(a) (b) (c) (d) 13-Month Average Balance Historical Projected Line Test Year Ending Test Year Ending No. Description Source 12/31/16 9/30/2019

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1 Projected Rate Base Schedule: B1 For the 13-Month Average Period Ending 9/30/2019 Witness: M. A. Suchta ($000) Page: 1 of 1 (a) (b) (c) (d) 13-Month Average Balance Historical Projected Line Test Year Ending Test Year Ending No. Description Source 12/31/16 9/30/ Plant in Service Exh A-12, Sch B2, L6 4,364,098 5,401,455 2 Plant Held for Future Use Exh A-12, Sch B2, L Construction Work in Progress Exh A-12, Sch B2, L8 191,186 97,252 4 Total Utility Plant 4,555,284 5,498,706 5 Less: Depreciation Reserve Exh A-12, Sch B3, L7 2,103,032 2,248,221 6 Net Utility Plant 2,452,252 3,250,486 7 Net Capital Lease Property Exh A-12, Sch B4.1, L Gas Stored Underground - non current Exh A-12, Sch B4.1, L7 33,251 35,303 9 Total Utility Property and Plant Line 6 + Line 7 + Line 8 2,485,503 3,285, Less: Capital Lease Obligations Exh A-12, Sch B4.1, L Net Plant Line 9 + Line 10 2,485,503 3,285, Allowance for Working Capital Exh A-12, Sch B4, L47 910, , Total Projected Rate Base Line 11 + Line 12 3,395,937 4,278,568

2 Projected Utility Plant Schedule: B2 For the 13-Month Average Period Ending 9/30/2019 Witness: M. A. Suchta ($000) Page: 1 of 1 (a) (b) (c) (d) 13-Month Average Balance MPSC Historical Projected Line Account Utility Plant Utility Plant No. Description Source 12/31/16 9/30/ Plant in service 101 4,285,898 5,401,455 2 Plant purchased or sold Experimental plant unclassified Plant leased to others Completed construction not classified ,200-6 Plant in Service 4,364,098 5,401,455 7 Plant held for future use Construction work in progress ,186 97,252 9 Gas Stored Underground - non current ,251 35, Total Projected Utility Plant 4,588,535 5,534,009

3 Projected Accumulated Provision for Depreciation Schedule: B3 For the 13-Month Average Period Ending 9/30/2019 Witness: M. A. Suchta ($000) Page: 1 of 1 (a) (b) (c) 13-Month Average Balance Historical Projected Depreciation Depreciation Line Reserve Reserve No. Description 12/31/16 9/30/ Intangible Plant 35,475 37,052 2 Production Plant Storage 158, ,584 4 Transmission 272, ,595 5 Distribution 1,566,397 1,668,617 6 General Plant 70,371 72,373 7 Total Projected Depreciation Reserve 2,103,032 2,248,221

4 Projected Working Capital Schedule: B4 For the 13-Month Average Period Ending 9/30/2019 Witness: M. A. Suchta ($000) Page: 1 of 1 (a) (b) (c) 13-Month Average Balance Historical Projected Line Test Year Ending Test Year Ending No. Description 12/31/16 9/30/2019 ASSETS Other Property and Investments 1 Investment in Blue Lake 12,408 13,491 2 Grantors Trust 18,802 19,513 Current and Accrued Assets 3 Cash and Special Deposits Temporary Cash Investments Notes Receivable 3,221 3,512 6 Customer Accounts Receivable 147, ,384 7 Other Accounts Receivable 18,463 26,060 8 Less: Uncollectibles (16,494) (14,888) 9 I/C Notes Receivable 9, I/C Accounts Receivable 18,393 24, Materials and Supplies 19,130 18, Gas In Underground Storage 56,353 46, Prepayments 18,186 24, GCC Deferred Asset 50,066 46, Unbilled Revenue 63,831 65, Other Current Assets 6,631 3, Total Current Assets 395, ,724 Deferred Debits 18 Unamortized Loss on Reacquired Debt 20,997 16, Vector Pipeline Lease 54,788 43, Prepaid Pensions 511, , Regulatory Assets - Environmental 27,832 22, Prepaid OPEB 172, , Regulatory Assets - CTA 3,690 (0) 24 Regulatory Assets - Demolition Fees 144 (0) 25 Other Deferred Debits 2,709 2, Total Deferred Debits 794, , Total Assets 1,220,895 1,359,238 STOCKHOLDERS' EQUITY AND LIABILITIES Current/Accrued Liabilities 28 Accounts Payable 141, , I/C Accounts Payable 23,230 44, Other Taxes Payable 3,907 5, Income Taxes Payable 9,150 2, Interest Payable 14,747 18, Inventory Equalization 32,118 27, Non-MGP Environmental Reserve - Current 1, Other Current Liabilities 27,590 27, Total Current Liabilities 253, ,343 Deferred Credits and Reserves 37 Provision for Injuries and Damages 7,785 8, Non-MGP Environmental Reserve 1,744 2, MGP Environmental Insurance Recoveries Regulatory Liability - FAS Regulatory Liability - Negative Pension 41,283 11, Reg Liability-Other Post Empl Benefits (OPEB) - 35, Postretirement Benefits 0-44 Other Deferred Credits 6,491 14, Total Deferred Credits 57,302 72, Total Liabilities 310, , Net Working Capital Requirement 910, ,780 SOURCE: Exh. A-12, Sch. B4.1, Column (f)

5 Projected Average Balance Sheet with Classifications - Assets Schedule: B4.1 For the 13-Month Average Period Ending 9/30/2019 Witness: M. A. Suchta ($000) Page: 1 of 2 (a) (b) (c) (d) (e) (f) Investor Supplied Funds Balance Sheet Line Adjusted Investor Working No. Description Total Supplied Utility Plant Non-Utility Capital ASSETS Property, Plant and Equipment 1 Plant In Service 5,401,455-5,401, Plant Held for Future Use Construction Work In Progress 97,252-97, Accumulated Depreciation/Depletion (2,248,221) - (2,248,221) Net Utility Plant 3,250,486-3,250, Net Property Under Capital Leases Gas Stored Underground - non current 35,303-35, Other Property and Investments 8 Non-Utility Property 2, ,011-9 Less: Depr Res (1,176) - - (1,176) - 10 Investment in Subsidiaries Investment in Blue Lake 13, , Grantors Trust 19, , Other Investments 2, , Total Other Property and Investments 35, ,967 33,004 Current and Accrued Assets 15 Cash and Special Deposits Temporary Cash Investments Notes Receivable 3, , Customer Accounts Receivable 195, , Other Accounts Receivable 26, , Less: Uncollectibles (14,888) (14,888) 21 I/C Notes Receivable I/C Accounts Receivable 24, , Materials and Supplies 18, , Gas In Underground Storage 46, , Prepayments 24, , GCC Deferred Asset 46, , Unbilled Revenue 65, , GCR Undercollection UETM - Current Other Current Assets 3, , Total Current Assets 441, ,724 Deferred Debits 32 Unamortized Debt Expenses 6,862 6, Unamortized Loss on Reacquired Debt 16, , Vector Pipeline Lease 43, , Prepaid Pensions 542, , Regulatory Assets - Minimum Pension Liability (0) (0) 37 Regulatory Assets - Environmental 22, , Regulatory Assets - CTA (0) (0) 39 Regulatory Assets - Demolition Fees (0) (0) 40 Prepaid OPEB 256, , Accumulated Deferred Income Taxes 202, , Misc Deferred Debit - Tax Related 40,845 40, Revenue Decoupling Mechanism Other Deferred Debits 2, , Total Deferred Debits 1,134, , , Total Assets and Other Debits 4,897, ,728 3,285,789 2,967 1,359,238

6 Projected Average Balance Sheet with Classifications - Liabilities Schedule: B4.1 For the 13-Month Average Period Ending 9/30/2019 Witness: M. A. Suchta ($000) Page: 2 of 2 (a) (b) (c) (d) (e) (f) Investor Supplied Funds Line Description Adjusted Total Investor Supplied Utility Plant Non-Utility Balance Sheet Working Capital STOCKHOLDERS' EQUITY AND LIABILITIES Capitalization 47 Common Equity 1,615,679 1,615, Preferred Stock Long-Term Debt 1,498,492 1,498, Total Capitalization 3,114,171 3,114, Long-Term Lease Obligations Current/Accrued Liabilities 52 Short-Term Debt 177, , Accounts Payable 167, , I/C Accounts Payable 44, , I/C Notes Payable - Parent I/C Notes Payable - Other Affiliates 8,571 8, Customer Deposits 10,415 10, Other Taxes Payable 5, , Income Taxes Payable 2, , Interest Payable 18, , Inventory Equalization 27, , GCR Overcollection MGP Environmental Reserve - Current Non-MGP Environmental Reserve - Current Other Current Liabilities 27, , Total Current Liabilities 491, , ,343 Deferred Credits and Reserves 67 Provision for Injuries and Damages 8, , Asset Retirement Obligation Accumulated Deferred ITC Accumulated Deferred JDITC 1,325 1, Accumulated Deferred Income Taxes 1,218,947 1,218, Misc Deferred Credit - MBT MGP Environmental Reserve Non-MGP Environmental Reserve 2, , MGP Environmental Insurance Recoveries Regulatory Liability - FAS 109 Plant Refundable Inc Tax Regulatory Liability - FAS Regulatory Liability - Negative Pension 11, , Regulatory Liability - Energy Optimization Reg Liability RDM Reg Liability-Other Post Empl Benefits (OPEB) 35, , Postretirement Benefits Other Deferred Credits 14, , Total Deferred Credits 1,292,388 1,220, , Total Stockholders' Equity and Liabilities 4,897,723 4,531, , Net Rate Base Totals (Assets vs. Liabilities) - (4,281,535) 3,285,789 2, ,780 SOURCE: Exh. A-12, Sch. B4.2

