welcome
play

Welcome 2016 Partners in Business Meeting October 12, 2016 - PowerPoint PPT Presentation

Mar 18, 2024 •309 likes •1.44k views

Welcome 2016 Partners in Business Meeting October 12, 2016 Connecting Energy Infrastructure The Value of ITC 2016 Partners in Business Meeting October 12, 2016 Simon S. Whitelocke Vice President, ITC Holdings Corp., and President, ITC

  1. ITC Transmission’s 2017 Network Rate is $2.856/kW-Mo Key Drivers PARS Refund $0.056 $0.019 $(0.399) $0.155 $29M | Increase due to refund of previous PARS credits to $0.164 PJM/NYISO A&G/OM Depreciati $(0.128) $0.168 on … $0.282 Offsets ROE Net Plant Change in True-Up Adjustment Change Deferred TU Taxes $11M over recovery in 2014 | $4M under recovery in 2015 Pars Refund Higher Plant Balances $161M in Capital Additions | Stone Pool, Fitz Transformer $2.856 $2.540 Fewer Credits and Offsets $10M Fewer MM/GG Credits | $5M PARS ROE Order $(23)M | Lower Return on Rate Base, Income Taxes Deferred Taxes Represents increases from 2016 to 2017 Projected rates * Total may not reconcile to 2016 projected rate change due to rounding Represents decreases from 2016 to 2017 Projected rates $(100)M | Election of Bonus Depreciation

  2. Accounting Change – Cost Allocation for Shared Assets • During 2016, ITC made refinements to the method of allocating the costs of shared assets owned by its affiliates • Office Facilities • Information Technology Hardware and Software • The changes reflect more appropriate cost causation factors and methods and standardizes the methodology among all of ITC’s affiliates. • Details contained in the accounting disclosure • For ITC Transmission, these changes decreased the 2017 revenue requirement by $2.9 million.

  3. METC 2017 Attachment O - Projected Formula Rate

  4. Rate Effects of the New ROE Independence Adder Base ROE: Capped ROE RTO Adder 10.32% 11.35% 150 BP Impacts of ROE Change to 2017 Projected Rates 9/1 Posting 10/7 Posting WACC 9.67% 8.45% Return on Rate Base $129.1 M $112.8 M Income Taxes $68.9 M $58.5 M Credits and Offset $103.0 M $95.7 M

  5. Steps to Derive the Projected 2017 Net Revenue Requirement 2017 Projected Rate Base Weighted Average Cost of Capital Step 1 $1,335,635,609 8.45% Allowed Return Operating Expenses + Income Taxes Step 2 $112,832,851 $213,296,008 Gross Revenue Requirement Revenue Credits/Offsets Step 3 $326,128,859 $95,689,620 Projected 2017 Revenue Req. 2015 True-Up Over Recovery Step 4 $230,439,239 $(2,874,558) Projected 2017 Net Revenue Requirement Step 5 $227,564,681

  6. METC’s 2017 Network Rate is $2.873/kW-Mo Key Drivers Higher Plant Balances $0.035 $(0.342) $0.043 $223M in Capital Additions | Battle Creek rebuild, Ludington $0.043 $0.044 $0.109 Breaker Replacement $0.323 A&G $(0.145) Offsets O&M Depreciation TOIT $(0.013) Expense TU ROE Change in True-Up Adjustment CWC/MS Net Plant Deferred Taxes $7M | Lower over-recovery Higher Depreciation, A&G, O&M and Tax Expenses $2.776 $2.873 $5M Taxes | $3M Depreciation Expense | $3M A&G ROE $(9)M | Lower Return on Rate Base | Lower Income taxes | Lower Credits/Offsets Deferred Taxes Represents increases from 2016 to 2017 Projected rates $(89)M | Election of Bonus Depreciation Represents decreases from 2016 to 2017 Projected rates

  7. Accounting Change – Cost Allocation for Shared Assets • During 2016, ITC made refinements to the method of allocating the costs of shared assets owned by its affiliates • Office Facilities • Information Technology Hardware and Software • The changes reflect more appropriate cost causation factors and methods and standardizes the methodology among all of ITC’s affiliates. • Details contained in the accounting disclosure • For METC, these changes decreased the 2017 revenue requirement by $0.9 million. 36

