold for not more than 60 business days. If either informal  
mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or the  
complaint process pursuant to R 792.10439 to R 792.10446 does not result in the  
applicant returning a signed interconnection agreement with any applicable payment  
within 60 business days and there are electrically coincident interconnection applications  
in progress behind this application, the electric utility may require the withdrawal of the  
interconnection application.  
(7) For level 4 or 5 projects, an electric utility shall countersign and provide a completed  
copy of the level 4 and 5 interconnection agreement within 10 business days of the  
applicant returning a mutually agreed-upon and signed level 4 and 5 interconnection  
agreement and the interconnection application shall proceed to R 460.966.  
(8) An applicant shall pay the actual cost of the interconnection facilities and  
distribution upgrades. The cost to the applicant for interconnection facilities and  
distribution upgrades may not exceed 110% of the estimate without an itemized summary  
and explanation of cost increases being provided to the applicant.If the costs are expected  
to exceed 125% of the estimate, the electric utility shall provide further explanation to the  
applicant prior to the costs being incurred. If the applicant does not consent in writing to  
pay the additional costs within 20 business days of receiving further explanation from the  
electric utility, the electric utility shall initiate informal mediation pursuant to R 460.904  
no later than 5 business days after the conclusion of the 20 business day applicant consent  
period. The applicant may dispute the expected costs pursuant to either informal  
mediation pursuant to R 460.904, formal mediation pursuant to R 460.906, or the  
complaint process pursuant to R 792.10439 to R 792.10446. If there is a dispute, the  
applicant shall make payment within 30 business days of final resolution of the dispute.  
(9) A party’s obligations under the interconnection agreement may be extended by  
agreement. If a party anticipates that it will be unable to meet a milestone for any reason  
other than an unforeseen event, the party shall do all of the following:  
(a) Immediately notify the other party of the reason or reasons for not meeting the  
milestone.  
(b) Propose the earliest alternate date when it can attain this and future milestones.  
(c) Request amendments to the interconnection agreement, if needed to address the  
changed milestones.  
(10) The party affected by the failure to meet a milestone shall not withhold agreement  
to any amendments proposed in subrule (9)(c) of this rule unless 1 of the following  
applies:  
(a) The party affected will suffer significant uncompensated economic or operational  
harm from the amendment or amendments.  
(b) The milestone under question has been previously delayed. (c) The affected party  
has reason to believe that the delay in meeting the milestone is intentional or unwarranted  
notwithstanding the circumstances explained by the party proposing the amendment.  
(11) If the party affected by the failure to meet a milestone disputes the proposed  
extension, the affected party may pursue either informal mediation pursuant to R  
Attachment A  
Page 32 of 50  
32  
460.904, formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446.  
(12) The electric utility shall provide the applicant with a final accounting report of any  
difference between costs charged to the applicant and previous payments to the electric  
utility for interconnection facilities or distribution upgrades.  
(a) If the costs charged to the applicant exceed its previous aggregate payments, the  
electric utility shall bill the applicant for the amount due and the applicant shall make a  
payment to the electric utility within 20 business days of the final accounting report. The  
applicant may dispute the invoice pursuant to either informal mediation pursuant to R  
460.904, formal mediation pursuant to R 460.906, or the complaint process pursuant to R  
792.10439 to R 792.10446. If there is a dispute, the applicant shall make payment within  
30 business days of final resolution of the dispute. Failure by the applicant to pay its costs  
is cause for disconnection of the applicant’s DER.  
(b) If the applicant’s previous aggregate payments exceed its costs under the  
interconnection agreement, the electric utility shall refund to the applicant an amount  
equal to the difference within 20 business days of the final accounting report.  
(13) The electric utility is responsible for specifying requirements in interconnection  
agreements to support independent system operator regulations or regional transmission  
operator regulations.  
(14) The electric utility may propose to the commission that a signed interconnection  
agreement be modified to require compliance with changes to an independent system  
operator, a regional transmission operator, or the state’s regulations, provided that these  
modifications do not alter the rights or obligations of the interconnection customer. Unless  
the electric utility has the consent of the applicant or interconnection customer in writing,  
an electric utility shall not modify a signed interconnection agreement without commission  
approval.  
R 460.966 Inspection, testing, and commissioning.  
Rule 66. (1) If the interconnection application requires telecommunications, cybersecurity,  
data exchange or remote controls operation, successful testing and certification of these  
items must be completed prior to or during testing. The electric utility’s interconnection  
procedures must describe the technical requirements of common items, but site-specific  
requirements may be included in the interconnection agreement.  
(2) An applicant shall notify the electric utility when installation of a DER and any  
required local code inspection and approval is complete. The applicant shall provide any  
test reports or configuration documents as defined in the standard level 1, 2, and 3  
interconnection agreement or level 4 and 5 interconnection agreement.  
(3) The electric utility shall review the applicant’s inspection, test reports, or configuration  
documents, and communicate its intent to perform a witness or commissioning test, or  
waive its right to perform a witness test and commissioning test within 10 business days.  
If the electric utility finds the applicant’s inspection, test reports, or configuration  
documents to be incomplete, insufficient, or unsatisfactory, the electric utility shall provide  
its reasons for doing so in writing and the applicant shall have at least 20 business days to  
implement corrections to those documents. The applicant, after taking corrective action,  
Attachment A  
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shall request the electric utility to reconsider its inspection, test reports, or configuration  
documents.  
(4) If the electric utility intends to witness or perform commissioning tests required to  
comply with the interconnection agreement or the interconnection procedures and inspect  
the DER, the electric utility shall witness or perform the commissioning tests and inspect  
the DER within the following:  
(a) Ten business days of receiving the notification from the applicant pursuant to subrule  
(2) of this rule for level 1 applications.  
(b) Twenty business days of receiving the notification from the applicant pursuant to  
subrule (2) of this rule for level 2 and level 3 applications.  
(c) A mutually-agreed upon timeframe after receiving the notification from the  
applicant pursuant to subrule (2) of this rule for level 4 and 5 applications.  
(5) The electric utility may waive its right to visit the site and inspect the DER or  
perform the commissioning tests.  
(a) If the electric utility waives this right, it shall provide a written waiver to the  
applicant within 10 business days from receiving the notification from the applicant  
pursuant to subrule (2) of this rule.  
(b) The applicant shall provide the electric utility with the completed commissioning  
test report within 20 business days of receipt of the electric utility’s written waiver.  
(6) If the electric utility attempts to conduct the inspection and testing pursuant to  
subrule (4) of this rule at the arranged time and is unable to access the DER or complete  
the testing, the DER must remain disconnected until the applicant and the electric utility  
can complete the inspection and testing.  
(7) If the electric utility witnessed or performed commissioning tests and inspected the  
DER pursuant to subrule (4) of this rule, within 5 business days of the receipt of the  
completed commissioning test report, the electric utility shall notify the applicant whether  
it has accepted or rejected the commissioning test report and found the site to be  
satisfactory or unsatisfactory.  
(a) If the commissioning test report is accepted and the site was found satisfactory, the  
electric utility shall provide the notification of acceptance in writing, and the  
interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report or did not find the site  
satisfactory, the electric utility shall provide its reasons for doing so in writing and the  
applicant has not less than 20 business days to implement corrections. The applicant, after  
taking corrective action, shall request the electric utility to reconsider its findings. The  
applicant may be billed the actual cost of any re-inspections.  
(8) If the electric utility waived its right to witness or perform commissioning tests and  
inspect the DER pursuant to subrule (5) of this rule, within 5 business days of the receipt  
of the completed commissioning test report, the electric utility shall notify the applicant  
whether it has accepted or rejected the commissioning test report.  
(a) If the commissioning test report is accepted, the electric utility shall provide  
notification of acceptance, and the interconnection application proceeds to R 460.968.  
(b) If the electric utility rejects the commissioning test report, the electric utility shall  
provide its reasons for doing so in writing and the applicant has not less than 20 business  
days to implement corrections. The applicant, after taking corrective action, may then  
request the electric utility to reconsider its findings.  
Attachment A  
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34  
(9) The cost of testing and inspection for applicants participating in an electric utility’s  
distributed generation program, as described in part 3 of these rules, R 460.1001 to R  
460.1026, are considered a cost of operating a distributed generation program and must  
be recovered pursuant to section 175(1) of the clean and renewable energy and energy  
waste reduction act, 2008 PA 295, MCL 460.1175.  
(10) If the applicant does not notify the electric utility that the DER is installed and  
ready to test pursuant to subrule (2) of this rule, the electric utility may, in writing, query  
the status of the interconnection. If the applicant does not provide a written response  
within 10 business days or no progress is evident, the electric utility may consider the  
interconnection application withdrawn.  
R 460.968 Authorization required prior to parallel operation.  
Rule 68. (1) The electric utility shall provide to the applicant written authorization to  
operate in parallel with the electric utility within 5 business days of all of the following  
conditions being met:  
(a) The electric utility notified the interconnection applicant that the commissioning test  
and inspection, where applicable, are accepted.  
(b) The applicant complied with all applicable parallel operation requirements as set  
forth in the electric utility’s interconnection procedures and applicable interconnection  
agreement.  
(c) The applicant complied with all applicable local, state, and federal requirements.  
(d) The electric utility received full payments for all outstanding bills.  
(2) With the written authorization, interconnection of the DER is considered approved  
for parallel operation, the DER may begin operating, and the applicant is considered an  
interconnection customer.  
(3) The applicant shall not operate its DER in parallel with the electric utility’s  
distribution system without prior written permission to operate from the electric utility.  
(4) Subject to reasonable timing and other conditions, including completion of  
conditions in the interconnection agreement or interconnection procedures, the electric  
utility shall allow for reasonable but limited testing before written authorization has  
occurred.  
R 460.970 Cost allocation of interconnection facilities, distribution upgrades, and  
associated operation and maintenance costs.  
Rule 70. Costs for interconnection facilities, distribution upgrades, and associated  
operation and maintenance costs must be classified into 1 of the following categories:  
(a) Site-specific costs, which include, but are not limited to, costs of interconnection  
facilities and distribution upgrades that are caused by 1 DER, whether that DER is  
electrically co-incident with other DERs or not. These costs must be assigned to the cost-  
causing applicant.  
(b) Shared interconnection facilities costs, which are costs caused by DERs which  
together necessitate the construction of interconnection facilities. The interconnection  
facilities costs, including any associated operation and maintenance costs, that should be  
Attachment A  
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35  
shared must be allocated to each applicant based on a methodology described in the  
electric utility’s interconnection procedures.  
(c) Shared distribution upgrade costs, which are costs caused by electrically co-incident  
DERs that together necessitate a distribution upgrade. The distribution upgrade costs,  
including any associated operation and maintenance costs, that should be shared must be  
allocated to each applicant based on a methodology described in the electric utility’s  
interconnection procedures.  
R 460.974 Interconnection metering and communications.  
Rule 74. (1) Any metering and communications requirements necessitated by use of the  
DER must be installed at the applicant’s expense. The electric utility may furnish this  
equipment at the applicant’s expense.  
(2) The electric utility may charge the interconnection customer reasonable ongoing fees  
to maintain the metering and communications equipment. These fees must be listed in the  
interconnection agreement.  
R 460.976 Post commissioning remedy.  
Rule 76. (1) If the electric utility finds that the DER is operating outside the terms of the  
interconnection agreement but does not find immediate disconnection pursuant to R  
460.978(1)(f) and (g) warranted, the electric utility shall promptly inform the  
interconnection customer or its agent of this finding. The interconnection customer is  
responsible for bringing the DER into compliance within 30 business days or a mutually  
agreed-upon time period. The electric utility may perform an inspection of the DER after  
a remedy is applied.  
(2) If the DER is not brought into compliance within 30 business days or the mutually  
agreed-upon time period, the electric utility may apply a remedy and bill the  
interconnection customer. The interconnection customer shall pay this bill within 5  
business days.  
R 460.978 Disconnection.  
Rule 78. (1) An electric utility may refuse to connect or may disconnect a project from  
the distribution system if any of the following conditions apply:  
(a) Failure of the interconnection customer to bring a DER into compliance pursuant to  
R 460.976(1).  
(b) Failure of the interconnection customer to pay costs of remedy pursuant to R  
460.976(2).  
(c) Termination of interconnection by mutual agreement.  
(d) Distribution system emergency, but only for the time necessary to resolve the  
emergency.  
(e) Routine maintenance, repairs, and modifications performed in a reasonable time and  
with prior notice to the interconnection customer.  
Attachment A  
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36  
(f) Noncompliance with technical or contractual requirements in the interconnection  
agreement that could lead to degradation of distribution system reliability, electric utility  
equipment, and electric customers’ equipment.  
(g) Noncompliance with technical or contractual requirements in the interconnection  
agreement that presents a safety hazard.  
(h) Other material noncompliance with the interconnection agreement.  
(i) Operating in parallel without prior written authorization from the electric utility as  
provided for in R 460.968.  
(2) An electric utility may disconnect electric service, where applicable, pursuant to R  
460.136.  
R 460.980 Capacity of the DER.  
Commented [A15]: As reflected in CE’s comments, the  
Company’s preferred revision to this section is that all of  
Section R 460.980 be revised to mirror the R 460.980 section  
included in the September 9, 2021 order in Case No. U-  
20890 Exhibit B.  
Rule 80. (1) If the interconnection application requests an increase in capacity for an  
existing DER, the electric utility shall evaluate the application based on the new ongoing  
operating capacity nameplate capacity of the DER. The maximum capacity of a DER is  
the aggregate nameplate capacity or may be limited as described in the electric utility’s  
interconnection procedures.  
(2) An interconnection application for a DER that includes single or multiple types of  
DERs at a site for which the applicant seeks a single point of common coupling must be  
evaluated as described in the electric utility’s interconnection procedures.  
(3) The electric utility’s interconnection procedures must include acceptable methods  
for power limited export DER so that the DER capacity considered by the electric utility  
for reviewing the interconnection application is only the amount capable of being  
exported.  
Commented [A16]: The Company also recommends  
relocating subrule (1) and (2) to sections related to material  
modification and applications.  
(4) An electric utility shall allow interconnection of limited-export or non-exporting  
DERs according to this subrule. If a DER uses any configuration or operating mode in  
this subrule to limit the export of electrical power across the point of common coupling,  
then the generating capacity shall be only the amount capable of being exported not  
including any inadvertent export. To prevent impacts on system safety and reliability, any  
inadvertent export from a DER must comply with the limits in subdivisions (e) or (f) of  
this subrule. The generating capacity specified by the applicant in the application will  
subsequently be included as a limitation in the interconnection agreement. Other means  
not listed in this subrule may be utilized to limit export if mutually agreed upon by the  
electric utility and applicant.  
(a) To ensure stop power is from being never exported across the point of common  
coupling, a reverse power protective function may be provided. The default setting for  
this protective function shall be 0.1% export of the service transformer’s rating, with a  
maximum 2.0 second time delay.  