7 Historical and Projected 13-Month Average Balance Sheet - Assets Schedule: B4.2 For the 13-Month Average Period Ending 9/30/2019 Witness: T. M. Uzenski ($000) Page: 1 of 2 (a) (b) (c) (d) Line No. Description 13-Month Average Balance Historical Test Period 12/31/2016 Change Projected Test Period 9/30/2019 ASSETS Property, Plant and Equipment 1 Plant In Service 4,364,098 1,037,357 5,401,455 2 Plant Held for Future Use Construction Work In Progress 191,186 (93,935) 97,252 4 Accumulated Depreciation/Depletion (2,103,032) (145,188) (2,248,221) 5 Net Utility Plant 2,452, ,234 3,250,486 6 Net Property Under Capital Leases Gas Stored Underground - non current 33,251 2,052 35,303 Other Property and Investments 8 Non-Utility Property 2,011-2,011 9 Less: Depr Res (1,008) (168) (1,176) 10 Investment in Subsidiaries Investment in Blue Lake 12,408 1,083 13, Grantors Trust 18, , Other Investments 2, , Total Other Property and Investments 34,319 1,652 35,971 Current and Accrued Assets 15 Cash and Special Deposits Temporary Cash Investments Notes Receivable 3, , Customer Accounts Receivable 147,550 47, , Other Accounts Receivable 18,463 7,598 26, Less: Uncollectibles (16,494) 1,606 (14,888) 21 I/C Notes Receivable 9,494 (9,494) 0 22 I/C Accounts Receivable 18,393 6,486 24, Materials and Supplies 19,130 (135) 18, Gas In Underground Storage 56,353 (9,539) 46, Prepayments 18,186 6,419 24, GCC Deferred Asset 50,066 (4,000) 46, Unbilled Revenue 63,831 1,634 65, GCR Undercollection UETM - Current Other Current Assets 6,631 (2,743) 3, Total Current Assets 395,273 46, ,724 Deferred Debits 32 Unamortized Debt Expenses 5,278 1,584 6, Unamortized Loss on Reacquired Debt 20,997 (4,359) 16, Vector Pipeline Lease 54,788 (10,815) 43, Prepaid Pensions 511,637 30, , Regulatory Assets - Minimum Pension Liability (0) (0) (0) 37 Regulatory Assets - Environmental 27,832 (4,959) 22, Regulatory Assets - CTA 3,690 (3,690) (0) 39 Regulatory Assets - Demolition Fees 144 (144) (0) 40 Prepaid OPEB 172,615 83, , Accumulated Deferred Income Taxes 161,290 40, , Misc Deferred Debit - Tax Related 53,333 (12,488) 40, Revenue Decoupling Mechanism Other Deferred Debits 2,709 (290) 2, Total Deferred Debits 1,014, ,926 1,134, Total Assets and Other Debits 3,929, ,314 4,897,723

8 Michigan Consolidated Gas Company Exhibit: A-12 Historical and Projected 13-Month Average Balance Sheet - Liabilities Schedule: B4.2 For the 13-Month Average Period Ending 9/30/2019 Witness: T. M. Uzenski ($000) Page: 2 of 2 Line No. (a) (b) (c) (d) 13-Month Average Balance Historical Test Period Projected Test Description 12/31/2016 Change Period 9/30/2019 STOCKHOLDERS' EQUITY AND LIABILITIES Capitalization 47 Common Equity 1,332, ,638 1,615, Preferred Stock Long-Term Debt 1,134, ,387 1,498, Total Capitalization 2,466, ,025 3,114, Long-Term Lease Obligations Current/Accrued Liabilities 52 Short-Term Debt 111,772 66, , Accounts Payable 141,310 25, , I/C Accounts Payable 23,230 21,673 44, I/C Notes Payable - Parent 1,231 (1,231) - 56 I/C Notes Payable - Other Affiliates 28,720 (20,149) 8, Customer Deposits 10, , Other Taxes Payable 3,907 1,196 5, Income Taxes Payable 9,150 (6,307) 2, Interest Payable 14,747 4,253 18, Inventory Equalization 32,118 (4,603) 27, GCR Overcollection MGP Environmental Reserve - Current Non-MGP Environmental Reserve - Current 1,109 (664) Other Current Liabilities 27,590 (316) 27, Total Current Liabilities 405,179 85, ,163 Deferred Credits and Reserves 67 Provision for Injuries and Damages 7, , Asset Retirement Obligation Accumulated Deferred ITC Accumulated Deferred JDITC 3,806 (2,481) 1, Accumulated Deferred Income Taxes 980, ,803 1,218, Misc Deferred Credit - MBT MGP Environmental Reserve Non-MGP Environmental Reserve 1, , MGP Environmental Insurance Recoveries Regulatory Liability - FAS 109 Plant Refundable Inc Tax 16,831 (16,831) 0 77 Regulatory Liability - FAS Regulatory Liability - Negative Pension 41,283 (29,754) 11, Regulatory Liability - Energy Optimization (0) 0-80 Reg Liability RDM Reg Liability-Other Post Empl Benefits (OPEB) - 35,706 35, Postretirement Benefits 0 (0) - 83 Other Deferred Credits 6,491 7,688 14, Total Deferred Credits 1,058, ,305 1,292, Total Stockholders' Equity and Liabilities 3,929, ,314 4,897, Net Rate Base Totals (Assets vs. Liabilities) (0) 0 -

9 13-Month Average Common Equity Reconciliation Schedule: B4.3 Balances Between Periods Ending 12/31/2016 and 9/30/2019 Witness: T. M. Uzenski ($000) Page: 1 of 1 (a) (b) (c) (d) (e) (f) Line No. Year Month Net Income Dividend Equity Infusion/ Rate Relief Ending Common Equity Balance Prior Month Bal. + Sum (col c. thru f) December 1,438,816 1/ January 39,506 (26,036) - 1,452,286 3 February 28, ,480,426 4 March 27, ,507,429 5 April 7,138 (26,036) - 1,488,531 6 May 2, ,491,224 7 June (5,120) - - 1,486,104 8 July (7,006) (26,036) - 1,453,062 9 August (5,998) - - 1,447, September (5,259) - - 1,441, October 5,230 (26,036) - 1,420, November 19, ,440, December 36, ,476, CY Activity 141,893 (104,144) January 40,124 (28,125) - 1,488, February 33, ,522, March 24, ,547, April 8,662 (28,125) - 1,527, May (1,590) - - 1,526, June (8,136) - - 1,518, July (8,521) (28,125) - 1,481, August (8,846) - - 1,472, September (6,769) - - 1,465, October 3,326 (28,125) 4,331 1,445, November 16,619-4,331 1,466, December 33,410-94,331 1,594, CY Activity 127,150 (112,500) 102, January 39,448 (30,000) 4,331 1,607, February 33,388-4,331 1,645, March 24,307-4,331 1,674, April 7,395 (30,000) 4,331 1,656, May (2,841) - 4,331 1,657, June (9,194) - 4,331 1,652, July (9,540) (30,000) 104,331 1,717, August (9,775) - 4,331 1,712, September (8,618) - 4,331 1,707, Jan-Oct 2017 Activity 64,569 (90,000) 138, For the 13-Month Average Period Ending 9/30/2019 1,615,679 2/ 1/ Adjusted year-end historical balance per Exhibit A-2 B4.2 2/ Also refer to Exh. A-12, Sch. B4.2, Col (c), line 47

10 Capital Expenditures Exhibit Index Schedule: B5 Witness: A. D. Sandberg Page: 1 of 2 Capital Expenditures Exhibit Index Exhibit No. Title Witness (Hyperlinked) Test Period Capital Expenditures A-12 B5 Capital Expenditures by Plant Type A. D. Sandberg A-12 B5.1 Capital Expenditures - Routine, Other Capital Projects and Infrastructure Recovery Mechanism A. D. Sandberg A-12 B5.2 Infrastructure Recovery Mechanism Capital J. M. Harris

11 Capital Expenditures by Plant Type Schedule: B5 ($000) Witness: A. D. Sandberg Page: 2 of 2 (a) (b) (c) (d) (e) (f) (g) (h) (i) Capital Expenditures Last Rate Case Projected Test Approved Spending Actual Spending 3/ Historical Projected Bridge Year Year Plan U Test Year U Line 12 mos. ended 12 mos. ending 9 Mo. ending 21 mos. ending 12 mos. ending 12 mos. ended 12 mos. ended No. Description 12/31/ /31/ /30/ /30/ /30/2019 Reference 10/31/ /31/ Distribution Plant 2 Mains $ 126,166 $ 178,337 $ 150,076 $ 328,413 $ 93,914 $ 135,941 $ 187,730 3 Services 97,287 92,383 82, ,840 68,700 92,040 96,400 4 Meter Purchases 9,636 9,759 8,162 17,921 10,367 10,338 9,079 5 Sales & Use Tax Settlement 1/ - (12,291) - (12,291) - - (13,417) 6 Total Distribution Plant $ 233,089 $ 268,189 $ 240,694 $ 508,883 $ 172,981 $ 238,319 $ 279,791 7 Transmission Plant 8 Mains 2/ 120,352 $ 119,088 $ 25,246 $ 144,333 $ 11,750 $ 124,338 $ 148,986 9 Sales & Use Tax Settlement 1/ - (4,597) - (4,597) - - (4,472) 10 Total Transmission Plant $ 120,352 $ 114,491 $ 25,246 $ 139,736 $ 11,750 $ 124,338 $ 144, Underground Storage Plant $ 39,642 $ 18,704 $ 21,803 $ 40,508 $ 21,499 $ 17,890 $ 19, General Plant 13 Structures and Improvements $ 7,106 $ 5,853 $ 9,675 $ 15,528 $ 10,650 $ 3,117 $ 8, Transportation Vehicles and Equipment 11,283 13,198 9,797 22,995 10,221 8,014 10, Tools and Equipment 1,573 1,290 2,025 3,315 2,169 1,190 1, Communication and Control Equipment 2,294 2,058 1,623 3,681 2,185 2,442 2, Computers and Related Equipment 9,534 5,393 6,391 11,783 5,880 3,122 10, Total General Plant $ 31,790 $ 27,791 $ 29,511 $ 57,301 $ 31,106 17,885 32, Total Capital Expenditures $ 424,873 $ 429,175 $ 317,254 $ 746,429 $ 237,336 $ 398,432 $ 477, Overlay - Impact of New Accounting (ASU 715) 4/ - - 8,495 8,495 12, Total Capital Expenditures $ 424,873 $ 429,175 $ 325,749 $ 754,924 $ 250,134 $ 398,432 $ 477,118 1/ Sales and Use Tax Settlement, Line No. 5 and 9, column c is sponsored by Witness Wisniewski. 2/ River Rouge incident insurance proceeds of $2.0 million received in 2017 is reflected in Transmission Plant - Mains, Line No. 8, column c. 3/ Column (i) Actual Spending Test Year U reflects 10 months of actual capital expenditures for November 2016 through August 2017 and 2 months of forecasted capital expenditures for September 2017 through October / New Accounting ASU 715, Line No. 20 sponsored by Witness Uzenski.