  8. Next Steps  Information Exchange Process:  Interested parties to submit information requests no later than December 1, 2016  We will make a good faith effort to respond within fifteen (15) business days of receipt of such requests  Any request for information must be submitted in writing to misoformularates@itctransco.com  All questions and answers will be distributed by email to the parties who asked, and will be posted on the OASIS website

  9. ITC Transmission Appendix

  10. ITCT’s Projected Rate Increased by $0.316 2017 2016 Increase/ Description Variance % Projected Projected (Decrease) $160,988,380 Projected Gross Plant in Service $2,701,029,380 $2,540,041,000 32,049,880 Accumulated Depreciation 787,058,880 755,009,000 (100,954,600) Deferred Income Taxes (293,699,463) (192,744,863) ADIT Deferral/M&S/Prepayment/CWC 68,299,501 70,883,941 (2,584,440) Rate Base $1,688,570,538 $1,663,171,078 $25,399,460 1.53% Return on Rate Base $147,110,886 $169,742,916 $(22,632,030) (13.33)% O&M Expenses $29,805,000 $30,070,506 $(265,506) A&G Expenses 34,827,000 32,885,000 1,942,000 Depreciation Expense 62,632,989 56,822,602 5,810,387 Income Taxes 74,367,550 89,479,069 (15,111,520) ADIT Deferral/Other Taxes 52,462,000 51,809,096 652,903 Total Operating Expenses $254,094,539 $261,066,274 $(6,971,735) (2.67)% Credits/Offsets (Sch. 26, 26A, PTP, rents) $(141,144,416) $(156,982,847) $15,838,431 True-Up Adjustments | CIAC 3,982,460 (12,157,000) 16,139,460 PARS Refund Adjustment 28,991,234 - 28,991,234 Projected Net Revenue Requirement* 293,034,702 261,669,343 31,365,359 Projected Network Load (based on 12 CP) 8,549,780 kW 8,586,625 kW (36,845) kW Projected Rate ($/kW-Mo) $2.856 $2.540 $0.316 12.44% * Totals may not reconcile due to rounding

  11. Step 1: Calculation of ITC Tranmsission’s Rate Base 2017 Projected 2016 Projected Increase/ Rate Base Components Variance % Amount Amount (Decrease) Gross Plant in Service $2,701,029,380 $2,540,041,000 $160,988,380 6.34% - Accumulated Depreciation 787,058,880 755,009,000 32,049,880 4.24% Net Plant in Service* $1,913,970,500 $1,785,032,000 $128,938,500 7.22% + Deferred Income Taxes (293,699,463) (192,744,863) (100,954,600) 52.38% + ADIT Deferral** 15,655,501 18,685,598 (3,030,097) (16.22)% + Materials & Supplies 36,272,000 35,691,905 580,095 1.63% + Land Held for Future Use 6,290,000 6,290,000 - 0.00% + Prepayments 2,003,000 2,347,000 (344,000) (14.66)% + Working Capital 8,079,000 7,869,438 209,562 2.66% = Total Rate Base* $1,688,570,538 $1,663,171,078 $25,399,460 1.53%

  12. Overview of 2017 Planned Capital Additions  The development of the annual Rate Base begins with a forecast of planned capital additions.  The ITC Transmission Planned Capital Addition slides identify expected line, substation, and other construction Nelson Dewey (Wisconsin) projects as they are currently known. Retirement Dubuque Marshalltown Retirement Construction  The projects identified represent our best estimates for projects to be initiated and completed.  Note that many factors such as regulatory approvals, construction resources, availability of materials, weather and other unforeseen events, could alter projections and schedules.