(b)To ensure stop power from being exported at least a minimum amount of power is  
imported across the point of common coupling at all times and, therefore, that power is  
not exported, an under-power protective function may be provided. The default setting  
for this protective function shall be 5% import of the DER’s total nameplate rating, with a  
maximum 2.0 second time delay.  
Commented [A17]: Reverse power (non-exporting)  
protective functions don’t ensure power is never exported.  
The protection is meant to detect and remove export above a  
set value.  
There are projects that use reverse power protection at  
locations where there is no service transformer. For this  
reason, if 460.980 (4)(a) is not deleted, the Company  
recommends the setting criteria be defined in the utility  
procedures.  
Commented [A18]: Under-power (non-exporting)  
protective functions don’t ensure power is never exported.  
Under-power protection is meant to detect and remove  
export.  
(c)This option requires the nameplate rating of the DER, minus any auxiliary load, to  
be so small in comparison to its host facility’s minimum load that the use of additional  
For this reason, if 460.980 (4)(b) is not deleted, the Company  
recommends the setting criteria be defined in the utility  
procedures.  
Attachment A  
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37  
protective functions is not required to ensure that power will not be exported to the  
distribution system. This option requires the DER capacity to be no greater than 50% of  
the applicant’s verifiable minimum host load over the past 12 months.  
(d) A certified power control system that reduced output rating utilizing the power  
rating configuration setting may be used to ensures the DER does not generate power  
beyond a certain value lower than the nameplate rating.  
Commented [A19]: If 460.980 (4)(c) is not deleted, the  
Company recommends it be updated to include references to  
the specific protection functions being referred to in R  
460.980 (a) and (b). The current language can be  
misinterpreted as meaning that additional protection  
functions defined in the utility procedures (e.g. 51V, 59N)  
are not required.  
Commented [A20]: The Company believes this  
requirement is a safety and reliability concern. Utilities  
cannot study the impact of a DER assuming the current (or  
future) owner will maintain the minimum load for the  
lifespan of the DER. Failure of an applicant or future DER  
owner to maintain minimum load may lead to damaged  
equipment. For this reason, the Company recommends  
460.980 (4)(c) should be removed.  
(e) DERs may utilize, a nationally recognized testing laboratoryA certified power  
control system and inverter system that results in the DER disconnecting from the  
distribution system, ceasing to energize the distribution system or halting energy  
productionlimiting inadvertent export within 2 seconds if the period of continuous  
inadvertent export exceeds 30 seconds. The electric utility may require additional  
protective functions. Failure of the control or inverter system for more than 30 seconds,  
resulting from loss of control or measurement signal, or loss of control power, must result  
in the DER entering an operational mode where no energy is exported across the point of  
common coupling to the distribution system.  
(f) DERs may be designed with other control systems or protective functions, or both  
that are mutually agreed upon by the applicant and the electric utility, to limit export and  
inadvertent export to levels mutually agreed upon by the applicant and the electric utility.  
The limits may be based on technical limitations of the applicant’s equipment or the  
distribution system’s equipment. To ensure inadvertent export remains within mutually  
agreed-upon limits, the applicant shall use an internal transfer relay, energy management  
system, or other customer facility hardware or software.  
Commented [A21]: A power rating configuration setting  
is a power control system. A power rating configuration  
setting needs to be certified. If 460.980 (4) (d) is not deleted,  
the Company recommends replacing “power rating  
configuration settings” with “power control system”. The  
power control system definition includes the certification  
requirements.  
Commented [A22]: If 460.980 (4)(e) is not deleted, the  
Company notes that a certified power control system  
includes inverter systems, and recommends that specifically  
calling them out is not required. This comment also applies  
to “or inverter system” in the same paragraph below.  
Commented [A23]: The UL 1741 CRD for PCS testing  
standard states that the open loop response time will be 30  
seconds by default but also notes that faster PCS response  
times may be required to meet specific utility requirements.  
If 460.980 (4)(e) is not deleted, the Company recommends  
that the slowest response time, in order for certification,  
should be defined in utility procedures.  
R 460.982 Modification of the interconnection application.  
Rule 82. (1) At any point after an interconnection application is considered accepted  
but before the signing of an interconnection agreement, the applicant, the electric utility,  
or the affected system owner may propose modifications to the interconnection  
application that may improve the costs and benefits of the interconnection, or that  
improve the ability of the electric utility to accommodate the interconnection. The  
applicant shall submit to the electric utility, in writing, all proposed modifications to any  
information provided in the interconnection application and the electric utility shall  
perform an evaluation to determine whether the proposed modification is a material  
modification and provide the results to the applicant within 10 business days.  
(2) The electric utility shall not be required to accept or implement a modification to the  
electric utility’s distribution system or generation assets that is proposed by an applicant or  
affected system operator.  
Commented [A24]: The UL 1741 CRD for PCS testing  
standard does not provide certification that power control  
systems disconnect, cease to energize, or halts energy  
production within any timeframe. The standard is used to  
certify power control system properly limits the output  
power and any unscheduled export within a specified  
timeframe. If 460.980 (4)(e) is not deleted, the Company  
recommends that the language should be updated to reflect  
this standard.  
Commented [A25]: The Company recommends that non-  
certified control system or protective functions shall only be  
accepted if both entities mutually agree. If 460.980 (4)(f) is  
not deleted, the Company recommends that the requirement  
for mutual agreement should be added to the rules.  
(3) The applicant may request a 1-hour consultation to discuss the results of the material  
modification review.  
(4) Neither the electric utility nor the affected system operator may unilaterally modify  
an accepted interconnection application. If the electric utility evaluates DERs using  
individual studies, the timelines specific to that interconnection application must be  
placed on hold while the proposed modification is being evaluated by the electric utility.  
(5) For a proposed modification which the electric utility has determined is a material  
modification and that further study is required, the applicant shall select 1 of the  
following options:  
Attachment A  
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38  
(a) Withdraw the modification.  
(b) Withdraw the application.  
(c) Propose a different modification to the interconnection application for electric  
utility review pursuant to subrule (1) of this rule to determine whether the modification is  
material.  
(d) If the electric utility offers an expedited study of the application with the proposed  
material modification, the applicant may request the expedited study. If the electric  
utility offers an expedited study, the process of performing an expedited study must be  
described in the electric utility’s interconnection procedures.  
(e) Initiate informal mediation pursuant to R 460.904  
(f) Initial formal mediation pursuant to R460.906  
(g) File a complaint pursuant to R 792.10439 to R 792.10446.  
(6) The applicant shall notify the electric utility of its selection pursuant to subrule (5) of  
this rule within 10 business days of receiving the electric utility notification of the results  
or the modification may be considered withdrawn.  
(7) For a proposed modification which the electric utility has determined is a material  
modification, but which does not require further study, the electric utility shall continue  
processing the interconnection application according to these rules.  
(8) Any modification to the interconnection application that could affect the operation  
of the distribution system, including but not limited to, changes to machine data,  
equipment configuration, or the interconnection site of the DER, not agreed to in writing  
by the electric utility and the applicant may be treated by the electric utility as a  
withdrawal of the interconnection application requiring submission of a new  
interconnection application.  
(9) At any point prior to the execution of an interconnection agreement, changes to  
ownership will cause the interconnection application to be put on hold until the new  
owner signs all necessary agreements and documents. An electric utility may not be  
found in violation of these rules related to the processing of the interconnection  
application during such a transfer of ownership.  
(10) The electric utility’s interconnection procedures must provide a procedure for  
performing a material modification review.  
R 460.984 Modifications to the DER.  
Rule 84. After the execution of the interconnection agreement, the applicant shall notify  
the electric utility of any plans to modify the DER. The electric utility shall review the  
proposed modification to determine if the modification is considered a material  
modification. If the electric utility determines that the modification is a material  
modification, the electric utility shall notify the applicant, in writing of its determination  
and the applicant shall submit a new application and application fee along with all  
supporting materials that are reasonably requested by the electric utility. The applicant  
may not begin any material modification to the DER until an interconnection agreement  
incorporating the material modification is fully executed.  
R 460.986 Insurance.  
Attachment A  
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39  
Rule 86. (1) An applicant interconnecting a level 1 or 2 project to the distribution  
system of an electric utility may not be required by the electric utility to obtain any  
additional liability insurance.  
(2) An electric utility shall not require an applicant interconnecting a level 1 or 2 project  
to name the electric utility as an additional insured party.  
(3) For a level 3 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $1,000,000.  
(4) For a level 4 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $2,000,000.  
(5) For a level 5 project, the applicant shall obtain and maintain general liability  
insurance of a minimum of $3,000,000.  
(6) For level 3, 4, and 5 projects, the electric utility may describe in its interconnection  
procedures required terms and conditions which must be specified in the general liability  
insurance.  
R 460.988 Easements and rights-of-way.  
Rule 88. If an electric utility line extension is required to accommodate an  
interconnection, the electric utility is responsible for providing and obtaining easements  
or rights-of-way. The applicant is responsible for the cost of providing and obtaining  
easements or rights-of-way.  
R 460.990 Interconnection penalties.  
Rule 90. Pursuant to section 10e of 1939 PA 3, MCL 460.10e, an electric utility shall  
take all necessary steps to ensure that DERs are connected to the distribution systems  
within their operational control. If the commission finds, after notice and hearing, that an  
electric utility has prevented or unduly delayed the ability of a DER greater than 100 kW  
to connect to the distribution system of the electric utility, the commission may order  
remedies designed to make whole the applicant proposing the DER, including, but not  
limited to, reasonable attorney fees. If the electric utility violates this rule, the  
commission may order fines of not more than $50,000 per day, commensurate with the  
demonstrated impact of the violation.  
R 460.991 Business day exclusions.  
Rule 91. An electric utility shall notify the commission and all applicants that have in-  
process applications when timelines are being extended due to a day in which electric  
service is interrupted for 10% or more of an electric utility’s customers pursuant to R  
460.901a(k). The electric utility shall also notify the commission and all applicants that  
have in-process applications when application processing resumes.  
R 460.992 Electric utility annual reports.  
Rule 92. An electric utility shall file an annual interconnection report on a date and in a  
format determined by the commission.  
Attachment A  
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40  
PART 3. DISTRIBUTED GENERATION PROGRAM STANDARDS  
R 460.1001 Application process.  
Rule 101. (1) An electric utility shall file initial distributed generation program tariff  
sheets in the first rate case filed after June 1, 2018.  
(2) Within calendar 30 days of a commission order approving an electric utility’s initial  
distributed generation tariff, or within 30 calendar days of the effective date of these  
rules, whichever is later, an alternative electric supplier serving customers in that electric  
utility’s service territory shall file an updated distributed generation program plan  
applicable to its customers in the affected electric utility’s service territory.  
(3) An electric utility and an alternative electric supplier shall annually file a legacy net  
metering program report and, if applicable, a distributed generation program report not  
later than March 31 of each year.  
(4) An electric utility and an alternative electric supplier shall maintain records of all  
applications and up-to-date records of all eligible electric generators participating in the  
legacy net metering program and distribution generation program.  
(5) Selection of customers for participation in the legacy net metering program or  
distributed generation program must be based on the order in which the applications are  
received.  
(6) An electric utility or alternative electric supplier shall not refuse to provide or  
discontinue electric service to a customer solely because the customer participates in the  
legacy net metering program or distributed generation program.  
(7) The legacy net metering program and distributed generation program provided by  
electric utilities and alternative electric suppliers must be designed for a period of not less  
than 10 years and limit each applicant to generation capacity designed to meet up to  
100% of the customer’s electricity consumption for the previous 12 months.  
(a) The generation capacity must be determined by an estimate of the expected annual  
kWh output of the generator or generators as determined in an electric utility’s  
interconnection procedures and specified on an electric utility's legacy net metering  
program or distributed generation program tariff sheet or in the alternative electric  
supplier’s legacy net metering program or distributed generation program plan. For  
projects in which energy export controls are implemented pursuant to section R 460.980  
and utilized to limit the export to 100% of the customer’s electricity consumption for the  
previous 12 months, an electric utility shall not add the storage capacity to generation  
capacity for the purpose of the study. If a customer has multiple inverters capable of  
exporting to the distribution grid, the inverters must be configured in a way that prevents  
the cumulative maximum export at any given time to exceed the approved amount in the  
customer’s application.  
(b) A customer’s electric consumption must be determined by 1 of the following  
methods:  
(i) The customer’s annual energy consumption, measured in kWh, during the previous  
12-month period.  
Attachment A  
Page 41 of 50  
41  
(ii) If there is no data, incomplete data, or incorrect data for the customer’s energy  
consumption or the customer is making changes on-site that will affect total  
consumption, the electric utility or alternative electric supplier and the customer shall  
mutually agree on a method to determine the customer’s electric consumption.  
(c) A net metering or distributed generation customer using an energy storage device in  
conjunction with an eligible electric generator shall not design or operate the energy storage  
device in a manner that results in the customer’s electrical output exceeding 100% of the  
customer’s electricity consumption for the previous 12 months. The addition of an energy  
storage device to an existing approved legacy net metering program system or distributed  
generation program system is considered a material modification. The electric utility  
interconnection procedures must include details describing how energy storage equipment  
may be integrated into an existing legacy net metering program system without impacting  
the 10-year grandfathering period or participation in the distributed generation program.  
(8) An applicant shall notify the electric utility of plans for any material modification to  
the project. An applicant shall re-apply for interconnection pursuant to part 2 of these  
rules, R 460.911 to R 460.992, and submit revised legacy net metering program or  
distributed generation program application forms and associated fees. An applicant may  
be eligible to continue participation in the legacy net metering program or distributed  
generation program when a material modification is made to a customer’s previously  
approved system and it does not violate the requirements of subrule (7) of this rule or R  
460.1026. An applicant shall not begin any material modification to the project until the  
electric utility has approved the revised application, including any necessary system  
impact study or facilities study. The application must be processed pursuant to part 2 of  
these rules, R 460.911 to R 460.992.  
R 460.1004 Legacy net metering program application and fees.  
Rule 104. (1) An electric utility or alternative electric supplier may use an online legacy  
net metering program application process. An electric utility or alternative electric  
supplier not using an online application process, may utilize a uniform legacy net  
metering program application form which must be approved by the commission. An  
electric utility’s legacy net metering program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the legacy net metering program shall concurrently submit a completed  
legacy net metering program application and interconnection application or indicate on  
the legacy net metering program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968.  
(a) Where a legacy net metering program application is accompanied by an associated  
interconnection application, an electric utility shall complete its review of the legacy net  
metering program application in parallel with processing the interconnection application  
pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, the electric utility shall notify the customer whether  
the legacy net metering program application is accepted, and provide an opportunity for  
Attachment A  
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42  
the customer to resolve any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application, or the electric utility may consider the legacy  
net metering program application withdrawn without refund of the application fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.946 fast track initial review, the electric utility shall determine whether  
the appropriate meter or meters, is installed for the legacy net metering program.  