12 Capital Expenditures - Routine, Other Capital Projects Schedule: B5.1 and Infrastructure Recovery Mechanism Witness: A. D. Sandberg ($000) Page: 1 of 2 (a) (b) (c) (d) (e) (f) (g) (h) (i) Capital Expenditures Last Rate Case Projected Test Approved Spending Actual Spending 5/ Five Year Historical Projected Bridge Year Year Plan U Test Year U Line Average 12 mos. ended 12 mos. ending 9 Mo. ending 21 mos. ending 12 mos. ending 12 mos. ended 12 mos. ended No. Description /31/ /31/ /30/ /30/ /30/ /31/ /31/2017 Routine 1 Distribution Plant 1/ $ 61,830 $ 65,760 $ 68,426 $ 68,859 $ 137,284 $ 82,613 $ 74,569 $ 68,891 2 Transmission Plant 1/ 2/ 7,185 11,694 2,765 4,106 6,871 5,023 6,211 4,925 3 Storage Plant 18,099 19,024 17,717 21,803 39,520 21,499 16,765 17,630 4 General Plant 19,730 31,790 27,791 29,511 57,301 31,106 17,885 32,904 5 Total - Routine $ 106,844 $ 128,269 $ 116,698 $ 124,279 $ 240,977 $ 140,241 $ 115,429 $ 124,350 Other Capital Projects 6 New Market Attachments $ 27,756 $ 34,967 $ 26,947 $ 61,914 $ 36,908 $ 28,946 $ 36,403 7 Advanced Metering Infrastructure 21,679 9,293 15,266 24,558 5,089 17,489 14,651 8 NEXUS 93,490 91,032 9, , , ,485 9 Belle River Compression 20, ,125 2, Gordie Howe International Bridge 3/ 606 3, , , Milford Junction Loop 4,046 7, ,023-2,900 7, Revenue Protection 4,271 3,053 4,291 7,344 5,713 4,724 3, Total - Other Capital Projects $ 172,467 $ 150,706 $ 56,753 $ 207,459 $ 48,688 $ 159,659 $ 183, Total - Routine and Other Capital Projects $ 300,736 $ 267,405 $ 181,031 $ 448,436 $ 188,928 $ 275,088 $ 307,642 Infrastructure Recovery Mechanism 4/ 15 Pipeline Integrity $ 11,121 $ 12,770 $ 11,123 $ 23,893 $ 6,708 $ 10,752 $ 14, Main Renewal Program 86, , , ,200 33,900 89, , MMO MAC Initiative - - 5,775 5,775 1, Meter Move-Out Program 26,693 25,500 17,625 43,125 5,875 22,700 23, Total Infrastructure Recovery Mechanism $ 124,137 $ 161,770 $ 136,223 $ 297,993 $ 48,408 $ 123,344 $ 169, Total Capital Expenditures $ 424,873 $ 429,175 $ 317,254 $ 746,429 $ 237,336 $ 398,432 $ 477, Overlay - Impact of New Accounting (ASU 715) 6/ - - 8,495 8,495 12, Total Capital Expenditures $ 424,873 $ 429,175 $ 325,749 $ 754,924 $ 250,134 $ 398,432 $ 477,118 1/ Sales and Use Tax Settlement included in Line No. 1 and Line No. 2, column (d). Sales and Use Tax Settlement is sponsored by Witness Wisniewski. 2/ River Rouge incident insurance proceeds of $2.0 million received in 2017 is reflected in Routine - Transmission Plant, Line No. 2, column (d). 3/ Gordie Howe International Bridge project capital expenditures, Line No. 10 reflect costs incurred by DTE Gas net of MDOT reimbursement of $5.3 million. Reimbursement of $3.2 million expected through period ending 9/30/2018. Reimbursement of $2.1 million expected through Test Period ending 9/30/ / Infrastructure Recovery Mechanism for Line No. 15, 16, 17, 18 and 19 excludes IRM expenditures beginning January 1, / Column (i) Actual Spending Test Year U reflects 10 months of actual capital expenditures for November 2016 through August 2017 and 2 months of forecasted capital expenditures for September 2017 through October / New Accounting ASU 715, Line No. 21 is sponsored by Witness Uzenski.

13 Capital Expenditures - Routine, Other Capital Projects Schedule: B5.1 and Infrastructure Recovery Mechanism Witness: A. D. Sandberg ($000) Page: 2 of 2 (a) (b) (c) (d) (e) (f) (g) Capital Expenditures Projected Test Five Year Historical Projected Bridge Year Year Line Average 12 mos. ended 12 mos. ending 9 Mo. ending 21 mos. ending 12 mos. ending No. Description /31/ /31/ /30/ /30/ /30/2019 Routine Capital Requirements Distribution Plant 1 Main Renewals $ 2,741 $ 2,353 $ 5,062 $ 2,918 $ 7,980 $ 3,028 2 Public Improvements 10,275 12,061 13,621 9,296 22,916 10,804 3 Service Abandonments 6,045 6,665 6,943 6,059 13,002 6,553 4 Service Alterations 8,321 9,330 11,347 8,872 20,219 9,198 5 Service Renewals 12,786 10,435 12,267 9,184 21,451 12,651 6 System Reliability 7,328 11,303 16,915 19,616 36,531 23,939 7 Cathodic Protection 3,700 3,570 4,051 3,975 8,026 4,882 8 Communications & Control - Meters 10,177 9,636 9,759 8,162 17,921 10,367 9 Permits and Other Adjustments ,528 1, Sales & Use Tax Settlement 1/ - - (12,291) - (12,291) - 11 Total Distribution Plant $ 61,830 $ 65,760 $ 68,426 $ 68,859 $ 137,284 $ 82,613 Transmission Plant 12 Transmission 2/ 3/ $ 7,185 $ 11,694 $ 7,362 $ 4,106 $ 11,468 $ 5, Sales & Use Tax Settlement 1/ - - (4,597) - (4,597) - 14 Total Transmission Plant $ 7,185 $ 11,694 $ 2,765 $ 4,106 $ 6,871 $ 5,023 Storage Plant 15 Gas Storage $ 4,974 $ 5,779 $ 5,869 $ 6,286 $ 12,155 $ 4, Environmental Projects - Storage Compression - Storage 12,674 12,831 11,251 15,128 26,379 16, Total Storage Plant $ 18,099 $ 19,024 $ 17,717 $ 21,803 $ 39,520 $ 21,499 General Plant 19 Structures and Improvements $ 3,322 $ 7,106 $ 5,853 $ 9,675 $ 15,528 $ 10, Transportation Vehicles and Equipment 8,469 11,283 13,198 9,797 22,995 10, Tools and Equipment 1,172 1,573 1,290 2,025 3,315 2, Communications and Control Equipment 2,192 2,294 2,058 1,623 3,681 2, Computers and Related Equipment 4,576 9,534 5,393 6,391 11,783 5, Total General Plant $ 19,730 $ 31,790 $ 27,791 $ 29,511 $ 57,301 $ 31, Total Routine Capital Requirements $ 106,844 $ 128,269 $ 116,698 $ 124,279 $ 240,977 $ 140,241

14 Infrastructure Recovery Mechanism Capital Schedule: B5.2 Expenditures Witness: J. M. Harris ($000) Page: 1 of 1 (a) (b) (c) (d) (e) (f) (g) (h) Line No. Description Pipeline Integrity $ 12,770 $ 14,830 $ 11,120 $ 11,120 $ 11,120 $ 11,120 $ 11,120 2 Modified Main Replacement Program 123, , , , , , ,600 3 MMO MAC Initiative - 7,700 20,300 20,300 20,300 20,300 20,300 4 Meter Move-Out Program 25,500 23,500 22,700 22,700 22,700 22,700 22,700 5 Total Infrastructure Recovery Mechanism $ 161,770 $ 181,630 $ 221,620 $ 245,120 $ 286,720 $ 286,720 $ 286,720 3/ Infrastructure Recovery Mechanism for years 2017 and 2018 are included in base rates. New IRM surcharge to begin January 1, 2019 through 2023.

15 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 1 of 26 Category: Capital Exhibit: Highest Cost Top 25 Project Detail Exhibit A-12, Schedule B5.3 page: 2 of 26 Tab No. 2 Chelsea 150 PSIG System Supply Routine Distribution Plant System Reliability page: 3 of 26 Tab No. 3 Fort St. Main Replacement Routine Distribution Plant System Reliability page: 4 of 26 Tab No. 4 Farm Tap Upgrades Routine Distribution Plant System Reliability page: 5 of 26 Tab No. 5 Muskegon 50 PSIG System Supply Routine Distribution Plant System Reliability page: 6 of 26 Tab No. 6 Gaylord AEP Interconnect Routine Transmission Plant Transmission page: 7 of 26 Tab No. 7 Six Lakes A Header Integrity Routine Storage Plant Gas Storage page: 8 of 26 Tab No. 8 Six Lakes A Header Well Drilling Routine Storage Plant Gas Storage page: 9 of 26 Tab No. 9 Six Lakes Heater Installation Routine Storage Plant Compression page: 10 of 26 Tab No. 10 BRM Unit #4 Engine Rebuild Routine Storage Plant Compression page: 11 of 26 Tab No. 11 Lynch - Asset Preservation Routine General Plant Structures and Improvements page: 12 of 26 Tab No. 12 Astro Voice Replacement System Routine General Plant Computers and Related Equipment page: 13 of 26 Tab No. 13 Ford Central Energy Plant Other Capital Projects New Market Attachments page: 14 of 26 Tab No. 14 Arauco Flakeboard America Other Capital Projects New Market Attachments page: 15 of 26 Tab No. 15 Nexus Other Capital Projects NEXUS page: 16 of 26 Tab No. 16 Gordie Howe International Bridge Other Capital Projects GHIB page: 17 of 26 Tab No. 17 Milford Junction Loop Other Capital Projects Milford Junction Loop page: 18 of 26 Tab No. 18 Northeast Beltline 24" ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity page: 19 of 26 Tab No. 19 Sparta-Muskegon 16" ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity page: 20 of 26 Tab No. 20 Loreed Ludington 16" ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity page: 21 of 26 Tab No. 21 Gaylord 8" ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity page: 22 of 26 Tab No. 22 Mackinaw 8" ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity page: 23 of 26 Tab No. 23 Rogers City 8" ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity page: 24 of 26 Tab No. 24 S. Suburban 30" ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity page: 25 of 26 Tab No. 25 Lincoln Traverse City 10" Pipe Replacement Infrastructure Recovery Mechanism Pipeline Integrity page: 26 of 26 Tab No. 26 Loreed Ludington 16" Tie Line ILI Expansion Infrastructure Recovery Mechanism Pipeline Integrity

16 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 2 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule Cost: Funding from Others: Available Studies: Chelsea 150 PSIG System Supply Customer growth in the Chelsea area has resulted in near minimum pressures on the Chelsea 100 psig distribution system on peak winter days. Routine Distribution Plant - System Reliability Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 1 Replace approximately 3.5 miles of 8" psig steel main with 12" 150 psig steel main on Dexter Chelsea Road from the PEPL Chelsea Gate Station in Lima Twp. to the district regulator at Railroad and Taylor Lane in Chelsea. Formally uprate the existing 100 psig mains to the west of Railroad and Taylor Lane in Chelsea and abandon the 150 to 100 psig district located at the PEPL Chelsea Gate Station. Installation of these facilities maintain the pressure on the 150 psig system above minimums needed to feed the local 60 psig grid systems in the Chelsea area and support the ongoing general growth in customers in the area. In addition, the psig district regulator at the PEPL Chelsea Gate Station can be abandoned providing a more reliable supply to the Chelsea area. Major Project Milestones: Completion Date: Engineering Design 10/1/2017 Permitting 9/5/2017 Land Acquisition 9/5/2017 Materials Procurement 8/31/2017 Construction Phase I /31/2017 Construction Phase II /31/2018 Commissioning 10/1/2018 In Service 11/1/2018 Project Cost Breakdown Total Project Cost Labor (Internal) $229,391 $116,045 $113,346 $0 Material $842,799 $426,357 $416,442 $0 Contract Services $6,397,563 $3,236,414 $3,161,149 $0 Overheads $520,247 $263,184 $257,063 $0 Contingency $510,000 $258,000 $252,000 $0 AFUDC $0 $0 $0 $0 Total $8,500,000 $4,300,000 $4,200,000 $0 The 100 psig system feeds numerous district regulators supplying the 60 psig distribution system for the Chelsea area. The graph above shows the recorded end pressure to the inlet of a 60 psig district regulator in the Chelsea area. With a 55 psig minimum inlet pressure to the 60 psig district regulator, the outlet pressures will fall below normal operating pressures for the 60 psig system that delivers gas directly to the customers in the area. Map/Location:

17 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 3 of 26 Project: Drivers: Category: Line Number: Scope: Fort St. Main Replacement 1) The Fort Street main cannot operate at a pressure suitable to supply the new 60 psig systems currently being installed to replace existing 2 and 10 psig cast iron systems in Detroit. 2) The Fort Street main is a mechanically joined 22" steel pipe installed in 1940 that is in poor condition, and it is difficult to repair in urban environment. 3) Planned street and sidewalk upgrades in downtown Detroit will make replacement in the future more costly. Routine Distribution Plant - System Reliability Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 1 Replace approximately 4000 feet of 22" 50 psig 1940 mechanically joined steel pipe with 150 psig design 16" FBE coated catholically protected steel pipe. 2) Tie over existing district and secondary regulators to the new 150 psig design system that will operate at 50 psig are included in the project. Benefits: 1) Replacement of the Fort Street main will allow supply of the new 60 psig systems that are being installed to replace 2 and 10 psig cast iron mains on the east side of downtown Detroit. 2) Replacement of this main will minimize potential for costly leak repair on mechanically joined " 50 psig main. 3) Replacement at this time will help avoid planned upgrades of sidewalks and streets that result in high restoration costs. Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Major Project Milestones: Engineering Design Permitting Materials Procurement Construction Phase I Construction Phase II Commissioning In Service Project Cost Breakdown (millions) Completion Date: 5/1/2018 4/1/2018 4/1/ /31/ /31/ /1/ /1/2019 Total Project Cost Labor (Internal) $246,000 $0 $123,000 $123,000 Material $591,800 $0 $295,900 $295,900 Contract Services $5,304,000 $0 $2,652,000 $2,652,000 Overheads $304,000 $0 $152,000 $152,000 Contingency $430,000 $0 $215,000 $215,000 AFUDC $168,000 $0 $84,000 $84,000 Total $7,043,800 $0 $3,521,900 $3,521,900

18 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 4 of 26 Project: Drivers: Category: Line Number: Scope: Farm Tap Upgrades New Gas Safety Code requirements effective March 24, 2017 require DTE Gas to perform inspections on single customer farm taps supplied from Transmission systems once every three years. Routine Distribution Plant - System Reliability Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 1 Specifically per the new code requirement, single customer Farm taps must be inspected and tested at least once every 3 calendar years, with intervals not exceeding 39 months, to determine the following: - That it is in good mechanical condition, - That it is adequate from the standpoint of capacity and reliability of operation for the service in which it is employed, - That it is properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation, and - That it is set to control or relieve at the correct pressure. In order to comply with the new inspection rule, DTE Gas has reviewed typical designs of the 600 single customer farm taps currently operating in our system and determined that some facility modifications will be required to complete the inspections. These modifications will be completed over 3 years period. Approximately 50% (300 units) of the farm taps are expected to require upgrades. 10 percent of the existing single customer farm taps (60 units) will require replacement due to corrosion and/or operational issues. Approximately 20% (120 units) will be removed by installing new main when limited amounts of new main is required to eliminate single customer farm taps. Another 20% (120 units) are acceptable for inspection as they are and will require no work. The following table shows the potential units and costs for the various methods of preparing for the required 3-year inspection of the existing 600 single customer farm taps: Resolution Method % Units $/Unit Total ($ mil) Replacement: 10% 60 $ 33, Upgrade: 50% 300 $ 11, Farm Tap removals: 20% 120 $ 18, No work required: 20% 120 $ % 600 $ 12, Benefits: Timing: Cost: Funding from Others: Available Studies: Map/Location: This project allows DTE Gas to meet new code requirements regarding single customer farm taps that went into effect in March In addition, existing single customer farm taps will be updated as needed to minimizing risk of operational issues. The following table shows the potential units and costs for the various methods of preparing for the requires 3-year inspection of the existing 600 single customer farm taps based on the total estimated cost and the months available by year to complete work: Project Cost Breakdown (millions) Year Units per Year $/yr millions Totals Total Project Cost Labor (Internal) $1,103,040 $54,000 $524,520 $524,520 Material $919,200 $45,000 $437,100 $437,100 Contract Services $3,676,800 $180,000 $1,748,400 $1,748,400 Overheads $428,960 $21,000 $203,980 $203,980 Contingency $372,000 $0 $186,000 $186,000 AFUDC $0 $0 $0 $0 Total $6,500,000 $300,000 $3,100,000 $3,100,000 These 600 single customer farm taps are located throughout Greater Michigan (outside of the Southeastern Michigan area).

19 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 5 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map: Muskegon 50 PSIG System Supply Due to customer growth and limited high pressure supplies, the 50 and 10 pisg systems in Norton Shores (Muskegon area) have been experiencing below minimum pressures on winter peak day. Routine Distribution Plant - System Reliability Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 1 Install 15,000 of 8 steel 145 psig main from Ellis & Sheridan to Grand Haven & Mt. Garfield and a new psig district regulator at Grand Haven & Mt. Garfield in Install 7,000 feet of 6 plastic 50psig main on Mt. Garfield from Grand Haven to Martin, a new psig district regulator at Martin & Mt. Garfield, and 10,000 feet of 8 plastic 10 psig main on Mt. Garfield from Martin to Henry then north on Henry up to Porter in Increased system reliability and peak day pressures above minimum on the Norton Shores 50 and 10 psig systems. Major Project Milestones: Engineering Design Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: Phase 1 (2018) Phase 2 (2019) 1/31/2018 1/31/2019 3/31/2018 3/31/2019 6/30/2018 6/30/ /1/ /1/ /31/ /31/ /1/ /1/2019 Total Project Cost Labor (Internal) $102,551 $0 $59,372 $43,180 Material $376,781 $0 $218,136 $158,645 Contract Services $2,860,087 $0 $1,655,840 $1,204,247 Overheads $232,581 $0 $134,652 $97,929 Contingency $228,000 $0 $132,000 $96,000 AFUDC $0 $0 $0 $0 Total $3,800,000 $0 $2,200,000 $1,600,000

20 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 6 of 26 Project: Drivers: Category: Line Number: Scope: Gaylord AEP Interconnect DTE Gas is currently under a transportation agreement for 50,000 Dth/Day with Great Lakes Gas Transmission (Great Lakes) to deliver gas to DTE s Gaylord and Alpena markets. Based on the current rates implemented by Great Lakes, supply from the 20 AEP has been determined to be a cost effective alternative that will reduce cost to DTE Gas customers. Routine Transmission Plant - Transmission Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 2 Tie-in to the 20" Kalkaska AEP dry header to the 8" Gaylord Line and construct a receipt meter station located near 110 Old State Road in Gaylord. In 2015, DTE Gas installed the new tap on the 8" Gaylord Line along with an isolation valve and approximately 1,200' of 12" pipe. The final 1,000' of 12" pipe, the tap of the 20" Kalkaska Dry Header and the receipt meter station consisting of filter separator, heater, regulation, monitoring & measurement equipment & odorization are being installed in Benefits: This would create an alternate supply source from the dry header, replacing transportation volumes provided by the current Great Lakes agreement. Alternative supply from this new AEP interconnect would cost less to serve the Gaylord/Alpena system than using supply from Great Lakes, please see table below for cost reduction, as discussed in Witness R. Lawshe testimony, Case No: U-18152: Construction Schedule: Cost: Funding from Others: Fabrication of the piping began in Big Rapids in August 2017 and the site is expected to be complete and ready for service in October Major Project Milestones: Engineering Design Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 02/01/17 04/01/17 06/30/17 10/23/17 10/31/17 11/01/17 Total Project Cost Labor (Internal) $444,333 $403,067 $41,267 $0 Material $922,719 $922,719 $0 $0 Contract Services $1,366,472 $1,162,727 $203,745 $0 Overheads $206,045 $196,057 $9,988 $0 Contingency $0 $0 $0 $0 AFUDC $54,982 $54,982 $0 $0 Total $2,994,551 $2,739,551 $255,000 $0 Available Studies: Map/Location:

21 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 7 of 26 Project: Drivers: Six Lakes A Header Integrity The existing Six Lakes gathering pipe was exposed to high CO2 gas back in the 1990's and has a history of containing produced water and sediment on the bottom of the pipe and has over fifty individual well connections. The new gathering pipe will be capable of running smart pigs to assess corrosion, and cleaning pigs to remove water and sediment, and will reduce the number of individual well connections by 60%, which reduces the risk of 3rd party damage to the gathering pipe. Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Routine Storage Plant - Storage Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 3 Multiyear project from 2015 to 2017 that includes replacement of existing Six Lakes A header with new "piggable" pipe and removal of less efficient vertical wells and replacing them with horizontal wells drilled from well pads Phase I - Installation of 1.5 miles of new piggable 12" gathering pipe, run from a new well pad #1 to existing well pad #4, installation of launcher at well pad #1 and receiver at well pad #4, and drilling of two new horizontal wells off of well pad #1. Abandon existing pipe Phase II - Installation of 2.2 miles of new piggable 16" gathering pipe, run from well pad #4 to the north side of the Six Lakes Compressor Station. Installation of launcher on well pad #4 and connecting the new to the existing receiver at the plant. Abandon existing pipe Phase III - Installation of 2.1 miles of new piggable 10" gathering pipe, run from a new well pad #9 to existing well pad #10. Installation of launcher on well pad #9 and receiver on well pad #10. Abandon existing pipe. Improves integrity of the Six Lakes Storage Field Major Project Milestones 2015 Phase I In Service 2016 Phase II In Service 2017 Phase III: Engineering Design Permitting Materials Procurement Construction Phase In Service Project Cost Breakdown Completion Date: 12/18/2015 9/6/2016 6/1/2017 7/15/2017 8/10/2017 9/20/2017 9/25/2017 Total Project Cost Labor (Internal) $303,291 $303,291 $0 $0 Material $772,030 $772,030 $0 $0 Contract Services $2,558,972 $2,558,972 $0 $0 Overheads $180,368 $180,368 $0 $0 Contingency $0 $0 $0 $0 AFUDC $138,339 $138,339 $0 $0 Total $3,953,000 $3,953,000 $0 $0