  13. 2017 Planned Transfers to Plant in Service Projected Projected Projected MISO ID Project Name MISO ID Project Name MISO ID Project Name Amount Amount Amount Reliability - System Capacity Improvements Customer Connections Reliability - Infrastructure Improvements 3285 Shoal 33.3 MVAR Capacitor Install $3,342,247 2929 Ariel Substation $551,493 1550 Sunset to Hager 120kV Rebuild $2,161,678 3938 Greenwood 54 MVar 120KV Capacitor 3,742,051 3281 Chelsea Interconnection 300,297 4539 Hemphill Ctrl Reloc - Hunters Creek 349,864 4153 Toll Road SVC 197,717 4566 Lark Customer Connection 268,535 8083 Cortland Relay Rpl Cortland-Warren 51,939 4518 Monroe 345-120kV Xfrmr 304 Rpl 4,052,124 4566 Detroit Waste Water Customer Conn 386,779 9440 Waterman Circuit Relocations 7,311,185 7560 Stone Pool Interconnection 11,068,770 4737 Genessee County Pumping 245,722 9998 Relay Replacement Project 8,296,008 7891 Carrigan 120 kV Switching Station 85,613 9360 Scio Substation 312,714 9998 Wood Pole Replacement Program 8,138,981 8087 Stratford Capacitor 794,132 10425 J340 Wind Farm 13,900,394 9998 Breaker Replacement Program 5,861,855 8094 Fitz 345/120kV Transformer&Station 7,965,445 10723 Skylark Substation 1,162,712 9998 Potential Device Replacement Program 2,307,632 9998 Transformer Refurbish Program 465,085 11603 J321 Interconnection Request 7,910,962 9998 NERC Req'd Protection System Repl. 1,162,712 9998 Misc Line Equipment Replacement 4,650,846 Total for Customer Connections $25,039,608 9998 Disconnect Switch Replacements 3,870,749 10923 Pole Top Switch Additions 2,325,423 9998 Transformer Replacement Program 4,754,370 $38,689,453 General Plant Total for Reliability - System Capacity Improvements 9998 Miscellaneous - Reliability/Infra. 2,077,767 Facilities $1,164,182 ITC Rights of Way Acquisition 3,488,135 Information Technology 10,965,509 Engineering Design 641,817 Security Improvements 581,356 ERUC - Reactionary Capital Work 581,356 Contractors 1,511,525 T-Value Mitigation to lower (MAD) 2,702,904 Total General Plant $14,222,572 ITCOP NERC CIP-006 981,233 Total for Reliability - Infrastructure Improvements $54,740,183 Grand Total for ITC Transmission's Planned Transfers to Plant in Service $132,691,816

  14. Step 2: Calculation of ITCTransmission’s Projected Rate of Return and Allowed Return 2017 Projected 2016 Projected Increase/ Cost of Capital Weight Projected Cost WACC WACC (Decrease) Equity 60% 11.35% 6.81% 8.33% (1.52)% Debt 40% 4.76% 1.90% 1.88% 0.02% Rate of Return 8.71% 10.21% (1.50)% 2017 Projected 2016 Projected Increase/ Increase/ Allowed Return Amount Amount (Decrease) (Decrease) Rate Base $1,688,570,538 $1,663,171,078 x Rate of Return (above) 8.71% 10.21% = Allowed Return* $147,110,886 $169,742,916 $(22,632,030) (13.3)% * Totals may not reconcile due to rounding

  15. Step 3: ITCTransmission’s Projected Operating Expenses and Total Gross Revenue Requirement 2017 Projected 2016 Projected Increase/ Operating Expense Variance % Amount Amount (Decrease) Operation & Maintenance Expenses $29,805,000 $30,070,506 $(265,506) (0.88)% Administrative & General Expenses 34,827,000 32,885,000 1,942,000 5.91% Depreciation Expense 62,632,989 56,822,602 5,810,387 10.23% ADIT Deferral Amortization 3,030,000 3,030,097 (97) 0.0% Taxes Other Than Income Taxes 49,432,000 48,779,000 653,000 1.34% Income Taxes 74,367,550 89,479,069 (15,111,520) (16.89)% Total Operating Expenses $254,094,539 $261,066,274 $(6,971,735) (2.67)% Projected Gross Revenue Requirement 2016 Projected Amount 2017 Projected Allowed Return (from previous slide) $147,110,886 + Projected Operating Expenses + Taxes (above) $254,094,539 2017 Projected Gross Revenue Requirement before Revenue Credits & Offsets $401,205,425 * Totals may not reconcile due to rounding