(b) When a legacy net metering program application is filed with an already in-progress  
interconnection application, the utility may process the legacy net metering application in  
parallel with the interconnection application pursuant to part 2 of these rules, R 460.911  
to R 460.992, and subrule (2)(a) of this rule, if practicable, or adopt the review process  
pursuant to subrule (2)(c) of this rule.  
(c) When a legacy net metering program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the legacy net metering program application in parallel with the interconnection  
application, or when the legacy net metering application is filed subsequent to the  
customer receiving authorization to operate its eligible generator in parallel pursuant to R  
460.968, the electric utility shall process the legacy net metering program application  
pursuant to both of the following:  
(i) The electric utility shall review the legacy net metering program application and  
determine whether to accept the application pursuant to the timelines in R 460.936(6) and  
(7) within 10 business days. The timelines in R 460.936(7)(a) apply to electric utility  
notifications. The electric utility shall provide the customer an opportunity to resolve any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
deficiency within the timelines pursuant to R. 460.936(7)(b), the electric utility may  
consider the legacy net metering application withdrawn without refund of the application  
fees.  
(ii) Within 10 business days of notifying the customer that the legacy net metering  
application has been accepted, the electric utility shall determine whether the appropriate  
meter is installed for the legacy net metering program.  
(d) If a customer approved for participation in the legacy net metering program requires  
a new or additional meter or meters, the electric utility shall arrange with the customer to  
install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit the  
legacy net metering program credit to be applied to the account no more than 10 business  
days after the necessary meter is installed and all necessary steps in R 460.966 are  
completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed legacy net metering program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The electric utility shall process the legacy net metering program application  
according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
Attachment A  
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43  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit the legacy net  
metering program credit to be applied to the account.  
(4) If a legacy net metering program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the deficiency  
within the timelines pursuant to R. 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the legacy net metering application withdrawn without  
refund of the application fees.  
(5) If a customer’s application for the legacy net metering program is approved, the  
customer shall have a completed and approved installation within 6 months from the date  
the customer’s application is considered complete, or the electric utility or alternative  
electric supplier may terminate the application without refund and shall have no further  
responsibility with respect to the application.  
(6) Customers participating in a legacy net metering program approved by the  
commission before the commission establishes a tariff pursuant to section 6a(14) of 1939  
PA 3, MCL 460.6a, may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment.  
(7) The legacy net metering program application fee for electric utilities and alternative  
electric suppliers may not exceed $50. The fee must be specified on the electric utility’s  
legacy net metering tariff sheet or in the alternative electric supplier's legacy net metering  
program plan.  
R 460.1006 Distributed generation program application and fees.  
Rule 106. (1) An electric utility or alternative electric supplier may use an online  
distributed generation program application process. An electric utility or alternative  
electric supplier not using an online application process may utilize a uniform distributed  
generation program application form that must be approved by the commission. An  
electric utility’s distributed generation program application may be combined with an  
electric utility’s interconnection application.  
(2) A customer taking retail electric service from an electric utility and applying to  
participate in the distributed generation program shall concurrently submit a completed  
distributed generation program application and interconnection application or indicate on  
the distributed generation program application the date that the customer applied for  
interconnection with the electric utility and, if applicable, the date the customer received  
authorization to operate in parallel pursuant to R 460.968.  
(a) When a distributed generation program application is accompanied by an associated  
interconnection application, an electric utility may complete its review of the distributed  
generation program application concurrently, before, or after processing the  
interconnection application pursuant to part 2 of these rules, R 460.911 to R 460.992.  
(i) Combined with the notification of interconnection application completeness and  
conformance pursuant to R 460.936, an electric utility shall notify the customer whether  
the distributed generation program application is accepted, and provide an opportunity for  
Attachment A  
Page 44 of 50  
44  
the customer to remedy any application deficiencies pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the electric utility may consider the  
distributed generation program application withdrawn without refund of the application  
fees.  
(ii) While processing the interconnection application, which may include, but is not  
limited to, R 460.946 fast track initial review, the electric utility shall determine whether  
the appropriate meter is installed for the distributed generation program.  
(b) If a distributed generation program application is filed with an already in-progress  
interconnection application, the electric utility may process the distributed generation  
program application in parallel with the interconnection application pursuant to part 2 of  
these rules, R 460.911 to R 460.992, and subrule (2)(a) of this rule, if practicable, or  
adopt the review process pursuant to subrule (2)(c) of this rule.  
(c) If a distributed generation program application is filed with an in-progress  
interconnection application and the electric utility determines it is not practicable to  
process the distributed generation program application in parallel with the  
interconnection application or the distributed generation application is filed subsequent to  
the customer receiving authorization to operate its eligible generator in parallel pursuant  
to R 460.968, the electric utility shall process the distributed generation program  
application pursuant to all of the following:  
(i) The electric utility has 10 business days to review the distributed generation  
program application and determine whether to accept the application pursuant to the  
timelines in R 460.936(6) and (7). The timelines in R 460.936(7)(a) apply to utility  
notifications. The electric utility shall provide the customer an opportunity to remedy any  
application deficiencies pursuant to R 460.936(7)(b). If the customer fails to remedy the  
application deficiencies within the timelines in R 460.936(7)(b), the electric utility may  
consider the distributed generation program application withdrawn without refund of the  
application fees.  
(ii) Within 10 business days of providing notification to the customer that the  
distributed generation program application has been accepted, the electric utility shall  
determine whether the appropriate meter, or meters, is installed for the distributed  
generation program.  
(d) If a customer approved for participation in the distributed generation program  
requires a new or additional meter or meters, the electric utility shall arrange with the  
customer to install the meter or meters at a mutually agreed upon time.  
(e) The electric utility shall complete changes to the customer’s account to permit  
distributed generation program credit to be applied to the account no more than 10  
business days after the necessary meter is installed and all necessary steps in R 460.966  
are completed.  
(3) A customer taking retail electric service from an alternative electric supplier shall  
submit a completed distributed generation program application to the alternative electric  
supplier and provide a copy to the electric utility that provides distribution service.  
(a) The alternative electric supplier shall process the distributed generation program  
application according to the applicable timelines in subrule (2)(a) through (d) of this rule.  
(b) The electric utility shall notify the alternative electric supplier when it has provided  
the applicant authorization to operate the eligible electric generator in parallel pursuant to  
Attachment A  
Page 45 of 50  
45  
R 460.968 and, if applicable, that installation of the appropriate meter or meters is  
completed.  
(c) Within 10 business days of the electric utility’s notification, the alternative electric  
supplier shall complete changes to the applicant's account to permit distributed generation  
program credit to be applied to the account.  
(4) If a distributed generation program application is not approved by the alternative  
electric supplier, the alternative electric supplier shall notify the customer and the electric  
utility of the reasons for the disapproval. The alternative electric supplier shall provide  
the customer an opportunity to remedy the deficiency pursuant to the timelines in R  
460.936(7)(b) or withdraw the application. If the customer fails to remedy the application  
deficiencies within the timelines in R 460.936(7)(b), the alternative electric supplier and  
electric utility may consider the distributed generation program application withdrawn  
without refund of the application fees.  
(5) If a customer’s distributed generation program application is approved, the customer  
shall have a completed and approved installation within 6 months from the date the  
customer’s application is considered complete, or the electric utility or alternative electric  
supplier may consider the application withdrawn without refund and shall have no further  
responsibility with respect to the application.  
(6) The distributed generation program application fee for electric utilities and  
alternative electric suppliers shall not exceed $50. The electric utility shall specify the fee  
on the electric utility’s distributed generation program tariff sheet or in the alternative  
electric supplier’s distributed generation program plan.  
(7) The customer shall pay all interconnection costs pursuant to part 2 of these rules, R  
460.911 to R 460.992, which include all electric utility costs associated with the  
customer’s interconnection that are not a distributed generation program application fee,  
excluding meter costs as described in R 460.1012 and R 460.1014.  
R 460.1008 Legacy net metering program and distributed generation program size.  
Rule 108. (1) If an electric utility or alternative electric supplier reaches the program  
sizes as defined in section 173(3) of the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1173 or a voluntarily expanded program above the  
requirements defined in section 173(3) of the clean and renewable energy and energy  
waste reduction act, 2008 PA 295, MCL 460.1173, as determined by combining both the  
distributed generation program and the legacy net metering program customer  
enrollments, the electric utility or alternative electric supplier shall notify the  
commission.  
(2) The electric utility or alternative electric supplier shall notify the commission of its  
plans to either close the program to new applicants or expand the program.  
(3) The electric utility shall file corresponding revised legacy net metering program or  
distributed generation program tariff sheets.  
(4) The alternative electric supplier shall file a revised legacy net metering program plan  
or distributed generation program plan.  
Attachment A  
Page 46 of 50  
46  
R 460.1010 Generation and legacy net metering program or distributed generation  
program equipment.  
Rule 110. New legacy net metering program or distributed generation program  
equipment and its installation must meet all current local and state electric and  
construction code requirements, and other standards as specified in part 2 of these rules,  
R 460.911 to R 460.992.  
R 460.1012 Meters for legacy net metering program.  
Rule 112. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility may determine the customer’s net usage using the customer’s  
existing meter if it is capable of reverse registration or may install a single meter with  
separate registers measuring power flow in each direction. If the electric utility uses the  
customer’s existing meter, the electric utility shall test and calibrate the meter to assure  
accuracy in both directions. If the customer’s meter is not capable of reverse registration  
and if meter upgrades or modifications are required, the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to the legacy net metering program customer. The cost of the meter or  
meter modification is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for the meter provided by the electric utility  
to similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter, if requested by the customer, at  
cost.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, the electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
upgrades are necessary to provide this functionality, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a legacy net metering program customer. The cost of the meter or  
meters is considered a cost of operating the legacy net metering program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above that for meters provided by the electric utility to  
similarly situated non-generating customers shall be paid by the eligible customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter is  
considered a cost of operating the legacy net metering program.  
(3) For a customer with a generation system capable of generating more than 150 kWac,  
the electric utility shall utilize a meter or meters capable of measuring the flow of energy  
in both directions and the generator output. If meter upgrades are necessary to provide  
this functionality, the customer shall pay the cost of providing any new meters.  
Attachment A  
Page 47 of 50  
47  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a legacy net metering program participant or the legacy net  
metering program.  
R 460.1014 Meters for distributed generation program.  
Rule 114. (1) For a customer with a generation system capable of generating 20 kWac  
or less, an electric utility shall determine the customer’s power flow in each direction  
using the customer's existing meter if it is capable of measuring and recording power  
flow in each direction. If the customer’s meter is not capable of measuring and recording  
the customer’s power flow in each direction and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring and recording the customer’s power flow in each  
direction at no additional charge to the distributed generation program customer. The cost  
of the meter or meter modification is considered a cost of operating the distributed  
generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring and recording the power flow in each direction to  
customers at cost. Only the incremental cost above the cost for the meter provided by the  
electric utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter at cost, if requested by the  
customer.  
(2) For a customer with a generation system capable of generating more than 20 kWac  
and not more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring and recording power flow in each direction and the generator output. If the  
customer’s meter is not capable of measuring and recording the customer’s power flow in  
each direction along with the generator output, and if meter upgrades or modifications are  
required, all of the following apply:  
(a) An electric utility serving 1,000,000 or more customers in this state shall provide a  
meter or meters capable of measuring the flow of energy in both directions at no  
additional charge to a distributed generation program customer. If the electric utility  
provides the upgraded meter at no additional charge to the customer, the cost of the meter  
is considered a cost of operating the distributed generation program.  
(b) An electric utility serving fewer than 1,000,000 customers in this state shall provide  
a meter or meters capable of measuring the flow of energy in both directions to customers  
at cost. Only the incremental cost above the cost for the meter provided by the electric  
utility to similarly situated non-generating customers shall be paid by the eligible  
customer.  
(c) An electric utility shall provide a generator meter. The cost of the meter shall be  
considered a cost of operating the distributed generation program.  
(3) For a customer with a methane digester generation system capable of generating  
more than 150 kWac, an electric utility shall utilize a meter or meters capable of  
measuring the flow of energy in both directions and the generator output. If meter  
Attachment A  
Page 48 of 50  
48  
upgrades are necessary to provide such functionality, the customer shall pay the cost of  
providing any new meters.  
(4) An electric utility deploying advanced metering infrastructure shall not charge the  
cost of advanced meters to a distributed generation program customer or the distributed  
generation program.  
R 460.1016 Billing and credit for legacy net metering program customers taking service  
under true net metering.  
Rule 116. (1) Legacy net metering program customers with a system capable of  
generating 20 kWac or less qualify for true net metering. For customers qualifying for  
true net metering, the net of the bidirectional flow of kWh across the customer  
interconnection with the electric utility distribution system during the billing period or  
during each time-of-use pricing period within the billing period, including excess  
generation, shall be credited at the full retail rate.  
(2) The credit for excess generation, if any, shall appear on the next bill. Any excess  
credit not used to offset current charges must be carried forward for use in subsequent  
billing periods.  
R 460.1018 Billing and credit for legacy net metering program customers taking service  
under modified net metering.  
Rule 118. (1) Legacy net metering program customers with a system capable of  
generating more than 20 kWac qualify for modified net metering. A negative net metered  
quantity during the billing period or during each time-of-use pricing period within the  
billing period reflects net excess generation for which the customer is entitled to receive  
credit. Standby charges for customers on an energy rate schedule must equal the retail  
distribution charge applied to the imputed customer usage during the billing period. The  
imputed customer usage is calculated as the sum of the metered on-site generation and  
the net of the bidirectional flow of power across the customer interconnection during the  
billing period. The commission shall establish standby charges for customers on demand-  
based rate schedules that provide an equivalent contribution to electric utility system  
costs. Standby charges may not be applied to customers with systems capable of  
generating 150 kWac or less.  
(2) The credit for excess generation must appear on the next bill. Any excess kWh not  
used to offset current charges must be carried forward for use in subsequent billing  
periods.  
(3) A customer qualifying for modified net metering shall not have legacy net metering  
program credits applied to distribution charges.  
(4) The credit per kWh for kWh delivered into the electric utility’s distribution system  
must be either of the following as determined by the commission:  
(a) The monthly average real-time locational marginal price for energy at the  
commercial pricing node within the electric utility’s distribution service territory or for a  
legacy net metering program customer on a time-based rate schedule, the monthly  
average real time locational marginal price for energy at the commercial pricing node  
Attachment A  
Page 49 of 50  
49  
within the electric utility’s distribution service territory during the time-of-use pricing  
period.  
(b) The electric utility’s or alternative electric supplier’s power supply component,  
excluding transmission charges, of the full retail rate during the billing period or time-of-  
use pricing period.  