22 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 8 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Six Lakes A Header Well Drilling The existing Six Lakes gathering pipe was exposed to high CO2 gas back in the 1990's and has a history of containing produced water and sediment on the bottom of the pipe and has over fifty individual well connections. The Six Lakes A Header Integrity project completed in 2017 will be capable of running smart pigs to assess corrosion, and cleaning pigs to remove water and sediment, and will reduce the number of individual well connections by 60%, which reduces the risk of 3rd party damage to the gathering pipe. The new piggable gathering line requires drilling of two new horizontal wells to maintain westside field deliverability. Routine Storage Plant - Storage Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 3 Construct wellpad near existing well #82A. Drive conductor casings. Drill and set surface casings. Directionally drill and set production casings in the top of the Stray B sandstone. Directonally drill the open hole sections. Connect wells to gathering pipe, log wells for base line assessments, complete wells and put into service. Restore wellpad. The 2018 Six Lakes Storage Field well drilling project will replace seven vertical wells with two horizontal wells to maintain westside field deliverability. Major Project Milestones: Engineering Design Permitting Construction Commissioning In Service Project Cost Breakdown Completion Date: 2/1/2018 4/1/2018 6/11/2018 7/11/2018 8/1/2018 Total Project Cost Labor (Internal) $225,000 $0 $225,000 $0 Material $605,036 $0 $605,036 $0 Contract Services $1,172,072 $0 $1,172,072 $0 Overheads $316,051 $0 $316,051 $0 Contingency $0 $0 $0 $0 AFUDC $113,000 $0 $113,000 $0 Total $2,431,159 $0 $2,431,159 $0

23 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 9 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Six Lakes A Heater Installation Systems Planning indicates there's a 445 MMcf/d deficiency for April Minimum Day design injection obligations, which puts DTE Gas customers at risk of curtailment. Installation of the Heaters significantly increases Taggart's injectability by allowing wells that would otherwise be shut-in, due to freezing potential, to be opened up for injection service. Routine Storage Plant - Compression Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 3 The addition of two (2) approximately 10,000,000 BTU/Hr heaters and associated valves and piping to heat gas prior to injection. Increases field injectability to be able to serve 100% of our firm obligations and eliminates the current risk of damaging the storage wells during injections. Major Project Milestones: Engineering Design Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 3/1/2018 3/1/2018 3/1/2018 8/1/2018 9/1/2018 9/1/2018 Total Project Cost Labor (Internal) $126,179 $0 $126,179 $0 Material $880,000 $0 $880,000 $0 Contract Services $1,446,520 $0 $1,446,520 $0 Overheads $276,271 $0 $276,271 $0 Contingency $0 $0 $0 $0 AFUDC $41,911 $0 $41,911 $0 Total $2,770,881 $0 $2,770,881 $0 April Minimum Day design from DTE Gas System Planning

24 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 10 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: BRM Unit #4 Engine Rebuild To complete major maintenance per the manufacturers recommended schedule (prior to 25,000 hours of runtime since last rebuild). This will help ensure engine operational reliability. Routine Storage Plant - Compression Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 3 Evaluation and rebuild, as necessary, of all major components on the engine and major auxillary units. Engine components will include cylinder liners and pistons, cylinder heads, master rods, piston rods and all bearings/bushings. Auxillary units include water pumps and filtration, oil pumps and filtration, water heating units, starters, electrical components and turbochargers. Following manufacturer recommendations will help ensure unit reliability for Midstream sales and Gas Control winter and summer needs. Major Key Milestone Design Material Purchase Construction Commissioning In Service Project Cost Breakdown Completion Date 11/30/18 03/31/19 07/10/19 07/19/19 08/09/19 Total Project Cost Labor (Internal) $55,000 $0 $5,000 $50,000 Material $1,160,000 $0 $0 $1,160,000 Contract Services $490,000 $0 $0 $490,000 Overheads $119,350 $0 $350 $119,000 Contingency $91,218 $0 $268 $90,950 AFUDC $114,934 $0 $337 $114,597 Total $2,030,502 $0 $5,955 $2,024,547 Reference Cooper-Bessemer OEM manuals on recommended duration between engine overhauls. Available Studies:

25 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 11 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Lynch - Asset Preservation Increased emergent infrastructure and system failures, due to deteriorating conditions, have resulted in unplanned corrective maintenance and capital asset preservation replacement requirements at the Lynch facility. The unplanned corrective maintenance has led to inefficient use of resources and increased cost due to emergency repairs. Assets that need to be replaced include the heating, ventilation and air conditioning (HVAC) system, electrical distribution systems within the building and parking lot and storm drainage systems. The HVAC systems have an unknown quantity of hazardous material and will be remediated before any other work begins. Assets are at the end of their useful life Routine General Plant - Structures and Improvements Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 4 Assets that will be replaced are fire detection and suppression systems, electrical distribution and plumbing systems, heating and cooling equipment, roof and paving. Capital maintenance standards are applied to optimize life cycle costs and ensure safety. Replacing these systems that are beyond useful life will lead to improved productivity and energy efficiency supporting employee engagement and environmental sustainability goals. The asset preservation project to be completed in 2018 will begin January, 1st 2018 and will be completed September 30th, The asset preservation projects to be complete in 2019 will begin January 1st, 2019 and will be completed September 30th, Project Cost Breakdown Total Project Cost Labor (Internal) $0 $0 $0 $0 Material $0 $0 $0 $0 Contract Services $1,496,000 $0 $544,000 $952,000 Overheads $594,000 $0 $216,000 $378,000 Contingency $0 $0 $0 $0 AFUDC $110,000 $0 $40,000 $70,000 Total $2,200,000 $0 $800,000 $1,400,000 Internal Study, Lynch Rd Requirement Report

26 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 12 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Astro Voice Replacement System To maintain a level customer safety profile as it pertains to gas leak response time during technological (IT) and cellular outages. Routine General Plant - Computers and Related Equipment Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 4 To replace the analog Astro Voice & Data Communication System and associated end of life infrastructure with the Michigan Public Safety Communication System (MPSCS). The system utilizes obsolete analog radios, base stations, and unsupported carrier-provided AT&T leased lines from AT&T, which drives a need for replacement. DTE s timely responses to Gas Leaks are key to our customer s safety. This solution will provide a backup to cellular coverage in an emergency. It will provide the ability to voice dispatch during this emergency, maintaining the ability to respond to a Gas Leak. The proposed utilization of the Michigan Public Safety Communication System (MPSCS) will allow DTE to: 1) take advantage of a robust and reliable radio communication system utilized by Michigan municipalities 2) utilize a system which is maintained and supported by the state of Michigan 3) directly communicate with state first responders during emergency events. In addition to multiple DTE Gas business units (Gas Operations, Gas Dispatch, Transmission and Storage, Gas Control), DTE ITS Radio Support benefits from this voice dispatching solution. ITS benefits given the fact that the infrastructure will be supported, externally, by the State of Michigan MPSCS. Schedule: 12/ Hardware Purchase 01/ /30/ Release 1: In-Truck Radio Replacement 07/ /30/ Release 2: Console replacement, field infrastructure retirement, Training Cost: Funding from Others: Available Studies: Project Cost Breakdown Total Project Cost Labor (Internal) $289,802 $289,802 $0 $0 Material $200,000 $200,000 $0 $0 Contract Services $1,486,204 $1,486,204 $0 $0 Overheads $403,800 $403,800 $0 $0 Contingency $630,000 $630,000 $0 $0 AFUDC $0 $0 $0 $0 Total $3,009,806 $3,009,806 $0 $0. DTE and ITS were using the MPSCS radio network (DTE emergency use - 20 Radios in substations) First Energy used the Ohio MARCS system (Similar system to MPSCS)

27 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 13 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Ford Central Energy Plant (CEP)- Dearborn Campus Transformation Project Over the next 10 years Ford Motor Company will be transforming its aging Dearborn campus into a modern green, high-tech corporate campus. As part of this transformation, Ford will be commissioning the construction of a new energy efficient central energy plant (CEP). The scope of gas facilities work is necessitated by Ford's natural gas equipment specified for their new CEP. Other Capital Projects - New Market Attachments Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 6 Install gas main and metering interconnecting Ford's new CEP with DTE Gas's Southfield high pressure gas system. The project will include 10,600' of 12" steel pipe south along Rotunda drive west along Oakwood then south along Carrol Shelby Drive to DTE Gas's metering facility centrally located in the Ford Dearborn Campus located at 1551 Carroll Shelby Drive, Dearborn, MI. DTE Gas will install two meters; one meter will provide metering and pressure regulaiton to the CEP at a flow rate up to 350 MMBTU/hr and a 200 psig delivery pressure. The second meter will provide metering and pressure regulation to the exisiting Ford Dearborn operations at a flow rate up to 200 MMBTU/hr and a 60 psig delivery pressure. Revenue generating project Major Key Milestone Survey/Route Confirmed Pipeline Drawing Preparation Drawing Approval Bid Process/Award Material procurement Permitting Pipeline Construction Metering Construction In Service - Meter 2 (60 PSIG) In Service - Meter 1 (200 PSIG) Completion Date 06/30/16 11/30/16 12/31/16 12/31/16 03/31/17 07/31/17 10/31/17 11/30/17 01/01/18 Q1/2019 Project Cost Breakdown Total Project Cost Labor (Internal) $81,485 $81,485 $0 $0 Material $604,220 $604,220 $0 $0 Contract Services $4,097,800 $4,097,800 $0 $0 Overheads $209,371 $209,371 $0 $0 Contingency $200,000 $200,000 $0 $0 AFUDC $324,124 $324,124 $0 $0 Total $5,517,000 $5,517,000 $0 $0 Ford has paid DTE Gas a security deposit to cover the entire project costs until such time negotiations of a gas transportation agreement between the parties is executed. The project will be funded under DTE Gas's new attachment rules modeling the contract term, incremental revenues from the Project, and any CIAC if required. The final deal financials will be modeled by DTE's controllers and require President/VP approval prior to contract exection with the customer.