  16. Step 4: ITC Transmission’s Projected Revenue Requirement after Credits & Offsets 2017 Projected 2016 Projected Increase/ Revenue Requirement & Revenue Credits/Offsets Variance % Amount Amount (Decrease) Revenue Requirement before Revenue Credits & Offsets $401,205,425 $430,809,190 $(29,603,765) (6.87)% Less: Attachment GG Revenue Requirement (Sch. 26) 19,593,463 22,290,605 (2,697,142) (12.10)% Less: Attachment MM Revenue Requirement (Sch. 26A) 91,090,953 106,059,366 (14,968,413) (14.11)% Less: Attachment SS Transmission Service Revenues (Sch. 36) - 5,716,876 (5,716,876) (100)% Less: Point-to-Point/Other Transmission Service Revenues 3,063,000 3,646,001 (583,002) (15.99)% Less: Rental Revenues 27,397,000 19,270,000 8,127,000 42.17% Subtotal Credits/Offsets $141,144,416 $156,982,847 $(15,838,431) 2017 Projected Revenue Requirement after Revenue Credits/Offsets $260,061,009 $273,826,343 $(13,765,334) (5.0)% * Totals may not reconcile due to rounding

  17. Step 5: ITC Transmission’s Net Revenue Requirement After 2015 True-Up Net Revenue Requirement 2017 Projected Revenue Requirement after Revenue Credits/Offsets $260,061,009 + 2015 True-up Adjustment Under/(Over) Recovery $3,982,460 + 2017 PARS Adjustments $28,991,234 2017 Projected Net Revenue Requirement (including 2015 True-up) $293,034,703 Load Divisor 102,597,360 Network & P-to-P Rate ($/kW/Mo) $2.856 * Totals may not reconcile due to rounding

  18. METC Appendix

  19. METC’s Projected Rate Increased by $0.097 2017 2016 Increase/ Descriptions Variance % Projected Projected (Decrease) $1,977,520,490 $1,754,324,000 $223,196,490 Projected Gross Plant in Service 456,283,810 433,490,000 22,793,810 Accumulated Depreciation (280,869,579) (191,115,211) (89,754,368) Deferred Income Taxes 95,268,508 103,388,656 (8,120,148) ADIT Deferral/M&S/Prepayment/CWC Rate Base $1,335,635,609 $1,233,107,445 $102,528,164 7.68% Return on Rate Base $112,832,851 $121,690,507 $(8,857,656) (7.28)% O&M Expenses $45,547,000 $45,414,000 $133,000 A&G Expenses 33,724,546 31,059,000 2,665,546 Depreciation Expense 36,806,545 33,405,000 3,401,545 Income Taxes 58,538,484 63,574,074 (5,035,590) ADIT Deferral/Other Taxes 38,679,433 35,217,071 3,462,362 Total Operating expenses/Income Taxes $213,296,008 $208,669,145 $4,626,863 2.17% ($95,689,620) ($99,086,614) $3,396,994 Credits/Offsets (Sch. 26, 26A, PTP, rents) True-Up Adjustment | CIAC $(2,874,558) $(10,481,279) $7,606,721 Projected Net Revenue Requirement* 227,564,681 220,791,759 6,772,922 2017 Projected Network Load (based on 12 CP) 6,601,000 kW 6,629,000 kW (28,000) kW Projected Rate ($/kW-Mo) $2.873 $2.776 $0.097 3.49% * Totals may not reconcile due to rounding