R 460.1020 Billing and credit for distributed generation program customers.  
Rule 120. As part of an electric utility’s rate case filed after June 1, 2018, the  
commission shall approve a tariff for a distributed generation program under the clean  
and renewable energy and energy waste reduction act, 2008 PA 295, MCL 460.1001 to  
460.1211. A tariff established under this rule does not apply to customers participating in  
a legacy net metering program under the clean and renewable energy and energy waste  
reduction act, 2008 PA 295, MCL 460.1001 to 460.1211, before the date that the  
commission establishes a tariff under this rule, who continue to participate in the program  
at their current site or facility as described by R 460.1026.  
R 460.1022 Renewable energy credits.  
Rule 122. (1) An eligible electric generator shall own any renewable energy credits  
granted for electricity generated under the legacy net metering program and distributed  
generation program.  
(2) An electric utility may purchase or trade renewable energy credits from a legacy net  
metering program or distributed generation program customer if agreed to by the  
customer.  
(3) The commission may develop a program for aggregating renewable energy credits  
from legacy net metering program and distributed generation program customers.  
R 460.1024 Penalties.  
Rule 124. Upon a complaint or on the commission’s own motion, if the commission  
finds after notice and hearing that an electric utility has not complied with a provision or  
order issued under part 5 of the clean and renewable energy and energy waste reduction  
act, 2008 PA 295, MCL 460.1171 to 460.1185, the commission shall order remedies and  
penalties as necessary to make whole a customer or other person who has suffered  
damages as a result of the violation.  
R 460.1026 Legacy net metering grandfathering clause.  
Rule 126. A customer participating in a legacy net metering program approved by the  
commission before the commission establishes the initial distributed generation program  
tariff pursuant to R 460.1020 may elect to continue to receive service under the terms and  
conditions of that program for up to 10 years from the date of initial enrollment. “Initial  
enrollment,” as used in this rule, means the date a customer or site initially enrolled in a  
legacy net metering program as described in the electric utility’s tariff. A customer  
participating in a legacy net metering program who increases the nameplate capacity of  
Attachment A  
Page 50 of 50  
50  
its generation system after the effective date of an electric utility’s distributed generation  
program tariff is no longer eligible to participate in the legacy net metering program.  
From:  
To:  
Subject:  
Date:  
Marco Menezes  
LARA-MPSC-EDOCKETS  
Distributed Generation Rules  
Monday, June 27, 2022 9:36:57 AM  
CAUTION: This is an External email. Please send suspicious emails to  
abuse@michigan.gov  
As the MPSC considers updating Michigan’s distributed generation rules, it should undertake  
a full “Value of Solar” study to assist in re-determining rates of reimbursement for power  
added to the grid by small, non-commercial distributed producers. A comprehensive analysis  
which assigns economic value to avoided externalities (pollution, climate change, etc) was not  
done when the current rates were set. Instead, the unsubstantiated, utility-promoted myth that  
residential solar is somehow “subsidized” by other rate-payers was uncritically accepted as  
fact. With the current low market penetration of renewables in the state, assigning the same  
“avoided cost” valuation to new renewable and fossil fuel choices was and remains an “apples  
to oranges” comparison.  
The resulting gross undervaluation of distributed generation underpinning current rate  
structure has significantly depressed expansion of residential solar in our State at a critical  
time of essential transition away from fossil fuels.  
Marco Menezes  
Hersey, MI  
Dykema Gossett PLLC  
Capitol View  
201 Townsend Street, Suite 900  
Lansing, MI 48933  
WWW.DYKEMA.COM  
Tel: (517) 374-9100  
Fax: (517) 374-9191  
Richard J. Aaron  
Direct Dial: (517) 374-9198  
Direct Fax: (855) 230-2517  
Email: RAaron@dykema.com  
June 27, 2022  
Lisa Felice  
Executive Secretary  
Michigan Public Service Commission  
PO Box 30221  
Lansing, MI 48909-7721  
Re: Case No. U-20890  
Michigan Electric Cooperative Association  
Dear Ms. Felice:  
Enclosed for electronic filing please find the Comments Of The Michigan Electric  
Cooperative Association in the above-referenced matter.  
If you have any questions, please contact me.  
Sincerely,  
DYKEMA GOSSETT PLLC  
Richard J. Aaron  
111253.000001  
California | Illinois | Michigan | Minnesota | Texas | Washington, D.C. | Wisconsin  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
* * * * *  
In the matter, on the Commission’s own motion, to )  
promulgate rules governing electric interconnection )  
reconciliation of its power supply cost recovery  
and distributed generation, and rescind  
legacy interconnection and net metering rules.  
)
)
)
Case No. U-20890  
COMMENTS OF THE MICHIGAN ELECTRIC COOPERATIVE ASSOCIATION  
The Michigan Electric Cooperative Association1 (“MECA”) appreciates the time and effort  
the parties have spent on developing the proposed rules in this case. Accordingly, MECA  
respectfully submits these comments in response to the May 26, 2022 Order of the Michigan Public  
Service Commission (the “Commission”) providing for renewed comments on its proposed  
Interconnection and Distribution Generation Standards (“Proposed Rules”):  
Introduction  
Paramount to MECA and its members is the safety and reliability of their distribution  
systems—which support a wide variety of commercial and residential activity throughout the state.  
MECA’s collective customer base is located in rural and historically underserved areas of  
Michigan and the health and livelihood of many customers within MECA’s collective service  
territory depends on a safe and reliable distribution grid. It is vital for MECA cooperatives to have  
1
MECA is a Michigan non-profit corporation, incorporated on July 26, 1978. MECA serves as  
the statewide association for Michigan’s rural electric distribution cooperatives, one generation  
and transmission cooperative, and one alternative electric supplier, who, combined, provide  
electricity to more than 650,000 Michigan residents in all or part of 58 Michigan counties.  
Currently, all of MECA’s member cooperatives are member-regulated under 2008 PA 167, as  
amended, MCL 460.31 et seq.  
4856-5083-1653.3  
1
the tools and ability to study and mitigate potential critical safety issues. While it is apparent that  
the legacy Interconnection and Distribution Generation Standards (pre-March 17, 2022  
amendment) (the “original MIXDG rules”) need to be revised because of the proliferation of third-  
party designed devices and the increasing popularity of distributed energy resources (“DERS”), it  
is important that revisions to the original MIXDG rules do not come at the cost of the MECA  
cooperatives’ ability to test and approve all proposed interconnections to their distribution systems.  
Protecting this right is critical to ensuring the safety of the MECA cooperatives’ customers,  
employees, and infrastructure. There are also a number of proposed rule changes that require  
current clarification—particularly because MECA cooperatives have already developed and  
submitted to stakeholders proposed interconnection procedures and forms which could be in  
conflict with the March 17, 2022 amended version of the Rules and the Proposed Rules.  
MECA appreciates the re-opening of this docket for the opportunity to submit additional  
comments and that, before the Commission approves its final rules, all parties have the opportunity  
to comment and weigh in on the proposals.  
Comments  
1.  
The Proposed Rules do Not Adequately Safeguard the MECA Cooperatives’ Ability  
to Provide a Safe and Reliable Distribution System.  
First and foremost, the Proposed Rules do not put enough control over vetting safety and  
reliability measures in the hands of the MECA cooperatives. While the comments below outline  
the specific ways in which these measures are lacking, it is important to note that when these issues  
are taken as a whole, the MECA cooperatives (and indeed all electric utilities under the rules)  
likely stand to provide less reliable energy to their customers as a direct result of the Proposed  
Rules, if those rules are not modified.  
2
These concerns regarding the safety, reliability and control of the MECA cooperatives’  
distribution system also implicate their ability to manage their privately owned property. By  
preventing the MECA cooperatives from adequately protecting its systems from DER exports,  
particularly during outage (i.e., fault) conditions, the Proposed Rules physically interfere with the  
MECA cooperatives’ ability to manage the safety and reliability of their distribution system. The  
physical appropriation of property—even temporarily—is impermissible under the Fifth  
Amendment. Cedar Point Nursery v Hassid, 141 S. Ct. 2063; __ U.S. __ (2021) (“The fact that a  
right to take access is exercised only from time to time does not make it any less a physical  
taking.”).  
2.  
The Proposed Rules Should Reintegrate Allowances for Additional Initial Screening  
Procedures.  
The Proposed Rules eliminated a previous allowance for additional supplemental review  
screens and thereby impair the ability of MECA to provide meaningful review in their  
interconnection procedures from Mich Admin Code, R. 460.950. Eliminating this important  
reliability safeguard will have potentially adverse outcomes. Additional supplemental review  
screens should be regarded as safety measure for the MECA cooperatives and not administrative  
“red tape.” In addition, the additional screens also benefit DER parties by identifying problems  
before they arise. Prior to the Proposed Rules, an electric utility was required to provide a “detailed  
technical rationale” and an “explanation of the technical justification for the additional screen” to  
implement additional supplemental screens—i.e., additional screens were not implemented  
arbitrarily. However, the Proposed Rules eliminated this ability to require additional screens  
where needed for technical reasons and therefore forces MECA cooperatives to fast track  
interconnections that have not been properly vetted. In turn, the Commission risks the reliability  
of the distribution system and the safety of other customers, unless the Final Rules reinstate the  
3
ability to implement additional screens. As the MECA cooperatives noted in their Answer to the  
DTE Petition for Rehearing:  
The proposed rules effectively allow dangerous operation until the project trips  
offline or the electric grid comes back online. This amount of time (short or long)  
can cause a transformer to fail catastrophically (potentially including a fire),  
seriously impact power quality to adjacent customers (potentially including  
appliance failures), and even feed into faults (both on the local distribution system  
and the upstream affected systems) that puts public health and safety at risk.  
This issue goes essentially unaddressed in the Proposed Rules and there is no opportunity for the  
MECA cooperatives to assess a potentially dangerous interconnection in an appropriate timeframe.  
The initial screens in Rules 46 and 50 are essential to the MECA cooperatives to determine  
if upgrades to the distribution system is required. Upgrades are essential for some interconnections  
to maintain the reliability and safety of the of grid and public, and potential upgrades need to be  
identified as soon as possible. Additionally, upgrades add costs that are the responsibility of the  
DER. It is important that the MECA cooperatives provide certainty to the DER as early as possible  
because it may dictate how the DER wants to proceed with their project.  
The MECA cooperatives recommend reinserting the additional supplemental review  
screens into the Proposed Rules.  
3.  
The Proposed Rules limit MECA Cooperatives’ Ability to Control the Safety of DER  
Power Export Limits.  
The Proposed Rules limit MECA cooperatives’ ability to control the safety of their  
distribution system by limiting the actions that the MECA cooperatives can take when controlling  
for DER power exports. The Proposed Rules provide that “[t]o prevent impacts on system safety  
and reliability, any inadvertent export from a DER must comply with the limits in subdivisions (e)  
or (f) of this subrule. . . . Other means not listed in this subrule may be utilized to limit export if  
mutually agreed upon by the electric utility and the applicant.” Mich Admin Code, R 460.980(4).  
4
In subdivisions (e) and (f), the only safety measures permitted are in the sole control of the DER  
to monitor and implement.  
The addition of subpart (4) in the Proposed Rules creates significant safety and liability  
concerns for the MECA cooperatives. Although the Proposed Rules specify that “failure of the  
control or inverter system for more than 30 seconds, resulting from loss of control or measurement  
signal, or loss of control power, must result in the DER entering an operational mode where no  
energy is exported across the point of common coupling to the distribution system,”2 it will be  
MECA cooperatives’ distribution system that bears the burden of the loss of the DER’s Power  
Control System. Therefore, the Proposed Rules put the monitoring and control over safety  
measures that will protect the MECA cooperatives’ distribution system entirely within the hands  
of a third party. This is not a suitable mechanism to create a timely and appropriate response that  
protects the MECA cooperatives’ distribution system and its reliability. Further, limiting the  
possible responses of the MECA cooperatives to protect “system safety and reliability” to the  
mechanisms provided in subdivisions (e) and (f) does not provide adequate flexibility for the  
MECA cooperatives to take the actions necessary to protect their distribution system in the event  
of excessive DER capacity exports.  
4.  
The Proposed Rules Adopt an Arbitrary Definition of “Business Days”.  
The Proposed Rules provide the following definition of “Business Days”  
“Business day” means Monday through Friday, starting at 12:00:00 a.m. and ending  
at 11:59:59 p.m., excluding the following holidays: New Year’s Day, Martin Luther  
King Jr. Day, Presidents Day, Memorial Day, Independence Day, Labor Day,  
Veterans Day, Thanksgiving Day, Christmas Eve, Christmas Day, and New Year’s  
Eve, Election Day, the day after Thanksgiving, electric utility holidays and any  
day that meets the criteria of catastrophic conditions as defined in R 460.702(f) in  
which electric service is interrupted for 10% or more of an electric utility’s  
2 Mich Admin Code, R 460.980(4)(e).  
5
customers. A list of electric utility holidays shall be provided in the electric  
utility’s interconnection procedures.  
This proposed definition is problematic for a number of reasons. First, there are references  
throughout the proposed rules where calendar days or business days have not been specified. See,  
e.g., Mich Admin Code, R 460.990. The Proposed Rules should be amended so that each reference  
to a “day” specifies whether it is a business day or a calendar day. Second, the electric service  
interruption standard does not reflect the reality of the MECA cooperatives’ system of business  
administration. MECA cooperatives tend to have smaller pool of customers than larger utilities,  
and those customers tend to be clustered in smaller geographic areas. It is much more likely for a  
weather event to result in a loss of a business day for MECA cooperative than it is for a larger  
utility like DTE. Particularly because electric service interruption days will likely only be  
measured in retrospect, this definition creates difficulties in tracking and administration for the  
Staff of MECA cooperatives. Third, even days with electric service outages for certain customers  
are days when the staff of the MECA cooperatives are still working. There is no differentiation in  
this proposed definition between days where staff and employees, or a majority of staff and  
employees, are unable to work because of circumstances beyond their control. The proposed  
definition is not a good measure of what a business day actually is. The MECA cooperatives  
recommend elimination of the electric service interruption clause altogether.  
5.  
It is Unclear How the Proposed Rules Should Be Applied to Alternative Energy  
Suppliers.  
While Alternative Energy Suppliers (“AES”) are included in the definition of “electric  
utility” under the Rules, an AES does not own distribution system infrastructure, and therefore it  
is unclear how the Proposed Rules should be applied. One alternative is that the AES is subject to  
the interconnection standards of the electric utility that the customer is interconnected to, however,  
6
this requires the AES to track and coordinate a variety of interconnection standards, again for  
facilities that it does not own, operate, or maintain. MECA recommends exempting AESs from  
the Proposed Rules and requiring that a customer coordinate an interconnection request directly  
with the interconnecting electric utility. This would eliminate extra administrative burdens on both  
the AES and the Commission. It would also streamline the interconnection process for the  
customer.  