28 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 14 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Funding from Others: Available Studies: Map/Location: Revenue generating project Construction Schedule: New service available November 1, Cost: Arauco Flakeboard America New service requirement for new Plant Other Capital Projects - New Market Attachments Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 6 Install 16,000 ft of 8" distribution steel pipeline, new customer meter set and upgrade Weyerhauser Gate Station to include new Filter Separator, Heater, regulation, Natural Gas monitoring & measurement equipment. Major Project Milestones: Engineering Design Permitting Materials Procurement Construction In Service Completion Date: Pipeline/Meter Completion Date: Gate Station Aug Sept June N/A Aug Sept Sept Oct Nov Nov Project Cost Breakdown Total Project Cost Labor (Internal) $500,000 $400,000 $100,000 $0 Material $500,000 $500,000 $0 $0 Contract Services $700,000 $700,000 $0 $0 Overheads $100,000 $100,000 $0 $0 Contingency $100,000 $100,000 $0 $0 AFUDC $0 $0 $0 $0 Total $1,900,000 $1,800,000 $100,000 $0

29 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: Sandberg Page: 15 of 26 Project: Drivers: Category: Line Number: Scope: NEXUS The NEXUS pipeline project consists of a proposed 255 mile, 36" diameter pipeline from Ohio to Michigan, terminating at a proposed NEXUS Meter Station to be located at the Willow Gate Station (WGS) in Ypsilanti Township, Washtenaw Count, Michigan. WGS is owned an operated by DTE Gas Company. Tie-in of NEXUS pipeline to DTE Gas facilities is at the outlet flange of the NEXUS Meter Station. The delivery of gas from NEXUS to DTE Gas is approximately 1.3 Bcf/day at 858 psig. Upon receipt, the gas may be delivered into DTE Gas's distribution system or transported on DTE Gas's system of transmission pipelines for deliveries to any number of inter and intrastate pipeline and gas storage operators. In order to transport the additional NEXUS gas through the DTE Gas pipeline system, a number of system upgrades ("DTE Gas-NEXUS upgrades") are required. Other Capital Projects - NEXUS Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 8 Major upgrades at the following DTE Gas facilities are required to transport NEXUS gas: Willow Gate Station, Willow Run Compressor Station, and Milford Compressor Station. The tentative in-service date for the NEXUS project, including DTE Gas-NEXUS upgrades is September 1, 2018 Willow Gate Station upgrades are needed to 1) interconnect DTE Gas facilities with NEXUS facilities and 2) move existing interconnecting pipeline deliveries to Willow Compressor Station. Upgrades to the existing facility include, installation of pipe, valves, and heaters to meet design requirements. Also associated with Willow Gate is the modification and enhancement of DTE Gas s current nomination system to account for the new supply from NEXUS. Willow Run Compressor Station upgrades are needed to compress gas from existing interconnecting pipelines to match the NEXUS delivery pressure of 858 psig. In order to meet delivery pressure requirements, an addition of four (4) new compressor units totaling 17,770 horsepower and associated valves, pipe, control systems, compressor and auxiliary buildings are needed. Milford Compressor Station upgrades are needed to boost gas pressure, after normal pressure losses, for continued delivery on DTE Gas s transmission system. The installation of three (3) new compressor units totaling 32,745 horsepower and associated valves, pipe, control system, compressor and auxiliary buildings are needed. Benefits: Revenue generating project Construction Schedule: Willow Gate Station Start Date Completion Date Engineering Design 12/01/15 06/01/16 Construction Phase I (Heaters) 08/01/16 09/30/16 Construction Phase II (30" Common Discharge Header) 02/01/17 06/15/17 Commissioning In Service 06/16/17 06/30/17 07/01/17 Willow Run Compressor Station Start Date Completion Date Engineering Design 12/01/15 10/16/16 Construction 10/03/16 10/25/17 Commissioning (Tentative) In Service (Tentative) 06/01/18 08/31/18 09/01/18 Milford Compressor Station Start Date Completion Date Engineering Design 12/01/15 10/16/16 Construction 10/03/16 11/17/17 Commissioning (Tentative) In Service (Tentative) 06/01/18 08/31/18 09/01/18 Cost: Project Cost Breakdown Total Project Cost Labor (Internal) $5,132,674 $4,283,642 $849,032 $0 Material $8,387,477 $8,387,477 $0 $0 Contract Services $67,224,901 $66,304,901 $920,000 $0 Overheads $5,155,382 $4,643,310 $512,072 $0 Contingency $3,160,000 $1,200,000 $1,960,000 $0 AFUDC $11,907,998 $6,212,998 $5,695,000 $0 Total $100,968,432 $91,032,328 $9,936,104 $0 Funding from Others: When placed into service, the revenue associated with the NEXUS project will support the invested capital. Available Studies: Map/Location:

30 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: Sandberg Page: 16 of 26 Project: Drivers: Category: Line Number: Scope: Gordie Howe International Bridge (GHIB) - DTE Gas Company The GHIB project is a new vehicular bridge owned by the Windsor Detroit Bridge Authority crossing the Other Capital Projects - Gordie Howe International Bridge Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 10 Vacation of point of entry (POE): A. Construct 7,500 feet of new 12" main around the plaza to connect system at Jefferson and Post to system Junction and Fort. B. Constrtuct a new 99# to 2# district regulator at Fort and Morrell C. Abandon 23,000 feet of existing main throughout the plaza area including a 16" 10# feeder main after the new main on Jefferson/Junction is completed. This work includes approximately 30 cut and cap locations. D. Abandon 8,000 feet of exsisting main in the area bounded by Livernois, Fort, Campbell and Conrail Railroad tracks including approximately 10 cut and cap locations. E. Construct 800 feet of new 8" main on Livernois for the Evans Distribution building. F. Relocate existing regulator at Livernois and South Service drive to Livernois and Fort. I-75 Road Work A. Abandon 3,000 feet or existing 2# and 10# main along existing service drive between Cavalry and Clark, including approximately 20 cut and cap locations. B. Construct 3,000 feeet of 8" 10# plastic main and 3,000 feet of 12" 2# plastic main, running in parallel along the new service drive, from Cavalry to Clark. C. Abandon mains on 4 existing bridges at Springwells, Green, Livernois and Clark including 10 cut and caps. D. Construct three new below-grade crossings of I-75 via open cut method at Govin, Beard, and McKinstry. E. Construct 3,500 feet of new 8" plastic main along Lafayette and Beard to allow elimination of the Green crossing of F. Construct new district regulator at Livernois and Lafayette to allow for elimination/reconfiguring of the Livernois and Beard crossings of G. Construct 2,300 feet of new 4" plastic main form Lafayette and 18th Streets to Fort and 23rd Street. Benefits: Construction Schedule: Cost: Funding provided Others: Available Studies: $5.3 million to be reimbursed by MDOT Major Project Milestones: Engineering Design Permitting Land Acquisition Materials Procurement Construction Phase I - I-75, Fort St, Junction Construction Phase II - POE Corridor Construction Phase III - POE Corridor Balance Construction Phase IV - I75 Service Drive In Service Completion Date: 10/1/2017 5/1/2017 7/1/2018 7/1/2017 6/1/2018 7/1/2018 7/1/2019 9/1/ Project Cost Breakdown Total Project Cost Labor (Internal) $1.3 $0.3 $0.7 $0.3 Material $0.1 $0.1 $0.0 $0.0 Contract Services $7.4 $2.5 $2.6 $2.3 Overheads $0.4 $0.1 $0.2 $0.1 Contingency $1.0 $0.4 $0.3 $0.3 AFUDC $0.1 $0.0 $0.1 $0.0 GHIB project total capital expenditure for $10.3 $3.4 $3.9 $3.0 Subtract MDOT Reimbursement ($5.3) $0.0 ($3.2) ($2.1) Total DTE Gas Capital Expenditures 1 $5.0 $3.4 $0.7 $0.9 MDOT Reimbursement of $5.3 million per agreement between MDOT and DTE Gas Map/Location: 1 DTE Gas GHIB project total capital expenditure of $5.0 million for 2017 through 2019 includes MDOT reimbursement of $5.3 million.

31 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: Sandberg Page: 17 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Milford Junction Loop Milford Junction Station is a location in the transmission system where several main pipelines converge. The junction provides continuous gas flow to and from various sections of the transmission and distribution systems. The Milford Junction station is a critical facility within the DTE Gas pipeline system that has a significant impact on DTE Gas s ability to deliver gas to its customers. As part of DTE s strategy to identify and mitigate pipeline safety risks, the Milford Junction Loop project will, in the event of a facility failure at Milford Junction, allow for isolation of the station and continued flow of gas around the station through the looped pipeline for uninterrupted gas supply. Other Capital Projects - Milford Junction Loop Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 11 Scope of Work: Design, construct and commission a 30 diameter, approximately 0.7 mile long transmission pipeline in the vicinity of Milford Junction, complete with four valve sites to connect with DTE Gas existing 24 Austin-Detroit B pipeline, 30 Austin-Detroit C pipeline, 36 Milford-Belle River E pipeline and 30 Milford K pipeline, and qualify for operation at a Maximum Allowable Operating Pressure (MAOP) of 1000 psig. The pipeline will serve as a bypass in the event of a failure at Milford Junction. The Milford Junction Loop project will, in the event of a facility failure at Milford Junction, allow for isolation of the station and continued flow of gas around the station through the looped pipeline for uninterrupted gas supply. In 2016, the ROW easements for the pipeline and the valve sites were secured and the valves sites along the "K"-Line and the "C"-Line were installed. The remaining valves sites and the pipeline will be constructed and place into service in November Major Project Milestones: Completion Date: Land Acquisition 05/14/16 Engineering Design 06/30/16 Materials Procurement 06/30/16 Act 9 Filing & Approval 08/23/16 Construction - Phase I 10/31/16 Permitting (Modification) 12/15/17 Construction - Phase II 11/10/17 Commissioning 11/17/17 Available for service 11/17/17 Site Restoration 08/01/18 Project Cost Total Project Breakdown Cost Labor (Internal) $157,911 $116,644 $41,267 $0 Material $123,566 $123,566 $0 $0 Contract Services $6,805,489 $6,750,506 $54,983 $0 Overheads $346,127 $342,377 $3,750 $0 Contingency $353,461 $353,461 $0 $0 AFUDC $236,446 $236,446 $0 $0 Total $8,023,000 $7,923,000 $100,000 $0 DTE Gas continuously evaluates its natural gas system to identify potential projects that would enhance reliability of gas supply to its customers. This evaluation process must consider, among other things, the capability of the current system, the need, from a reliability perspective, of the enhancement under evaluation, and the costs that customers will incur if the system enhancement is undertaken. In this case, the evaluation process identified the Milford Junction Bypass Pipeline as an infrastructure improvement that would improve the reliability of the Company s natural gas systems. More specifically, Milford Junction is crucial in facilitating natural gas deliveries to SEMI markets from storage located west, north and east of our market area. In 2012, as part of a routine review for emergency preparedness and system reliability, DTE Gas assessed the criticality and risk levels at Milford Junction along with reviews at all DTE Gas major facilities. The performance of these facilities was examined under Design Day conditions. DTE ranked the facilities by level of risk, and various contingency plans were determined for catastrophic failures at critical facilities. Of all the locations that were assessed, Milford Junction was given the second highest risk rating, but was the only site that did not currently have an available contingency plan. A catastrophic event at Milford Junction would affect approximately 50% of our total customer base and would undoubtedly cause major gas outages to essentially all customers located on the southwestern end of DTE Gas s SEMI distribution system. Because Milford Junction is the central point for gas deliveries to all of our major SEMI gate stations and storage facilities, any catastrophic failure leaves no alternative but market curtailment during the period Milford Junction is out of service. Pending the installation of the Milford Junction Bypass as a permanent solution to mitigate loss of service from a catastrophic failure at Milford Junction, DTE Gas implemented a number of interim measures including installation of higher fencing around the perimeter of the facility and the installation of 24x7 video camera monitoring to enhance the general protection of the facility. Alteranate Route Selection: DTE Gas reviewed two alternate routes in addition to the proposed route based on a number of variables. We have concluded from the review, summarized on the tables below, that the proposed route is the optimum route. Map/Location:

32 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 18 of 26 Project: Drivers: Northeast Beltline ILI Expansion (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Category: Line Number: Scope: Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline. Project will be completed in two phases as follows: Phase 1 - Engineering, Land acquisition, Permiting, Materials procurement and Installation of bored crossings Phase 2: Additional materials procurement, Construction and Commissioning Benefits: Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Construction Schedule: Major Project Milestones: Engineering Design Completion Date: 5/31/2018 Mate Materials (Phase 1) Permitting Land Acquisition Construction Phase I Materials (Phase 2) Construction Phase 2 Commissioning In Service 7/30/2018 7/30/2018 8/30/2018 9/30/ /30/2018 9/30/ /15/ /15/2019 Cost: Total Project Cost Project Cost Breakdown Labor (Internal) $600,000 $0 $300,000 $300,000 Material $1,200,000 $0 $400,000 $800,000 Contract Services $3,450,000 $0 $1,050,000 $2,400,000 Overheads $750,000 $0 $250,000 $500,000 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $6,000,000 $0 $2,000,000 $4,000,000 Funding from Others: Available Studies: Map/Location:

33 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 19 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Sparta Muskegon 16" ILI Expansion (West trap) (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Major Project Milestones: Engineering Design Permitting Land Acquisition Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 1/31/2018 2/28/2018 1/31/2018 4/30/2018 5/15/2018 5/30/2018 6/1/2018 Total Project Cost Labor (Internal) $529,077 $341,577 $187,500 $0 Material $747,305 $497,305 $250,000 $0 Contract Services $1,509,289 $853,039 $656,250 $0 Overheads $426,261 $270,011 $156,250 $0 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $3,211,932 $1,961,932 $1,250,000 $0 Risk assessment was performed to identify candidate lines for the ILI expansion program. The resulting prioritization matrix plus reassessment schedule is used to select pipelines for retrofit each year.

34 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 20 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule Cost: Funding from Others: Available Studies: Map/Location: Loreed Ludington 16" ILI Expansion (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Major Project Milestones: Engineering Design Land Acquisition Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 3/30/2019 4/30/2019 5/30/2019 6/30/ /15/ /31/ /1/2019 Total Project Cost Labor (Internal) $382,500 $0 $0 $382,500 Material $510,000 $0 $0 $510,000 Contract Services $1,338,750 $0 $0 $1,338,750 Overheads $318,750 $0 $0 $318,750 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $2,550,000 $0 $0 $2,550,000 Risk assement was performed to identify candidate lines for the ILI expansion program. The resulting prioritization matrix plus reassessment schedule is used to select pipelines for retrofit each year.

35 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 21 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Gaylord 8" ILI Expansion (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline (mile post 0 to 35.7). Phase 1 of retofit (mile post 35.7 to 65.3) was completed in 2013 Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Major Project Milestones: Engineering Design Land Acquisition Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 3/30/2018 4/30/2018 5/30/2018 6/30/ /15/ /31/ /1/2018 Total Project Cost Labor (Internal) $330,000 $0 $330,000 $0 Material $440,000 $0 $440,000 $0 Contract Services $1,155,000 $0 $1,155,000 $0 Overheads $275,000 $0 $275,000 $0 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $2,200,000 $0 $2,200,000 $0 Risk assement was performed to identify candidate lines for the ILI expansion program. The resulting prioritization matrix plus reassessment schedule is used to select pipelines for retrofit each year.

36 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 22 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Mackinaw 8" ILI Expansion (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline (mile post 9.9 to 46.9). Phase 1 of the retrofit (mile post 0 to 9.9) was completed in 2013 Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Major Project Milestones: Engineering Design Land Acquisition Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 3/30/2018 4/30/2018 5/30/2018 6/30/ /15/ /31/ /1/2018 Total Project Cost Labor (Internal) $330,000 $0 $330,000 $0 Material $440,000 $0 $440,000 $0 Contract Services $1,155,000 $0 $1,155,000 $0 Overheads $275,000 $0 $275,000 $0 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $2,200,000 $0 $2,200,000 $0 Risk assement was performed to identify candidate lines for the ILI expansion program. The resulting prioritization matrix plus reassessment schedule is used to select pipelines for retrofit each year.

37 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: Sandberg Page: 23 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Rogers City 8" ILI Expansion (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Major Project Milestones: Engineering Design Land Acquisition Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 3/30/2019 4/30/2019 5/30/2019 6/30/ /15/ /31/ /1/2019 Total Project Cost Labor (Internal) $328,500 $0 $0 $328,500 Material $438,000 $0 $0 $438,000 Contract Service $1,149,750 $0 $0 $1,149,750 Overheads $273,750 $0 $0 $273,750 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $2,190,000 $0 $0 $2,190,000 Risk assement was performed to identify candidate lines for the ILI expansion program. The resulting prioritization matrix plus reassessment schedule is used to select pipelines for retrofit each year.

38 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 24 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: S. Suburban ILI Expansion (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline. This is a multiyear project to be completed in 2017 with the design and installation of the South receiver trap at Southern Station, and tie-in of the North launcher trap (installed in 2015) at the Ecorse/Hannan valve site. Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Major Project Milestone Completion Date Design 5/30/2017 Materials 7/15/2017 Construction 9/30/2017 Commissioning 10/5/2017 In-Service 10/6/2017 Project Cost Breakdown Total Project Cost Labor (Internal) $333,271 $333,271 $0 $0 Material $128,135 $128,135 $0 $0 52.5% $1,317,102 $1,317,102 $0 $0 Overheads $257,831 $257,831 $0 $0 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $2,036,339 $2,036,339 $0 $0 Items requested by Staff: i. Purpose and Necessity of the Project with Supporting Data ii. Line Design, size, material used iii. Line Length and ROW requirements iv. Approximate Construction Schedule v. Project effect on cost of operation and reliability of service vi. Description of the property being replaced and salvage value vii. Map of site and location of facilities viii. Funding from other entities (MDOT, Customer, Municipalities, Etc.) ix. All studies performed by the Company or 3rd party regarding the project

39 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 25 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Lincoln Traverse City 10" Pipe Replacement Approximately 0.4 miles of the 1956 Lincoln-Traverse City 10" pipeline located in a High Consequence Area (HCA) contain Low Frequency Electric Resistance Weld (LF-ERW) seam. Seams of this vintage are generally considered to be "defective" relative to post 1970 pipe manufacturing technology, and the pipe segment is deemed to be exposed to a manufacturing threat. Being in a HCA, the pipe segment is therefore subject to integrity assessment. A recent audit of the TIMP determined that the prior assessment by DA method is not suitable for the seam threat inherent in the segment. As a result, DTE Gas elected to use pressure test as an alternative assessment method. Consequently, the 1956 pipe segment will be replaced with new pipe, tested to the requirements of subpart J of the Michigan Gas Safety Standard. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Replace approximately 0.4 mile segment of the 1956 Lincoln-Traverse City 10" pipeline with new, tested pipe to satisfy the requirements of Subpart O of Michigan Gas Safety Standards for integrity assessment of pipelines in HCA. Replacing the 1956 pipe segment containing a manufacturing seam threat with new pipe eliminates the seam threat and reduces the risk of pipeline failure. Major Project Milestones: Completion Date: Engineering Design 3/30/2017 Land Acquisition 4/30/2017 Permitting 5/15/2017 Materials Procurement 5/15/2017 Construction Phase I 6/30/2017 Construction Phase II 8/4/2017 Commissioning 8/5/2017 In Service 8/5/2017 Project Cost Breakdown Total Project Cost Labor (Internal) $398,154 $398,154 $0 $0 Material $230,364 $230,364 $0 $0 Contract Services $1,063,617 $1,063,617 $0 $0 Overheads $321,335 $321,335 $0 $0 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $2,013,470 $2,013,470 $0 $0 LINCOLN - TRAVERSE CITY (10) PIPE REPLACEMENT

40 Highest Cost Top 25 Capital Project Detail Schedule: B5.3 Witness: A. D. Sandberg Page: 26 of 26 Project: Drivers: Category: Line Number: Scope: Benefits: Construction Schedule: Cost: Funding from Others: Available Studies: Map/Location: Loreed Ludington 16" Tie Line ILI Expansion (1) TIMP rules require assessment of pipelines in segments classified as High Consequence Areas to identify and remediate any defects that could affect serviceability of the lines. Approximately 13% of DTE Gas transmission system miles is classified as HCA, leaving 87% not subject to assessment. Approved assessment methods include In-Line-Inspection (ILI), Direct Assessment (DA) and Pressure Test. ILI is the industry recognized method that covers all known measurable pipeline threats, and is the cheapest assessment method on a cost/mile basis. Consequently, DTE is proactively expanding the use of the ILI method to cover more miles of its transmission pipeline system to reduce risk and improve system integrity and reliability. (2) PHMSA, in a recent Notice of Proposed Rule Making (NPRM), expanded assessments of pipelines beyond HCA into class 3 and 4 non-hca as well as newly defined Moderate Consequence Areas (MCA). This rule is expected to be finalized in DTE Gas's proactive ILI expansion program is consistent with the proposed rules (3) Gas infrastructure in the country continues to age. The ILI expansion program provides valuable information on the condition of DTE Gas's transmission pipelines and is a major element of DTE Gas's strategy to assess long term serviceability of its pipelines. Infrastructure Recovery Mechanish - Pipeline Integrity Exhibit A-12, Schedule B5.1, Page 1 of 2, Line 15 Install launcher and receiver, replace any restrictive pipeline components such as fittings, valves, and replace unbarred tees to enable end to end passage of In-Line-Inspection (ILI) tools for assessment of pipeline Increasing the percentage of system miles assessed by ILI reduces risk and enhances the integrity and reliability of the transmission system Major Project Milestones: Engineering Design Land Acquisition Permitting Materials Procurement Construction Commissioning In Service Project Cost Breakdown Completion Date: 3/30/2019 4/30/2019 5/30/2019 6/30/ /15/ /31/ /1/2019 Total Project Cost Labor (Internal $300,000 $0 $0 $300,000 Materials $400,000 $0 $0 $400,000 Contract Services $1,050,000 $0 $0 $1,050,000 Overheads $250,000 $0 $0 $250,000 Contingency $0 $0 $0 $0 AFUDC $0 $0 $0 $0 Total $2,000,000 $0 $0 $2,000,000 Risk assement was performed to identify candidate lines for the ILI expansion program. The resulting prioritization matrix plus reassessment schedule is used to select pipelines for retrofit each year.