  20. Step 1: Calculation of METC’s Rate Base 2016 2017 Projected Increase Rate Base Components Projected Variance % Amount (Decrease) Amount Gross Plant in Service $1,977,520,490 $1,754,324,000 $223,196,490 12.72% - Accumulated Depreciation 456,283,810 433,490,000 22,793,810 5.26% Net Plant in Service* $1,521,236,680 $1,320,834,000 $200,402,680 15.17% + Deferred Income Taxes (280,869,579) (191,115,211) (89,754,368) 46.96% + ADIT Deferral** 27,240,565 30,645,636 (3,405,071) (11.11)% + Revenue Deferral 27,500,000 30,250,000 (2,750,000) (9.09)% + Materials & Supplies 27,256,000 29,581,895 (2,325,895) (7.86)% + Land Held for Future Use - - - + Prepayments 3,363,000 3,352,000 11,000 0.33% + Working Capital 9,908,943 9,559,125 349,818 3.66% = Total Rate Base* $1,335,635,609 $1,233,107,445 $102,528,164 8.31% * Totals may not reconcile due to rounding

  21. Overview of 2017 Planned Capital Additions  The development of the annual Rate Base begins with a forecast of planned capital additions.  The METC Planned Capital Addition slides identify expected line, substation, and other construction projects as they are currently known.  The projects identified represent our best estimates for projects to be initiated and completed.  Note that many factors such as regulatory approvals, construction resources, availability of materials, weather and other unforeseen events, could alter projections and schedules.

  22. 2017 Planned Transfers to Plant in Service Projected Projected MISO ID Project Name MISO ID Project Name MISO ID Project Name Projected Amount Amount Amount Reliability - Infrastructure Improvements 4143 Verona - Marshall 138KV TE Upgrade $26,870 Reliability - System Capacity Improvements Customer Connections 4147 Battle Creek Island Road 138KV Rebl 19,980,642 3599 Palisades 345KV Station Equipment $753,800 2486 Haakwood Substation Interconnection $286,948 4150 Verona-Argenta 138kV TE upgrade 153,301 3926 Dort 138kV Terminal Equipment Upgrd 244,440 4510 Battle Creek to Morrow #1 138kV Sag 284,499 4537 Faussett CE Interconnection 408,801 4154 North Belding 138kV Terminal Equipm 109,671 4539 Hemphill Control Relocation 3,776,437 4537 Benston 138kV GOAB Installation 285,677 4505 Bass Creek-Sternberg 138kV Sag Rem 249,375 4542 Morrow Control Relocation 730,080 4537 Laperell Interconnetion 286,948 4509 Argenta-Battle Creek 345kV Sag Rem 2,474,929 4556 Blackstone 138 kV Second Bus-Relay 783,842 4557 Croton to Four Mile 138 kV Circuit 197,130 4524 Emmet-Livingston 138kV Sag Remediat 181,897 9422 Coldwater Interconnection 10,972,787 8170 Leoni to Page Ave 138kV Relay 77,175 8067 Beals Road 138kV Station Equi Upgrd 398,994 Total for Customer Connections $12,241,161 9945 Breaker Replacement Program - METC 10,369,406 8078 Donaldson Creek 33.3 MVAR Capacitor 414,194 9945 METC Relay Betterment Project 6,480,117 8080 Coldwater 138kV Capacitor 3,880,910 9945 METC Wood Pole Replacement Program 9,919,608 8096 Roosevelt-Gaines 345 kV Sag Remed 383,475 9945 Potential Device Replacement Progra 1,271,401 8109 Gaylord-Livingston 138kV Sag Remed 51,179 9945 Disconnect Switch Replacements 3,424,851 General Plant 8119 Pole Top Switch Additions 3,586,853 9945 METC NERC Protection Compliance 1,195,618 Facilities - METC $597,228 8127 Ludington 345 kV Breaker Replacemnt 8,527,045 9945 Mio 138kV Switch Replacement 688,573 METC Station Security 489,757 9945 Transformer Replacement Program 4,782,471 8144 Meyer 345-138kV Station 4,484 9945 Miscellaneous - Reliability/Infrast 2,296,026 Contractors - METC 5,562,208 9972 Four Mile Control Relocation 3,555,859 8460 Grand Blanc BOC Hemphill 138kV Sag 76,393 Total General Plant $6,649,192 9975 Verona Control Relocation 2,964,029 8461 Cobb-Sternberg 138kV Sag Remediate 306,976 10286 Campbell 138kV remv breaker 588 89,671 8540 Claremont-Layton 138kV Sag Remediat 491,787 METC Rights of Way Acquisition 3,586,853 9945 Transformer Refurbish Program 478,247 Engineering Design 597,809 9945 METC Misc Line Equip Replacement 3,725,201 ERUC- Reactionary Capital Work 597,809 10384 Verona-Barnum Creek Jct 138kV Sag 1,078,303 T-Value Mitigation to lower (MAD) 1,209,208 METC NERC CIP-006 717,371 Total for Reliability - Infrastructure Improvements $ 79,039,286 Total for Reliability - System Capacity Improvements $28,135,523 Grand Total for METC's Planned Transfers to Plant in Service $126,065,163