6.  
MECA Cooperatives Support the Addition of Rule 56, Adding Flexibility to Tailor  
Studies of Interconnection Applications.  
As a collective of smaller electric utilities under the Rules, the MECA cooperatives  
appreciate the flexibility provided by the addition of Mich Admin Code, R 460.956, which allows  
for an alternative process to study interconnection applications different from the process  
described in the rules. MECA supports the addition of Rule 56.  
7.  
MECA Cooperatives Support the Addition of Rule 82(5)(d) and the Flexibility it  
Provides in Types of Studies of Applications.  
Similar to the previous comment, the MECA cooperatives are supportive of the added  
language in Mich Admin Code, R 460.982(5)(d). Expedited studies put additional administrative  
pressure on smaller utility providers such as the MECA cooperatives and the MECA cooperatives  
appreciate the flexibility to decline to provide expedited studies.  
Conclusion  
The MECA cooperatives appreciate this opportunity to provide additional comments,  
however, the current Proposed Rules do not provide the tools necessary to ensure a safe and  
reliable electric grid. In addition, there also remains a need for clarifications of certain rules. The  
MECA cooperatives respectfully urge the Commission to consider the comments above and revise  
the Proposed Rules accordingly.  
7
Respectfully submitted,  
Michigan Electric Cooperative Association  
Dated: June 27, 2022  
Richard J. Aaron (P35605)  
Dykema Gossett PLLC  
Capitol View Bldg.  
201 Townsend Street, Suite 900  
Lansing, Michigan 48933  
Telephone: (517) 374-9198  
8
STATE OF MICHIGAN  
MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own  
)
)
)
)
)
motion, to promulgate rules governing  
electric interconnection reconciliation of its  
power supply cost recovery and distributed  
generation, and rescind legacy  
Case No. U-20890  
interconnection and net metering rules.  
COMMENTS OF  
THE ECOLOGY CENTER  
THE ENVIRONMENTAL LAW & POLICY CENTER  
AND VOTE SOLAR  
June 27, 2022  
1
The Environmental Law and Policy Center, the Ecology Center and Vote Solar,  
(collectively, the Clean Energy Organizations, or “CEO”) timely file these comments on the draft  
set of rules titled Interconnection and Distributed Generation Standards (“MIXDG rules”)  
consistent with the Michigan Public Service Commission’s (“MPSC” or “Commission”) May 12,  
2022 Order. The CEO, alongside utilities and other stakeholders, participated in the working  
groups that informed Commission Staff’s initial draft of the rules. These working groups were  
open to any interested person. All participants were focused on providing information and  
perspectives that would help Commission Staff develop clear rules that provided for safe and  
reliable interconnection. These early discussions were helpful in identifying a broad spectrum of  
concerns for Staff to consider in developing a set of potential rules for the Commission to study.  
The Commission put a set of draft rules out for formal public comment on September 9, 2021,  
consistent with the Michigan Administrative Procedures Act (“Draft MIXDG rules”).  
The CEO submitted comments on the Draft MIXDG rules on November 1, 2021. The  
Commission issued an order responding to comments and approving a revised version of the  
MIXDG rules for final adoption on March 17, 2022 (“MIXDG rules”). On April 14, 2022, various  
monopoly utilities petitioned for rehearing of the Commission’s March 17 Order, arguing that  
untimely comments had been considered by the Commission.1 The CEO answered the petition on  
May 5, 2022. On May 12, 2022, the Commission agreed to provide a second public hearing on  
the MIXDG rules and, after engagement with the proper regulatory authorities, on May 26 the  
Commission issued an Order setting a comment deadline of 5:00 p.m. (Eastern time) on June 27,  
2022.  
1 It appears that commenter Sunrun timely submitted comments and a document Sunrun believed contained redlines,  
but in fact inadvertently provided a clean copy of the rules instead of the redline. When Staff noted that the redlines  
were not appearing in the document, Sunrun was notified, and the correct file was provided. (See May 12, 2022  
Order at 3).  
2
The CEO are generally supportive of the MIXDG rules as approved by the Commission on  
March 17, 2022. To be clear, no set of draft or final rules in this proceeding has reflected all of  
the CEO recommendations. Nor would the CEO necessarily expect that to be the case, given the  
diversity of perspective represented in the commenting parties. The CEO incorporate herein, and  
do not repeat, previous comments on the Draft MIXDG rules. Failure to address a particular aspect  
of the Draft MIXDG rules should not be construed as agreement, nor constitute waiver of any legal  
right to participate in any challenge to the rules.  
A. The proposed MIXDG rule is consistent with the Commission’s statutory authority  
under MCL 460.1173.  
In 2016, the Michigan legislature established a distributed generation program by passing  
Act 342, which amended Act 295 of 2008. Act 342 authorizes the Commission to promulgate  
rules “necessary to implement” the distributed generation program. MCL 460.1173(1). It also  
unambiguously directs the Commission to develop “statewide uniform interconnection  
requirements for all eligible electric generators.” MCL 460.1173(6)(a).  
(1) The time limits for approval of parallel operation in the MIXDG rules recognize  
reliability and safety complications. (MCL 460.1173(1)).  
Act 342 directs the Commission that:  
Any rules adopted regarding time limits for approval of parallel operation  
shall recognize reliability and safety complications including those arising  
from equipment saturation, use of multiple technologies, and proximity to  
synchronous motor loads.  
MCL 460.1173(1). “Parallel operation” is defined in the MIXDG rules as the operation, for longer  
than 100 milliseconds, of a DER while connected to the energized distribution system. See  
MIXDG rules Definitions at (y). This section of the statute applies specifically to “time limits for  
approval” of parallel operation. In other words, the legislature wanted to be sure that the  
3
Commission considered how reliability and safety complications impact the deadlines established  
in interconnection rules.  
Here, the Commission determined, based upon its own expertise and information provided  
in comments, that the portions of the MIXDG rules regarding time limits for approval of parallel  
operation recognize reliability and safety complications that are raised in the interconnection  
context. MCL 460.1173(1). The Commission explicitly acknowledged and acted upon comments  
from utilities recommending changing the term “days” to “business days,” excluding utility  
holidays from the definition of “business days,” and increasing the length of certain deadlines.  
(March 17, 2022 Order at 8-10). The Commission also recognized utility safety and reliability  
concerns with respect to time limits in the simplified track review process. In response to utility  
comments, the Commission expanded the timeline for utility specification of equipment an  
application from 10 business days to 20 business days. (March 17, 2022 Order at 22). With respect  
to inspection, testing, and commissioning, the Commission recognized DTE’s concerns that a  
longer timeframe was necessary to enable utilities to coordinate with an applicant and physically  
visit the project site. In recognition of DTE’s comments related to reliability and safety, the  
Commission modified the draft rules to provide additional time for larger projects. (March 17,  
2022 Order at 27). In recognition of potential reliability and safety complications, the Commission  
recognized the need for smaller utilities to have longer time frames. The Commission added a new  
rule providing an additional 10 business days for each timeline in the ruleset for electric utilities  
with less than 1,000,000 Michigan customers. (March 17, 2022 Order at 34).  
(2) The MIXDG rules are designed to protect electric utility workers and equipment  
and the general public. (MCL 460.1173(6)(a)).  
In addition to the general authority to promulgate rules necessary to implement the  
distributed generation program, the Commission has an affirmative duty to develop statewide  
4
uniform interconnection requirements. MCL 460.1173(6)(a). These statewide rules must be  
designed to “protect electric utility workers and equipment and the general public.” MCL  
460.1173(6)(a). The statute delegates this fact-finding exercise to the administrative and technical  
expertise of the Commission. The Commission’s finding that the MIXDG rules are designed to  
protect electric utility workers and equipment, as well as the general public, is based on its  
expertise. Slis v. State, 332 Mich. App. 312, 353, 956 N.W.2d 569, 592, appeal denied, 506 Mich.  
912, 948 N.W.2d 82 (2020) (“the principle of giving due deference to an agency with regard to  
fact-finding because of its expertise has become well established in our civil jurisprudence”);  
Travelers Ins. Co. v. Detroit Edison Co., 465 Mich. 185, 198, 631 N.W.2d 733 (2001)  
(“[A]dministrative agencies possess specialized and expert knowledge to address issues of a  
regulatory nature.”)  
The MIXDG rules reflect the growing use of energy storage in Michigan and the broad  
availability of power-limited export systems. The Midwest states of Illinois and Minnesota have  
interconnection rules that enable power-limited export systems.2 Indeed, to omit rules governing  
power-limited export would invite damage to utility equipment and potentially harm utility  
workers and the general public. Uniform statewide definitions and standards for energy storage  
protect utility workers and equipment and the general public by creating clarity, transparency, and  
predictability in the process. The Commission’s limited-export standards are consistent with the  
2019 Model Interconnection Rules from the Interstate Renewable Energy Council (“IREC”), a  
non-profit organization that has been instrumental in assisting several state utility commissions in  
2
Illinois Commerce Commission. Docket 20-0700. Final Order. May 25, 2022. Available at:  
https://www.icc.illinois.gov/docket/P2020-0700/documents/324414. See proposed rule in MN Pub. Util. Comm.,  
Dkts. E999/CI-16-521 & E999/CI-01-1023, In the Matter of Updating the Generic Standards for the Interconnection  
and Operation of Distributed Generation Facilities Established under Minn. Stat. § 216B.1611.  
5
rules that focus on distributed energy resource interconnection procedures. Relevant and  
responsive to concerns raised by utilities in their petition for rehearing, IREC provided a memo to  
Vote Solar explaining that the MIXDG rules do not raise safety and reliability concerns as claimed  
by the utilities. (See Attachment A, June 24, 2022 memo from Brian Lydic, Chief Regulatory  
Engineer, IREC to Vote Solar). IREC’s memo supports the Commission’s conclusion that the  
MIXDG rules are designed to “protect electric utility workers and equipment and the general  
public.” MCL 460.1173(6)(a).  
(3) The MIXDG rules provide an opportunity for utility testing and approval of  
interconnection consistent with Michigan law. (MCL 460.1173(6)(b)).  
Act 342 specifies that “Both of the following must be completed before equipment is  
operated in parallel with the distribution system of the utility: (i) Utility testing and approval of  
interconnection, including all metering. (ii) Execution of a parallel operating agreement.” (MCL  
460.1173(6)(b)). Rule 460.966 specifically allows for inspection, testing and commissioning of  
devices, and sets straightforward timeframes for completing those tasks.  
In its request for a rehearing, the utilities seemed to think that Rules 460.920 and 460.980  
foreclosed the utility’s “right” to test and approve all proposed interconnections. (Petition for  
Rehearing at 7). Rule 460.920 requires each utility to develop interconnection procedures that  
must be approved by the Commission. These procedures must include acceptable methods or  
standards for power-limited export DERs in compliance with allowances in Rule 460.980. Rule  
460.980 requires utility interconnection procedures to include “acceptable methods for power  
limited export DER so that the DER capacity considered by the electric utility for reviewing the  
interconnection application is only the amount capable of being exported.” Rule 460.980(4). Rule  
460.980(4)(e) allows DERs to use a system that has been certified to ensure that export of energy  
will stop when necessary to protect utility workers and equipment and the general public.  
6
The utilities appear to argue that this provision in the MIXDG rules, which allows the use  
of thoroughly tested and nationally certified devices, is inconsistent with the statutory requirement  
that utilities “test and approve” equipment before interconnection. The statute cannot reasonably  
be interpreted to mean that before any export-limiting equipment is interconnected, utilities are  
entitled to individually test and approve that specific piece of equipment.  
It would be unreasonable to construe the statute as directing the Commission to develop  
statewide interconnection requirements that prevented any member of the public from  
interconnecting until their specific piece of equipment had been inspected by the utility. It is  
perfectly reasonable to interpret the statute as allowing utilities to rely on certification of a device  
rather than individual testing. Certified devices have met “acceptable safety and reliability  
standards by a nationally recognized testing laboratory” in conformance with technical standards.  
(See MIXDG rules Definitions at (m)). These testing laboratories must be recognized by the  
accreditation program of the United States Department of Labor Occupational Safety and Health  
Administration. (See MIXDG rules Definitions at (u)). Furthermore, it is clear from the number  
of states who have incorporated certification into limited-export rules that national certification  
obviates the need for individualized testing of devices. (See also Attachment A).  
* * * * *  
The issues raised by the utilities in the petition for rehearing are meritless, and the  
Commission should not modify the MIDXG rules on the basis that they raise safety or reliability  
concerns.  
7
Respectfully submitted,  
_____________________  
Margrethe Kearney  
Environmental Law & Policy Center  
146 Monroe Center, Ste 422  
Grand Rapids, MI 49503  
T: (773) 726-8701  
F: (312) 795-3730  
mkearney@elpc.org  
Dated: June 27, 2022  
8
Case No. U-20890  
Comments of the CEO - Attachment A  
Date: June 27, 2022  
Page 1 of 11  
MEMORANDUM  
Date: June 24, 2022  
To: Vote Solar  
From: Brian Lydic, Chief Regulatory Engineer, Interstate Renewable Energy Council (IREC)  
This multi-part memorandum serves to address certain technical issues raised by DTE Electric Company’s  
and Consumers Energy Company’s (“the Petitioners”) Joint Petition for Rehearing of April 14, 20221  
(“the Petition”). The Petitioners raise a number of concerns regarding due process and unsafe or  
unreliable electrical conditions that could arise due to the filed Public Service Commission  
Interconnection and Distributed Generation Standards (“MIXDG”). Here, I address the safety and  
reliability concerns raised in the Petition’s section B, namely the general conclusion that:  
“The MIXDG rules conflict with the authorizing statutes by failing to consider, and ultimately creating  
safety and reliability concerns.”2  
The Petitioners focus on concerns around allowing certified Power Control Systems (“PCS”), the effects  
of inadvertent export (“IE”) on conductors and transformers (or distribution system equipment more  
generally), and the ramifications of fast track eligibility limits and certain screens being based on the  
limited-export value. This memo serves to refute the characterization of certain aspects of these  
arguments based on experience, standards and emerging best practices, and concludes that the MIXDG  
rules are in line with emerging best practices that maintain safety and reliability of the distribution  
system.  
I.  
Inadvertent export is an understood phenomenon supported by field applications and  
standards.  
IREC supports the allowance for limited-export systems as defined by R 460.980(4). This  
language is similar to that used in the new Illinois Part 466 interconnection rules3 (Section  
466.75) as well as that proposed by the Toolkit & Guidance for the Interconnection of  
Energy Storage & Solar-Plus-Storage4 (“BATRIES Toolkit”, Chapter III). Therefore, we believe  
it reflects innovation in best practice for the interconnection evaluation of Distributed  
Energy Resource (DER) systems that electronically limit export power. Limited-export  
systems including those using relays or Power Control Systems can introduce inadvertent  
export, which is export of power exceeding the “ongoing operating capacity”5 and for a  
limited duration, generally due to fluctuations in load-following behavior. While some  
utilities may not be currently familiar with the phenomenon, the use of systems that  
generate IE is supported by existing experience and standards.  