41 Infrastructure Recovery Mechanism Capital - Summary Schedule: B6 Capital Expenditures Commission Approved Target Levels Witness: J. M. Harris ($000) Page: 1 of 2 (a) (b) (c) (d) (e) (f) (g) (h) Line No. Description Mileage/Meter Goal 1 Pipeline Integrity $ 7,818 $ 7,818 $ 11,120 $ 11,120 $ 11,120 $ 11,120 (per Case No. U-16999) Main Renewal Program 2 Main Renewal Program - Base 17,400 17,400 17,400 17,400 17,400 17, Miles (per Case No. U-16407) 3 Modified Main Renewal Program 29,500 29,500 29,500 29,500 29,500 29, Miles (per Case No. U-16999) 4 Modified Main Renewal Program 15,600 31,400 31,400 31,400 31, miles (2016), 32 Miles ( ) (per Case No. U-17701) 5 Modified Main Renewal Program ,500 15,500 15,500 15, miles (2016), 25 Miles ( ) (per Case No. U-17999) 6 Modified Main Renewal Program - 75,900 99, , miles (2019), 83 miles (2020), 131 miles (2021) (per Case No. U-18999) 7 Meter Move-Out Program 22,700 22,700 22,700 22,700 22,700 22,700 12,790 inside meters (per Case No. U-16451) 8 Meter Move-Out Program 20,000 20,000 20,000 8,000 inside meters (per Case No. U-18999) 9 Total Infrastructure Recovery Mechanism $ 77,418 $ 93,018 $ 127,620 $ 223,520 $ 246,820 $ 289,020 (1) (2) (3) (4) (5) (6) (1) Infrastructure Recovery Mechanism capital costs recoverable through the Infrastructure Recovery Mechanism Recovery Charge as approved in Case No. U (2) Total Infrastructure Recovery Mechanism capital costs requested to be recovered through the Infrastructure Recovery Mechanism Recovery Charge as filed in this case.

42 Infrastructure Recovery Mechanism Capital - Summary Schedule: B6 Capital Expenditures Commission Approved Target Levels Witness: J. M. Harris ($000) Page: 2 of 2 (a) (b) (c) (d) 2019 No. Description Low Range Target High Range 10 Pipeline Integrity $ 3,923 $ 11,120 18, Main Replacement Program $ 162, , , Meter Move-Out Program $ 35,503 42,700 49, Total Infrastructure Recovery Mechanism $ 223, No. Description Low Range Target High Range 14 Pipeline Integrity $ 3,172 $ 11,120 19, Main Replacement Program-Total $ 185, , , Meter Move-Out Program $ 34,752 42,700 50, Total Infrastructure Recovery Mechanism $ 246, No. Description Low Range Target High Range 18 Pipeline Integrity $ 1,814 $ 11,120 20, Main Replacement Program-Total $ 225, , , Meter Move-Out Program $ 33,394 42,700 52, Total Infrastructure Recovery Mechanism $ 289,020

43 Main Renewal Program History Schedule: B6.1 For the Period Witness: J. M. Harris ($Millions) Page: 1 of 1 (a) (b) (c) (d) Line No. Description Footage Miles Cost MRP Mains Replaced 73, $ MRP Mains Retired 36, MRP Service Lines and Meter Work Total MRP 109, $ Unplanned Main Replacement - Routine 30, Total 140, $ MRP Mains Replaced 221, $ MRP Mains Retired 60, MRP Service Lines and Meter Work Total MRP 282, $ Unplanned Main Replacement - Routine 30, Total 312, $ MRP Mains Replaced 311, $ MRP Mains Retired 80, MRP Service Lines and Meter Work Total MRP 392, $ Settlement Adjustment per Case No. U Reconciliation (2.7) 18 Total Adjusted MRP $ Unplanned Main Replacement - Routine 24, Total 417, $ MRP Mains Replaced 360, $ MRP Mains Retired 77, MRP Service Lines and Meter Work Total MRP 438, $ Unplanned Main Replacement - Routine 20, Total 458, $ MRP Mains Replaced 332, $ MRP Mains Retired 63, MRP Service Lines and Meter Work Total MRP 396, $ Unplanned Main Replacement - Routine 29, Total 425, $ MRP Mains Replaced 726, $ MRP Mains Retired - 35 MRP Service Lines and Meter Work Total MRP 726, $ Unplanned Main Replacement - Routine 21, Total 748, $ Forecast 39 MRP Mains Replaced 796, $ MRP Mains Retired MRP Service Lines and Meter Work Total MRP 796, $ Unplanned Main Replacement - Routine 27, Total 823, $ 128.6

44 Incremental Resource Requirements Schedule: B6.2 For Witness: J. M. Harris Page: 1 of 1 (a) (b) Line No. Description FTEs for DTE Gas Distribution Employees FTEs for DTE Gas Distribution Support Employees 48 (Supervision, engineers, inspectors, etc.) Incremental Estimated Resource Requirements 244

45 Capital Expenditures - Main Renewal Program Schedule: B6.3 For the Period Witness: J. M. Harris Page: 1 of 2 (a) (b) (c) (d) (e) Line Unit Cost Planned Total Cost No. Description Basis Mileage Unit Cost (Millions $) Main Renewal Program (MRP) 2 Main Renewal - SEMI - Risked Ranked U $ 1,099,000 $ Main Renewal - GRMI - Risked Ranked and Grid U $ 700,000 $ Main Renewal - SEMI - MGA U $ 1,099,000 $ Total Main Renewal 154 $ 1,034,185 $ Main Retirement - SEMI U $ 340,000 $ Total - $ 340,000 $ - 9 Total - MRP 154 $ 1,034,185 $ One-time costs for expansion - $ - $ Grand Total - MRP 154 $ 1,071,092 $ Main Renewal Program (MRP) 13 Main Renewal - SEMI - Risked Ranked U $ 1,000,000 $ Main Renewal - GRMI - Risked Ranked and Grid U $ 700,000 $ Main Renewal - SEMI - MGA U $ 1,000,000 $ Total Main Renewal 178 $ 941,011 $ Main Retirement - SEMI U $ 340,000 $ Total - $ 340,000 $ - 20 Total - MRP 178 $ 941,011 $ One-time costs for expansion - $ - $ Grand Total - MRP 178 $ 953,258 $ 169.7

46 Capital Expenditures - Main Renewal Program Schedule: B6.3 For the Period Witness: J. M. Harris Page: 2 of 2 (a) (b) (c) (d) (e) Line Unit Cost Planned Total Cost No. Description Basis Mileage Unit Cost (Millions $) Main Renewal Program (MRP) 24 Main Renewal - SEMI - Risked Ranked U $ 1,000,000 $ Main Renewal - GRMI - Risked Ranked and Grid U $ 700,000 $ Main Renewal - SEMI - MGA U $ 1,000,000 $ Total Main Renewal 206 $ 927,184 $ Main Retirement - SEMI U $ 340,000 $ Total - $ 340,000 $ - 31 Total - MRP 206 $ 927,184 $ One-time costs for expansion - $ - $ Grand Total - MRP 206 $ 936,990 $ Main Renewal Program (MRP) 35 Main Renewal - SEMI - Risked Ranked U $ 1,000,000 $ Main Renewal - GRMI - Risked Ranked and Grid U $ 700,000 $ Main Renewal - SEMI - MGA U $ 1,000,000 $ Total Main Renewal 254 $ 911,417 $ Main Retirement - SEMI U $ 340,000 $ Total - $ 340,000 $ - 42 Total - MRP 254 $ 911,417 $ One-time costs for expansion - $ - $ Grand Total - MRP 254 $ 921,654 $ 234.1

47 Inside Meter Move-Out History Schedule: B6.4 For Witness: J. M. Harris Page: 1 of 1 (a) (b) (c) (d) (e) (f) (g) (h) Line No. Description Forecast Total 1 Meter Move Out 12,847 13,207 14,578 12,901 14,401 14,000 81,934 2 Inside Meters 10,279 10,940 10,170 9,013 6,699 12,790 59,891 3 Impacted Outside Meters 2,568 2,267 4,408 3,888 7,702 1,210 22,043 4 Main Renewal Program 3,695 5,944 7,435 5,404 3,935 6,000 32,413 5 Inside Meters 2,340 2,911 3,645 2,074 1,017 1,100 13,087 6 Impacted Outside Meters 1,355 3,033 3,790 3,330 2,918 4,900 19,326 7 Routine Activity 11,416 10,039 7,279 6,427 6,512 4,000 45,673 8 Inside Meters 11,416 10,039 7,279 6,427 6,512 4,000 45, Total Inside Meter Move-out 27,958 29,190 29,292 24,732 24,848 24, , Inside Meters 24,035 23,890 21,094 17,514 14,228 17, , Impacted Outside Meters 3,923 5,300 8,198 7,218 10,620 6,110 41,369

48 Leaks on Mains and Services Schedule: B6.5 Witness: J. M. Harris Page: 1 of 1 Miles of Metallic Main DTE 9,153 9,130 9,074 9,168 9,071 8,956 8,913 All Michigan 27,248 27,230 27,108 27,055 26,784 26,555 26,356 All Michigan ex. DTE 18,095 18,100 18,034 17,888 17,713 17,599 17,443 Consumers 13,943 13,994 13,931 13,830 13,711 13,625 13,519 Leaks on Mains - Corrosion DTE 1,568 1,664 4,331 5,036 4,336 3,625 3,011 All Michigan 2,066 2,185 2,055 5,457 4,744 3,986 3,383 All Michigan ex. DTE Consumers Leaks from Corrosion per 100 miles of Main DTE All Michigan All Michigan ex. DTE Consumers Leaks from Corrosion per 100 miles of Metallic Main DTE All Michigan All Michigan ex. DTE Consumers Linear (DTE)

49 Overdue MACs by Aging Schedule: B6.6 For 2017 Witness: J. M. Harris Page: 1 of 1 (a) (b) (c) (d) Line No. Description Southeast Greater Michigan Total years overdue 13,583 2,930 16, years overdue 10,138 4,518 14, years overdue 13,605 5,934 19, years overdue 8,555 2,607 11, years overdue 10,331 2,113 12, years overdue 8,610 1,839 10, years overdue 6,264 2,258 8, years overdue 41,427 3,803 45,230 9 Unidentified / Investigating Total MAC Check Backlog 112,786 26, ,813

50 Actual Capital Cost of IRM compared to targeted Schedule: B6.7 levels 2014, 2015, 2016 Witness: J. M. Harris Page: 1 of 1 (a) (b) (c) (d) Line No. Description Planned Actual Variance Main Renewal Program $ 46,900,000 $ 47,017,000 $ 117,000 2 Meter Move Out 22,700,000 26,480,000 3,780,000 3 Pipeline Integrity 7,820,000 7,738,000 (82,000) 4 Total IRM $ 77,420,000 $ 81,235,000 $ 3,815, Main Renewal Program $ 46,900,000 $ 53,074,000 $ 6,174,000 6 Meter Move Out 22,700,000 25,038,000 2,338,000 7 Pipeline Integrity 7,820,000 9,038,000 1,218,000 8 Total IRM $ 77,420,000 $ 87,150,000 $ 9,730, Main Renewal Program $ 58,625,000 $ 86,323,000 $ 27,698, Meter Move Out 22,700,000 26,693,000 3,993, Pipeline Integrity 7,820,000 11,121,000 3,301, Total IRM $ 89,145,000 $ 124,137,000 $ 34,992,000

51 Map of MAC MMO Pilot Area Schedule: B6.8 Witness: J. M. Harris Page: 1 of 1