1 DTE Electric Company’s and Consumers Energy Company’s Joint Petition for Rehearing, Case No. U-20890, April  
14, 2022  
2 Petition for Rehearing, p. 12  
3 Title 83: Public Utilities Chapter I: Illinois Commerce Commission Subchapter c: Electric Utilities  
Part 466 Electric Interconnection of Distributed Energy Resources Facilities  
https://www.icc.illinois.gov/docket/P2020-0700/documents/324414/files/564658.pdf  
4 BATRIES Toolkit, p. 53 – 55, https://energystorageinterconnection.org/resources/batries-toolkit/  
5 As defined in R 460.901b  
Case No. U-20890  
Comments of the CEO - Attachment A  
Date: June 27, 2022  
Page 2 of 11  
a. PCS equipment has been used in HI, CA and elsewhere with no known safety or  
reliability issues.  
The California Public Utilities Commission first authorized changes to Rule 21 (the state’s  
interconnection procedures) in Decision 16-06-052 adopted on July 1, 2016 to allow for  
the use of PCS. These changes, including adoption of section Mm of the rules, were  
implemented through advice letter filings in 2016 (see, e.g., San Diego Gas & Electric  
Company Advice Letters 2959-E and 2959-E-A). Hawaii also began allowing the use of  
power controls systems in late 2015. See Hawaiian Electric Co., Rule 22. With around six  
years of field experience with these systems in the United States, no known safety or  
reliability issues have arisen due to IE. It is IREC’s understanding that similar equipment  
has been used elsewhere in the world (e.g., Europe) for even longer. Note that these  
types of systems have been “self-certified” by the manufacturers in the past before UL  
published a test procedure for PCS in 2019.  
b. The National Electrical Code provides for fire safety and allows for inadvertent export  
up to 30 seconds in duration.  
The National Electrical Code (“NEC”) 2020 edition, in section 705.13, permits the use of  
certified PCS to ensure equipment thermal limits are not exceeded. In doing so, the NEC  
does not include additional limitations on the number or frequency of inadvertent  
export events, nor does it include additional requirements for safety that are covered by  
certification. An example use case for the PCS is to limit currents from multiple DER  
units to maintain the current output of the total system within the capabilities of a  
conductor or bus to which they are all connected. This is a very similar use case to the  
export-limiting function also allowed by PCS addressed by R 460.980(4)(e), which must  
ensure that export is maintained within the distribution system equipment capabilities.  
c. The UL 1741 Certification Requirement Decision (“CRD”) for Power Control Systems  
supports the use of Power Control Systems inclusive of inadvertent export for NEC  
conductor loading and utility interactive export-limiting applications.  
The potential for use of certified equipment for PCS has been bolstered since UL  
published the CRD for PCS in March 2019. This testing protocol can be used today by  
manufacturers to verify compliance with their Nationally Recognized Testing Laboratory.  
These systems can work either for conductor protection in the NEC context, or for  
export limitation, or both. Both use cases would have the effect of controlling power at  
the point of common coupling to a set value. The CRD was developed with the input of  
utilities, safety experts and manufacturers to ensure safe operation. The BATRIES Toolkit  
notes some specific assurances provided by the multiple tests included in the CRD6:  
“To mitigate the potential for disruption, it mandates that the time the PCS takes to  
respond to inadvertent export, known as the open loop response time (OLRT), be  
measured through a series of load drops and step changes in generation. It requires that  
6 BATRIES Toolkit, p. 160 - 161  
Case No. U-20890  
Comments of the CEO - Attachment A  
Date: June 27, 2022  
Page 3 of 11  
the OLRT be no greater than 30 seconds (although manufacturers can—and do—support  
faster response times, in some cases to meet regulatory requirements).”  
“In addition to the OLRT, the CRD requires testing of abnormal conditions such as loss of  
control circuit power, loss of control signal, and loss of signal from sensors due to open  
circuit or short circuit. These conditions must be appropriately detected during both  
startup and normal operation. The PCS also checks for incorrect installation at startup.  
Some exceptions to these tests are provided if additional protections are put in place for  
the PCS. Power must be kept at or below the set limit during any of the abnormal  
conditions.”  
d. Conclusion.  
Power Control Systems and export-limiting devices more broadly have been used in DER  
systems for a number of years. Standards that support their safe use have been created,  
and innovative best practice defined in recent publications supports the inclusion of  
certified limited-export systems in interconnection rules. Many interconnection rules  
have not been updated in some time and can benefit from inclusion of concepts that  
support energy storage interconnection and the ability to control DER. The focus of  
states should be to implement these findings and standards, while continuing to learn  
from the updated interconnection rules as a process of continual adjustment.  
II.  
“Dangerous operation” is mischaracterized by the utilities.  
Despite the use of power-limiting devices and attendant inadvertent export being supported  
by standards, the Petitioners refer to IE as “dangerous operation” as in the following  
excerpt7:  
“The proposed rules effectively allow 32 seconds of dangerous operation until the project  
needs to come back into compliance. This short amount of time can cause a transformer to  
fail catastrophically (potentially including a fire) and seriously impact power quality to  
adjacent customers (potentially including appliance failures).”  
This broad characterization does not hold up upon review of conductor and transformer  
engineering standards. The following discussion references engineering standards to show  
that IE is not a dangerous condition for conductors or transformers.  
a. Inadvertent export is generally driven by changes in load, not nameplate ratings.  
It is important to note up front that the evaluation of export power is appropriate in the  
interconnection evaluation process, since the nameplate rating of a DER may not  
actually present itself at the DER terminals due to normal operation. For instance,  
multiple storage units may be connected in parallel to a residential load panel in order  
to increase the total kilowatt-hour capacity of the storage system. If these units are, for  
example, rated at a power of 5 kW each and 10 kWh, three units in parallel would have  
a nameplate rating of 15 kW and capacity of 30 kWh. However, if the customer is  
7 Petition for Rehearing, p. 8  
Case No. U-20890  
Comments of the CEO - Attachment A  
Date: June 27, 2022  
Page 4 of 11  
restricted from exporting any stored power and utilizes a PCS to manage the power  
output of the three storage units, such that they are generally non-exporting (with  
allowance for IE), then the total output of the combined storage system will only ever  
match the load at the house. If the maximum load of the house is 10 kW, then the  
maximum the total output of the storage system would ever be is 10 kW. Inadvertent  
export is generally driven by changes in load, so the maximum IE that would occur if all  
house load turned off at once would be 10 kW. Short of a failure of the certified PCS  
controls, the nameplate rating of 15 kW would never occur and would not present a  
reliability hazard to the distribution system.8 It should be noted that under distribution  
system fault conditions PCS or other export controls may not act in time to reduce fault  
currents. Utilities should continue to use rated fault current to evaluate protection  
impacts unless the export controls manufacturer provides test data proving that fault  
currents can be controlled.  
b. The amount of inadvertent export potential (maximum 200% of export limit) is not  
dangerous to conductors.  
The potential for distribution system safety and reliability impacts from IE events can be  
characterized by way of example. A possible, though unlikely, scenario for an individual  
IE event would be for a single system or group of systems to export 200% the current  
rating of the conductor. As described in the following example, this is not a safety or  
reliability concern as this is well within the capabilities of conductors.  
A conductor should be rated for at least the maximum load power, which we will call 1X.  
So, the circuit has a current-carrying capacity of no less than 1X, and a maximum load of  
1X. Assume that all load is served by a DER coupled with an energy storage system  
(“ESS”), such that either the generator or ESS (or in combination) can serve the whole  
load at any given time. Thus, the generator is sized for an output power of no less than  
1X, and the ESS is also sized no less than 1X. An export limit for the DER is set, using a  
PCS, at 1X to remain within the circuit rating (which would equate to a hosting capacity  
of around 330% of export capacity compared to minimum load, assuming minimum load  
is 30% of maximum). Note that the likelihood of being able to export at 1X is unlikely as  
other system constraints like steady-state voltage would likely limit the export to a  
lower value. Also note that the NEC requires overcurrent protection of the conductors  
monitored by the PCS, so they remain protected.  
In this example, in order to serve both the load as well as export up to the technical  
limit, the generator is sized at 2X and the ESS is also sized at 2X, for an aggregate  
nameplate rating of 4X (or 1,330% of minimum load). The ESS will not be discharging full  
power at the same time as the generator due to the lack of load, so at maximum the  
DER aggregate power is 2X (whether from either generation source alone or in concert).  
This also remains true if the ESS is charging, adding to the load. In this case the DER  
setpoint will depend on both the generator and ESS, and the combined output would  
remain 2X at maximum.  
8 The UL Certification Requirement Decision for Power Control Systems requires testing to ensure IE remains within  
limits for sudden increases in generation levels as well as for a drop in load.  
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Under a worst-case IE scenario, all 1X load would drop off instantaneously. This does not  
happen in the real world, as there is always some minimum load. The 2X steady-state  
operating level of the DER now flows through the 1X rated circuit until the control  
system brings the DER output down to 1X, back in line with the circuit’s capacity. See  
Figure 1 below showing the current flow at the start of the IE event. While the output of  
the control system changes more akin to exponential decay, for our consideration we  
can simplify it to a linear response over a duration of 30 seconds. We can then consider  
this to mean an average of 1.5X current for 30 seconds, or similarly 2X for 15 seconds.9  
Note that many inverter-based PCS will have time responses much less than 30 seconds.  
Emergency amperage ratings for conductors vary based on size, insulation and  
temperature, but typical examples are:  
•
Emergency/overload rating is at least 600% of the current rating for 30 seconds and  
at least 800% for 15 seconds.10,11  
•
Overload ratings for most conductors, including smaller insulated cables, are over  
300% for 100 seconds and over 1000% for 10 seconds.12  
Due to the ability of conductors to pass approximately 600% of rated current for 30  
seconds, the 150% worst-case current for 30 seconds or 200% for 15 seconds should not  
be a reliability issue and leaves a conservative safety margin. Many conductors can  
withstand at least 150% or 200% rated current for 15 minutes or more. Even in the  
unthinkable scenario that worst-case IE events were triggered repeatedly one after  
another 30 times in a row, the conductor would not be damaged. Again, this example is  
at a very high level of penetration, assuming all DER is oversized compared to load and  
utilizing a PCS. DER interconnecting at lower levels of penetration would be subject to  
further study according to the R 460.946 procedures (460.946(4)(b) would not pass  
applications that would cause any reverse power on the line section).  
Due to the diversity of loads and DER on any circuit, there is virtually no possibility that  
limited-export systems could inadvertently export all at the same time. Even so, the  
above example works similarly for a collection of diverse DER systems with worst-case  
inadvertent exports occurring at the same time, showing that thermal limits would not  
be exceeded in aggregate. See Figure 2 below showing current flow at the start of such  
an IE event.  
Another potential mode for IE occurrence would be due to sharp fluctuations in  
generation. While PV systems do not increase power from 0% to 100% over very short  
periods of time under normal operation, we will use that as a boundary scenario. For  
this example, we assume that a PV system is sized at 4X (4 times the maximum load and  
4 times the capacity of the circuit), and with a 1X export limit as in the example above.  
9 These simplifications are conservative, since the heating capability of overcurrent is dependent on the square of  
the current. E.g., for the 1.5X current case, the i2 would be assumed as 2.25 A2 for the full 30 seconds, rather than  
decreasing over time.  
10 Aluminum Electrical Conductor Handbook, Third Edition , The Aluminum Association (1989),  
https://www.aluminum.org/sites/default/files/AECD%20part1%20compressed.pdf.  
11 IEEE Std 242-2001 figure 9-17a.  
12 IEEE Std 242-2001 table 9-6.  
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Date: June 27, 2022  
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This assumes the same penetration levels as in the first example. We will assume load is  
at zero, although this is never the case. If generation jumps from 0 to 4X  
instantaneously, we can consider the simplified IE event to be an average of 2.5X (250%  
of the circuit rating) for 30 seconds or 4X (400% of the circuit rating) for 15 seconds. This  
remains within the overload ratings mentioned above.  
At a more practical level of penetration in today’s terms, say where DER meets 100% of  
minimum load and could potentially pass through the fast track screens, there is even  
less worry about thermal issues. If all load was fully offset by DER, minimum load would  
be zero. Therefore, if all DER systems utilized a PCS, the export limit would be 0. Again,  
assume maximum load is 1X and the circuit rating is 1X. In this case the DER would be  
operating at 1X, with no current exporting. If all load drops off, the IE event will have a  
maximum current of 1X, or average of 0.5X over 30 seconds, all completely within the  
normal rating of the circuit.  
Figure 1 – Single DER with 1X rated circuit (1X = 730A in this example), and 1X rated load  
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Figure 2 – Example feeder with multiple DER and 1X rated circuit (1X = 730A in this example) and 1X load  
c. Conclusion on conductor effects.  
Given the above analysis, I determine that the overloading of conductors due to IE  
events that the MIXDG rules would allow would not result in catastrophic damage to  
conductors.  
Case No. U-20890  
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Date: June 27, 2022  
Page 8 of 11  
d. The amount of inadvertent export potential is not catastrophic to transformers.  
Contrary to the language of the Petition13, overloading a transformer for a short period  
is not likely to result in fire except for very large overloads. The American National  
Standard ANSI C57.92-1981 IEEE Guide for Loading Mineral-Oil-Immersed Power  
Transformers Up to and Including 100 MVA with 55 °C or 65 °C Average Winding Rise  
gives recommendations for loading transformers based on loss of life due to aging of the  
winding insulation. This aging which occurs under normal use is a function of time and  
temperature, though it can be exacerbated by overloading. According to the standard,  
normal daily loss of life for a transformer is 0.0369% at an average ambient temperature  
of 30 °C (86 °F). Lower ambient temperatures should give higher loading capability with  
no effect on transformer lifetime. The actual loading capabilities are determined based  
on a hottest spot temperature value. As noted in the standard14:  
“Normal life expectancy will result from operating with a continuous hottest-spot  
conductor temperature of 110 °C (or equivalent variable temperature with 120 °C  
maximum) in any 24 h period.”  
“Transformers may be operated above 110 °C hottest-spot temperature for short periods  
provided they are operated for much longer periods at temperatures below 110 °C.”  
Transformer temperature rise requires some appreciable duration of loading to  
significantly raise the internal temperature, but is also dependent on cooling and  
ambient temperature. Table 3(d)15 in the standard gives the capability for normal and  
moderate sacrifice of life for 65 °C rise, self-cooled (OA) and water-cooled (OW)  
transformers with equivalent load before peak load equaling 100% of the nameplate  
rating. It would be a conservative assumption to use 100% preloading and then assume  
an IE event of 200% of the transformer rating. This would be akin to a DER system(s)  
exporting at its maximum technical interconnection limit (the transformer rating) all day  
long and then all load dropping off at once to create the IE event. Table 3(d) shows that  
a transformer under these preloading16 conditions can withstand 30 minutes of 200%  
overloading in a day to equate to a 0.25% loss of life, and the top oil temperature would  
reach 98 °C. Top oil temperature would need to approach 145 °C to create a risk of  
sudden ignition and explosion17. That would account for 60 IE events per day if the  
events were actually 30 seconds in duration and at the rating of the transformer for the  
duration, which is an unnecessarily conservative assumption per the discussion in  
section II.b of this memo. That level of loss of life equates to 162 hours over the 65,000  
hour normal expected lifetime of the transformer. This effect is far from a catastrophic  
fire.  
13 Petition for Rehearing, p. 8  
14 IEEE C57.92 at p. 39 - 40  
15 IEEE C57.92 at p. 22  
16 Including a 30 °C ambient temperature  
17 P.K. Sen et al., Transformer Overloading and Assessment of Loss-of-Life for Liquid-Filled Transformers Final  
Report, Power Systems Engineering Research Center, p. 15 (February 2011), https://pserc.wisc.edu/wp-  
content/uploads/sites/755/2018/08/T-25_Final-Report_Feb-2011.pdf  
Case No. U-20890  
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Date: June 27, 2022  
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e. Conclusion on transformer effects.  
Given the above analysis, I determine that the overloading of transformers due to IE  
events that the MIXDG rules would allow would not result in catastrophic damage to  
transformers.  
III.  
The BATRIES Toolkit provides learnings on power quality effects of inadvertent export and  
suggestions for eligibility limits and screening.  
Learnings from the BATRIES Toolkit note that power quality impacts of inadvertent export  
events are likely to be minimal especially for smaller systems, and those impacts can be  
screened for with the addition of an IE voltage change screen. Modeling and simulation  
conducted for the BATRIES project indicate that power quality effects of IE are likely to be  
minimal except for larger systems under certain circumstances. To screen for this effect, an  
IE voltage change screen was derived and large systems that would have an effect can be  
effectively screened regardless of eligibility limits being based on the limited-export power.  
a. Chapter V of the BATRIES Toolkit notes the potential worst-case conditions for power  
quality effects of inadvertent export.  
Chapter V of the BATRIES Toolkit describes modeling and simulation for urban and rural  
feeders and the penetrations at which coincident occurrences of IE could introduce  
power quality (voltage) issues. These coincident scenarios are worst-case rather than  
real-world. The key findings of this chapter state18:  
“These response times support the assertion that thermal impacts are unlikely to be a  
limiting factor for inadvertent export because both their level (110% maximum) and  
duration (typically 2-10 seconds) are below any known thresholds for concern.”  
Based on this modeling, a screen for voltage-based power quality interactions was  
devised and is presented in Chapter IV. It is presumed that this screen would catch  
thermal effects as well, as voltage impacts are likely to occur before thermal issues  
arise.19  
b. Chapter IV of the BATRIES Toolkit bases some screening or study on the limited-export  
value, and introduces a new inadvertent export screen to screen for voltage impacts  
of inadvertent export.  
The BATRIES Toolkit defines the term Export Capacity, which has a similar meaning to  
“ongoing operating capacity” of R 460.901(b). Chapter IV notes that it is reasonable to  
assess the steady-state export, and thus the limited-export value, in the penetration and  
transformer screens.20  
However, as noted by the BATRIES Toolkit21:  
18 BATRIES Toolkit, p. 92  
19 BATRIES Toolkit, p. 64  
20 BATRIES Toolkit, p. 62 – 66  
21 BATRIES Toolkit, p. 63  
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“The 15% screen is used as a proxy for reviewing voltage and other system effects. Any  
steady-state voltage rise due to reverse power flow would continue to be effectively  
evaluated under the 15% screen since the exported power that could cause reverse flow  
would still be accounted for. However, nonexporting DER capacity could also potentially  
introduce voltage changes due to inadvertent export events. As these short-term voltage  
effects would be dependent on only the non-exporting portion of the Nameplate Rating,  
the revisions to the 15% screen could mean that there is a possibility that these voltage  
changes would not be effectively screened. The non-exporting portion is the Nameplate  
Rating minus the Export Capacity.”  
Thus, an IE screen was devised to catch any possible voltage changes greater than 3%22,  
which is a conservative value based on IEEE 1547-2018 requirements of subclause  
7.2.2.23 Note that this screen considers load equal to the nameplate rating at the DER  
site to turn off at once. This is a conservative assumption. As noted in section II.a of this  
memo, the nameplate rating will not present itself at the DER terminals if site load is  
lower. The BATRIES Toolkit limits the application of this screen to systems where this  
conservative estimate of IE power is less than 250 kVA.  
The Toolkit notes24:  
“To limit the need to apply this screen to systems where there is little chance of voltage  
impact, the project team completed a review of the calculation for a large selection of  
feeders. No change lower than 298 kW triggered a calculation of more than 3% at the  
end of an “average” 12 kilovolts (kV) medium length feeder, and detailed calculations  
showed a maximum change of 368 kW. For a longer 4.2 kV feeder, the calculation was  
maintained within the limit up to 413 kW, with detailed calculations finding a maximum  
change of 574 kW. Therefore, it is reasonable to assume compliance without the need of  
running the calculation for systems with a non-exporting capacity below 250 kW.”  
While the limited applicability of this screen may allow it to be used in initial review  
screens, similar evaluations for power quality (e.g., evaluation of voltage change due to  
loss of generation) are typically only performed in supplemental review. Applying this  
screen should eliminate the instances where unintended voltage effects of IE are  
discovered in the field.  
c. Chapter IV of the BATRIES Toolkit bases eligibility limits on the export power value.  
As noted in the BATRIES Toolkit25:  
“The eligibility limit does not take the place of the screens and thus should only be used  
to sort out projects that are very unlikely to pass the screens.  
22 BATRIES Toolkit, p. 63 – 65  
23 IEEE Std 1547-2018 IEEE Standard for Interconnection and Interoperability of Distributed Energy Resources with  
Associated Electric Power Systems Interfaces, p. 61  
24 BATRIES Toolkit, p. 65  
25 BATRIES Toolkit, p. 61  
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Fast Track eligibility should be modified so that it is evaluated on the basis of the  
project’s Export Capacity and not the Nameplate Rating of the project.”  
d. Conclusion  
Taken together with all the Chapter IV screens, the eligibility limit based on the limited-  
export value would still allow proper screening of impacts from limited-export systems.  
While missing the inadvertent export screen, Michigan R 460 hews fairly closely to the  
concepts introduced by the BATRIES Toolkit. Some states (such as Illinois in its Rule 466) do  
not yet introduce the inadvertent export screen, but we encourage it be discussed by states  
innovating interconnection rules to be more suitable for storage systems.  
IV.  
Overall Conclusion  
As detailed in sections I – III of this memo, the Petitioners’ safety and reliability concerns  
around the allowance for certified Power Control Systems (PCS) to limit export, the effects  
of IE on conductors and transformers, and the ramifications of fast track eligibility limits and  
screens being based on the limited-export value appear to be unfounded. Given that the  
MIXDG rules generally follow emerging best practice, IREC encourages those rules to move  
toward implementation, even if some changes are made as a result of the rehearing. The  
Public Service Commission, utilities and stakeholders can rest assured that safety or  
reliability issues will not likely arise due to application of these rules.  
Sincerely,  
Brian Lydic, Chief Regulatory Engineer  
Interstate Renewable Energy Council  
brian@irecusa.org  
734-548-8664  
STATE OF MICHIGAN  
BEFORE THE MICHIGAN PUBLIC SERVICE COMMISSION  
In the matter, on the Commission’s own motion,  
to promulgate rules governing electric  
interconnection and distributed generation and  
)
)
)
Case U-20890  
to rescind legacy interconnection and net metering )  
rules.  
__________________________________________)  
)
COMMENTS OF THE MICHIGAN ELECTRIC AND GAS ASSOCIATION  
Pursuant to the Commission’s May 26, 2022 Order establishing a second public hearing for  
the administrative rules governing Michigan’s electric interconnection and distributed generation  
programs, the Michigan Electric and Gas Association1 (“MEGA” or “the Association”) submits  
these comments in response to the Commission’s request for public comment regarding the draft  
rules.  
I.  
Procedural History  
The Commission in its September 9, 2021 order provided a draft update to the Michigan  
Interconnection for Distributed Generation (MIXDG) rules, setting a public hearing for October  
20, 2021 and allowing for submission of written comments until November 1, 2021. On March 17,  
2022, the Commission adopted the rules, as revised, and referred the rules to the Michigan Office  
of Administrative Hearings and Rules and the Legislative Service Bureau for formal approval and  
transmission to the Joint Committee on Administrative Rules.  
On April 14, 2022, Consumers Energy Company (Consumers) and DTE Electric Company  
1
The MEGA member companies are investor-owned natural gas and electric utilities with fewer than 500,000  
customers in the state of Michigan, and include: Alpena Power, Citizens Gas Fuel Company, Indiana Michigan  
Power, Michigan Gas Utilities, Northern States Power Company – Wisconsin, SEMCO Energy Gas Company,  
Upper Michigan Energy Resources Corporation, and Upper Peninsula Power Company.  
1
(DTE Electric) (together, petitioners) filed a Joint Petition for rehearing of the Commission’s  
March 17, 2022 Order (Joint Petition) pursuant to Mich Admin Code, R 792.10437 (Rule 437).  
On May 4, 2022, Indiana Michigan Power Company (I&M), Michigan Electric and Gas  
Association (MEGA), and Michigan Electric Cooperative Association (MECA) filed answers to  
the Joint Petition for rehearing. On May 5, 2022, the Environmental Law and Policy Center,  
Ecology Center, and Vote Solar (together, the Clean Energy Organizations or CEOs) filed an  
answer to the Joint Petition.  
On May 12, 2022, the Commission granted the Joint Petition for rehearing and at its May 26,  
2022 hearing set the schedule for the public hearing and submission of written comments based  
on the draft rules included in the May 26, 2022 Order.  
II.  
Introductory Comments  
MEGA thanks the Commission for providing this additional opportunity for public comment  
on the proposed rules. As the Commission is aware, these rules have far-reaching effects on  
customer demand, interactions between utilities and their customers, and the safe, reliable  
operation of the grid.  
The Association supported the Joint Petition because its members agreed with certain concerns  
being expressed by the Joint Petitioners, particularly those related to safety. Further, because our  
members continue to evaluate their procedures for interconnecting customer-owned distributed  
generation systems, new issues have arisen that the Association members seek to raise for the  
Commission’s consideration. MEGA’s membership is comprised of smaller utilities, and these  
complex rules have required significant time to develop the draft procedures presented to the Staff  
Workgroup. Each Association member will continue to refine their individual proposals for  
submission once the final rules in this docket are adopted.  
2
The opportunity for all parties to review the final draft rules prior to submission to the Office  
of Administrative Hearings and Rules will benefit stakeholders later in the process as utilities  
develop their procedures for evaluating potential impacts of interconnecting customer-owned  
resources to the utility’s distribution system.  
MEGA members have expressed concerns that the changes being proposed by the draft rules  
may not adequately resolve certain safety and/or reliability issues that inherently exist with larger,  
complex customer-owned systems (despite the additional time afforded our members under  
proposed Rule 908). The Association’s members believe these matters are worthy of  
reconsideration by the Commission.  
MEGA will summarize its previous comments that remain applicable to the current draft rules  
(Section III), discuss new issues that have been identified by its members as they continue to  
review the rules to determine how they will be implemented (Section IV), and address specific  
rule comments under Section V.  
III.  
Summary of Previous MEGA Comments  
First and foremost, MEGA would like to thank the Commission for recognizing the significant  
impact the rules and processes contained therein have on utilities and the relationship they maintain  
with their customers, as the Association noted in its initial comments (MEGA Comments Pages 2-  
3). MEGA welcomes the addition of Rule 908 (460.908) that provides additional time for the  
smaller utilities to review and process their customers’ requests for interconnection while ensuring  
reliability and safety are maintained. While this additional time will be beneficial to the  
Association’s members, there are some remaining concerns regarding safety and reliability that  
are addressed below in Section IV.  
3
As noted in their previous comments (Page 10), MEGA members remain concerned about the  
costs of implementing the rules. Many of these rules will require additional investments that are  
not currently contemplated by the Association’s members, whether that’s potential information  
technology upgrades or additional staff required to implement the requirements and processes that  
are set forth in these rules. As an example, some of our utilities will have to create new systems to  
manage this complex process, while others will have to modify existing systems. In either case,  
the cost for establishing the new systems and upgrades will be assigned to and recovered from the  
member’s Michigan-based customers.  
MEGA is disappointed in the fee cap reductions for impact studies. In our proposed draft filings  
in the stakeholder workgroups, it was noted that our members will be seeking higher fee caps to  
ensure adequate cost recovery in their individual cases. MEGA did not lower the fee caps as  
adopted by the Commission in its final rules for the System Impact Study or Facilities Study to  
reflect that there will be actual costs that will exceed the proposed caps in the final rules.  
IV.  
Additional Comments Pursuant to Draft Rules Adopted May 26, 2022  
The revisions the Commission proposed in the new draft rules have generated additional  
concerns for MEGA members. Association members are concerned about safety and reliability,  
and some of the changes could have adverse impacts. The Joint Petition outlined several concerns  
that MEGA members share, as discussed below.  
MEGA agrees with the Joint Petitioners’ assessment of the rule promulgation authority granted  
to the Commission, the scope of which is further defined by MCL 460.1173. The statute’s clear  
focus on maintaining safety and reliability of the grid provides strong guidance that “Michigan  
law reserves to electric utilities the right to test and approve all proposed interconnections to their  
4
electrical systems.” (Joint Petitioners, Page 7). MEGA members have identified some potential  
issues for the consideration of the Commission.  
First, there has been an increase in the number of customers that are proposing to install more  
generation capacity than is currently allowed under the statute for each system level. These  
customers have typically purchased “turn-key” installations from an electrician or solar installation  
contractor and are relying on them to develop and submit the documentation that is required under  
the Rules. When the issue is raised by the utility during its review of the customer’s application,  
the customer’s electrician or solar installation contractor has attempted to utilize the inverter to  
limit the amount of the export to the utility’s distribution system to stay under the statutory  
cap. This is generally accomplished via programming of the inverter (in the field).  
These types of arrangements create both a safety and reliability issue because the inverter can  
be modified by the customer or its contractor AFTER the installation, inspection, and approval by  
the utility. This scenario creates a potential safety and or reliability concern without the utility’s  
knowledge. The utility is now tasked with inspecting numerous interconnections to ensure that the  
customer, developer, or third party has not altered the software or modified the system in a manner  
that adversely affects the safe and reliable operation of grid. Smaller utilities, like MEGA  
members, may not have the ability to inspect each the hardware or software settings for each  
interconnected inverter.  
Lastly, it has been the experience of MEGA members that some customers have modified and  
or added additional equipment that substantially alters the characteristics of their installation after  
inspection and approval by the utility. This scenario also presents potential safety and or system  
reliability concerns whenever the utility has not been afforded an opportunity to fully evaluate the  
customer’s modifications prospectively. Consistent with statute, MEGA members believe there is  
5
a strong need for requiring the customer to install disconnecting devices that provide the utility’s  
staff with the ability to visibly confirm all customer-owned sources of energy have been  
disconnected from the distribution system. This safety precaution helps to ensure the safety of  
utility workers and the general public.  
V.  
Specific Rule Comments  
Part 1. General Provisions  
Rule 460.1a(cc) Definitions; A-I and Rules 460.952 and 460.956 Alternative Process  
MEGA had previously expressed concern about the overlap between the Regional  
Transmission Operator (RTO) methodology where MEGA members provide consolidated  
Distribution Impact System reports that include components of the Feasibility, Impact and  
Facilities, Studies.  
The Association appreciates the Commission’s adopting in the draft rules an alternative  
process (R 460.952 and R 460.956) to create flexibility and reduce duplication of process with  
the RTO.  
Rules 460.901a(bb), 460.901a(gg), and 460.901b(x) Capacity Definitions  
The definition of Aggregated Capacity R 460.901(d) states “aggregated ongoing operating  
capacities of all DERs across multiple points of common coupling” which seems to run counter  
to the definition of “Generating Capacity” in 460.901(gg). MEGA suggests the Commission  
should clarify that this definition means the sum of total nameplate capacity for all DERs without  
the inclusion of export limiting technologies.  
The definition of “Generating Capacity” R 460.901(gg) also includes the language; “except  
that where this capacity is limited by any of the methods of limiting electrical export, generating  
6
capacity shall be the net capacity as limited though the use of such methods not including  
inadvertent export.” This language seems appropriate for the definition of “Export Capacity,” but  
we feel generation capacity should include the total nameplate capacity of a DER(s) so that  
utilities have full visibility into the assets being installed behind a single metering point. This  
would prevent developers from “hiding” capacity (i.e., a 20MW solar array with 15MW battery  
storage system appearing as 5MW to qualify for fast-track review).  
Rule 460.1b(s) Nameplate Capacity  
MEGA suggested that the Nameplate Rating should also include Ah and kWh ratings for  
Energy Storage. The Commission declined to modify the definition and instead added kWh (for  
storage) to the nameplate capacity description in R 460.930(2)(e).  
The Association appreciates the Commission’s action on this issue.  
Rule 460.908 Timelines for electric utilities serving fewer than 1,000,000 in-state customers.  
(Previous Rule 908 – Appointment of Experts)  
Regarding the former Rule 908, MEGA again appreciates the Commission’s efforts to  
streamline the rules and remove burdensome requirements and looks forward to continuing to  
work with Staff in this regard.  
Regarding the new Rule 908 granting additional time for smaller utilities to evaluate and  
work with their customers on interconnections, the Association members thank the Commission  
for recognizing the concerns expressed by the smaller utilities. We believe this extra time will be  
beneficial, particularly as the companies navigate through implementation of these new rules.  
Further, we believe the additional time will enable increase the ability of the smaller teams at  
each utility to evaluate interconnection applications and systems.  
7
Part 2. Interconnection Standards  
Rule 460.914 Transition non-study group, Rule 460.916 Legacy applications, Rule 460.918  
Transition batch study process, Rule 460.918(8)(b) Transition batch study process, Rule  
460.918(10) Transition batch study process, Rule 460.918(15) Transition batch study  
process  
While not specifically addressing Association concerns relating to the transition batch  
process, in removing the rules in their entirety, MEGA’s concerns have been addressed. The  
Association appreciates the Commission’s action on this issue to provide greater clarity to both  
utilities and customers.  
Rules 460.926 and 460.928 Initial fees and Fee and fee cap modifications  
While MEGA understands the benefits of set fees across the board for interconnections,  
MEGA disagrees with the Commission’s reductions imposed on the fee caps for the fast track,  
system impact study, and facilities study. Association members have experienced widely varying  
costs associated with studies in applications they have received thus far, as many members are  
contracting third parties to conduct these studies. Further, MEGA members remain concerned  
about cost-shifting from the cost-causer (applicant) to other ratepayers in the applicable customer  
class of the applicant.  
While MEGA appreciates that a waiver process has been included in the rules, members are  
concerned that a waiver process creates two issues. First, the Commission is arbitrarily capping  
fees from actual costs that are to be incurred by the utility to process the application. In our  
initial draft process documents submitted to staff in the stakeholder workgroup, we assume  
higher fees to be proposed by MEGA members to reflect that. Second, MEGA members believe  
that because cost recovery is limited to actual costs, caps are unnecessary.  
MEGA requests that, at a minimum, the Commission revert to the previous fees for the three  
above studies. Alternatively, the Commission could consider a process for study fees that sets a  
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deposit amount or requires the utility to provide a good-faith estimate that is later trued-up once  
all studies are completed. These trued-up costs would have to be paid prior to moving forward in  
the application process.  
This would provide transparency to the applicant on the potential costs for the studies, and  
ensure full cost recovery of the studies, preventing subsidization of the applicant by other  
ratepayers.  
Rule 460.942 Non-export track review  
Association members have expressed concern that the utility may not be informed of  
potential load offsets in these types of applications. Noting that the rule appears to give  
discretion to utility in setting some screening criteria, MEGA nonetheless suggest adding a  
requirement that, at a minimum, the project’s nameplate rating must be included in the  
application and further, that the utility retains the right to determine the load offset. These are  
critical specifications of the proposed system that should be included in every application so that  
the proposed system can be properly reviewed.  
Rule 460.944 Fast track applicability, Rule 460.946 Fast track; initial review  
MEGA has significant concerns with the inability to require additional screens being  
specifically allowed in the rules. MEGA members have concerns related to safety and reliability.  
With technology shifting at an increasingly rapid pace, the ability of utilities to respond to the  
changing dynamics of customer interconnect requests is an important facet of ensuring safety  
and reliability. Association members believe additional screens would assist in proper evaluation  
of some of the concerns outlined above, specifically related to situations where overbuilt systems  
are being applied for interconnect.  
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In addition, under Rule 460.944 Level 1 - 5 DERs may receive fast track approval and  
provide for “use of an energy storage device so the export of power meets the requirements of  
level 1, level 2, level 3, level 4 or level 5 as large as 5 MWac.” It remains unclear to MEGA  
members whether a DER larger than 5MW would qualify for fast-track review if energy storage  
or some other export limiting technology (that may have its own safety considerations that would  
need to be independently evaluated) is used to reduce the export capacity to 5MW or less.  
Rule 460.984 Modifications to the DER  
MEGA appreciates the Commission’s commitment to safety by revising the rules to remind  
applicants that they should proceed with material modifications pursuant to an executed  
Interconnection Agreement, as experience (noted above) has indicated that this is a growing  
problem and is generating concern amongst members. As noted earlier, the onus is on the utility  
to continually inspect equipment that is not utility-owned to ensure safety and reliability, and  
here, to ensure that customers are not violating their interconnection agreement.  
R 460.986 Insurance.  
MEGA appreciates the flexibility the rules provide to utilities to ensure that there are adequate  
insurance policies. While the Association believes this flexibility should extend to all Levels, the  
requirements for larger projects under Levels 3 – 5 are appreciated.  
R 460.988 Easements and rights-of-way.  
MEGA members have concerns that the requirement the utility obtain easements for line  
extensions to serve a DER customer is untenable. After reviewing and considering the proposed  
changes to Michigan’s Rule 460.988, which would require utilities to acquire easements at the  
request of private entity “applicants” for tie-ins from generating facilities to the larger electric  
“grid” (“interconnections”), but also requires the applicants to pay for the “cost” of such  
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acquisitions, MEGA members have identified the following four concerns and considerations  
that MEGA members would like the Commission to consider with regard to the proposed Rule  
changes:  
Condemnation Rights and Responsibilities  
A potentially significant concern for utilities regarding the proposed change to Rule 460.988  
and the new requirement that utilities “provide and obtain” easements and rights-of-way for  
interconnections is that utilities might be required to exercise their condemnation powers to  
acquire such easements, and in doing so, might be subject to successful objections from property  
owners during the condemnation process that might ultimately prevent utilities from acquiring  
the easements needed for the interconnections. In Michigan, electric utilities fall under the  
Uniform Condemnation Procedures Act (UCPA) (PA 87 of 1980). If a property owner raises an  
objection during condemnation to a private utility’s need or necessity for a proposed taking of  
property (in this case, an easement), and if the taking is not pursuant to a Certificate of Public  
Convenience and Necessity, the trial court is given broad discretion to determine whether the  
requisite “need” exists for the taking. This presents an opportunity for the trial court to scrutinize  
the route designated for the line in question, and the location of the easement to be acquired. If  
the trial court determines that an alternative route for the line (and thus an alternative location for  
the easement) exists and would be preferable/less burdensome/more reasonable, the court could  
sustain the property owner’s objection to the condemnation, which would prevent the utility from  
acquiring the easement through condemnation.  
This is of concern to utilities because, in cases of interconnections, the utility would not have  
the opportunity to choose the location of the generating facilities, and therefore the line route for  
the tie-in (that would necessarily run between the generating facility and the utility’s  
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substation/tie-in point) would be generally predetermined by the applicant requesting the  
interconnection – not the utility. This would leave utilities in the unfortunate position of  
defending a line route or siting decision in a condemnation of an easement for the  
interconnection which the utility did not choose and likely will not have an opportunity to vet. If  
the applicant chooses a non-ideal location for the generating facility, property owners whose land  
is condemned for easements for the interconnection may be successful in challenging the line  
route and the need for the easements being condemned, and the utility would be unable to  
acquire the easement through condemnation.  
Not only does the possibility of a successful objection in this regard put the utility in the  
unfortunate position of defending siting decisions which it did not make, but it also creates the  
opportunity for utilities to ultimately be unable to fulfill their obligation under Rule 460.988 to  
acquire the easements needed for an interconnection. It also raises the question of who will incur  
the costs of an unsuccessful condemnation, given that the utility will initially incur those costs  
but Rule 460.988 could be interpreted as only requiring the interconnection applicant to  
reimburse the utility for the costs of successfully acquiring the easements for the interconnection  
– and not necessarily for the costs of an unsuccessful attempt to acquire the necessary easements.  
Cost Recovery and Transparency  
Utilities are also concerned that the “costs” of obtaining easements under Rule 460.988,  
which the applicant is required to pay, are not defined. Utilities will presumably be required to  
initially incur all of the substantial costs of acquiring/attempting to acquire the easements for the  
interconnection (including legal and court fees, costs of personnel to negotiate acquisitions, title  
and survey costs and the actual acquisition costs) and to seek reimbursement from the applicant.  
However, since the “costs” to be reimbursed do not appear to be defined under the Rules, utilities  
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may be required to expend additional sums to establish that they are entitled to reimbursement  
from the applicants for all the substantial costs incurred by the utilities in obtaining/attempting to  
obtain the easements for the interconnection. If all expenses incurred by the utility on pursuing  
the needed easements are not recouped by the utility from the applicants, there is the possibility  
that the utility’s rate base will have to absorb the additional costs.  
Utilities might also be concerned that their ability to successfully acquire easements outside  
of condemnation (through informal negotiations with property owners either before or during  
condemnation proceedings) may be hindered by the fact that the utility is not ultimately  
responsible for the costs of the acquisition. Because the applicant is ultimately responsible for  
the costs of the easement acquisitions, the applicant may seek to restrict the utility’s ability to  
informally resolve acquisitions by limiting the compensation that the utility is authorized to offer  
property owners to resolve the easement acquisition.  
Assignment of Acquired Easements and Liability Concerns  
Another concern of utilities is that their ability to assign the easements back to the applicants  
after the easements are acquired may be restricted if the easements are acquired through  
condemnation. Property owners who are aware that the utility is only exercising its powers of  
eminent domain to acquire easements for the applicant’s interconnection may object to the taking  
during the condemnation by arguing that the taking is essentially an impermissible taking for a  
private purpose if the utility intends to assign the easement to a private entity (the applicant)  
immediately following its acquisition. To avoid this potentially successful objection, utilities  
may be forced to maintain their ownership of the easements for the interconnection that are  
acquired through condemnation, even though the utility may not own or operate any of the tie-in  
facilities that will occupy the easement.  
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Unfortunately, ownership of the interconnection easements may subject the utilities to  
additional liabilities and obligations in regard to maintaining the easements. In particular,  
easement holders are required to maintain their easement areas in a safe condition, Morrow v  
Boldt, 203 Mich App 324, 330; 512 NW2d 83, 86 (1994). If utilities are precluded from  
assigning the easements to the applicants in order to avoid a successful objection to the taking if  
the easements are acquired by condemnation, then this ongoing maintenance obligation would  
fall upon utilities in regard to interconnection easements, and utilities would be forced to incur  
ongoing costs and liabilities regarding their maintenance of the easements. These costs would  
ultimately be borne by the ratepayers of the utility, essentially subsidizing a private entities’  
assets with no benefit to the ratepayers.  
Timing of Acquisition  
Utilities are tasked under the proposed rules to perform several tasks on behalf of the  
customer/applicant, including acquiring necessary easements for the project Acquisition of  
easements, depending on the nature and need of easement necessary for the project may result in  
timing issues with the customer’s/applicant’s application. Utilities may have difficulties in  
securing these easements delaying a project (outlined above). Smaller utilities have limited  
resources (which the Commission has recognized by affording additional time for processing  
applications in proposed R 460.908), but easements could result in additional time and cost that  
affect other areas of the utility service. Utilities must remain focused on their core mission to  
deliver safe and reliable service to all customers. Easement acquisition may have elements  
outside the utility’s control that delay interconnection and or could impact core utility services if  
staffing resources need to be reallocated to meet deadlines in the rules.  
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VI.  
Conclusion  
MEGA appreciates the Commission’s willingness to reopen the comments in the docket for  
these rules and appreciates the opportunity to provide additional feedback on the changes made.  
The Association again thanks the Commission for additional time to work with applicants on these  
agreements.  
The Association asks the Commission to consider its comments, particularly relating to control  
of equipment, safety, and reliability as well as the fee structure and easements outlined above.  
Sincerely,  
Dated: June 27, 2022  
Daniel Dundas  
President  
Michigan Electric and Gas Association  
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;