  23. Step 2: Calculation of METC’s Projected Rate of Return and Allowed Return 2017 2016 Projected Increase/ Cost of Capital Weight Projected Projected Cost (Decrease) WACC WACC Equity 60% 11.35% 6.81% 8.03% (1.22)% Debt 40% 4.10% 1.64% 1.84% (0.20)% Rate of Return 8.45% 9.87% (1.42)% 2017 Projected 2016 Projected Increase/ Variance Allowed Return Amount Amount (Decrease) % Rate Base $ 1,335,635,609 $ 1,233,107,445 x Rate of Return 8.45% 9.87% (above) = Allowed Return* $112,832,851 $121,690,507 $(8,857,656) (7.28)% * Totals may not reconcile due to rounding

  24. Step 3: METC’s Projected Operating Expenses and Total Gross Revenue Requirement 2017 Projected 2016 Projected Increase/ Operating Expense Variance % Amount Amount (Decrease) Operation & Maintenance Expenses $45,547,000 $45,414,000 $133,000 0.29% Administrative & General Expenses 33,724,546 31,059,000 2,665,546 8.58% Depreciation Expense 36,806,545 33,405,000 3,401,545 10.18% Regulatory Deferral Amortization (Note I-a) 2,750,000 2,750,000 - 0.00% ADIT Amortization 3,405,071 3,405,071 - 0.00% Taxes Other Than Income Taxes 32,524,362 29,062,000 3,462,362 11.91% Income Taxes 58,538,484 63,574,074 (5,035,590) (7.92)% Total Operating Expenses + Income Taxes $213,296,008 $208,669,145 $4,626,863 2.22% Projected Gross Revenue Requirement 2016 Projected 2017 Projected Allowed Return (from previous slide) $112,832,851 + Projected Operating Expenses $213,296,008 2017 Projected Gross Revenue Requirement before Revenue Credits & Offsets $326,128,859 * Totals may not reconcile due to rounding

  25. Step 4: METC’s Projected Revenue Requirement after Credits & Offsets 2017 Projected 2016 Projected Increase/ Revenue Requirement & Revenue Credits/Offsets Variance % Amount Amount (Decrease) Gross Revenue Requirement before Revenue Credits & Offsets $326,128,859 $330,359,652 $(4,230,793) (1.28)% Less: Attachment GG Revenue Requirement (Sch. 26) 81,353,926 85,258,372 (3,904,446) (4.58)% Less: Attachment MM Revenue Requirement (Sch. 26A) 64,694 75,241 (10,547) (14.02)% Less: Point-to-Point/Other Transmission Service Revenues 13,727,000 13,131,001 595,999 4.54% Less: Rental Revenues 544,000 622,000 (78,000) (12.54)% Subtotal Credits/Offsets $95,689,620 $99,086,614 ($3,396,994 ) (3.43)% 2017 Revenue Requirement after Revenue Credits/Offsets $230,439,239 $231,273,038 $(833,799) (0.36)% * Totals may not reconcile due to rounding

  26. Step 5: METC’s Net Revenue Requirement after 2015 True -Up Net Revenue Requirement Projected 2017 Gross Revenue Requirement after Revenue Credits/Offsets $230,439,239 + 2015 True-up Adjustment Under/(Over) Recovery $(2,874,558) 2017 Projected Net Revenue Requirement (including 2015 True-up) $227,564,681 Load Divisor 79,212,000 Network & P-to-P Rate ($/kW/Mo) $2.873 * Totals may not reconcile due to rounding

  27. Michigan Regulatory Update 2016 Partners in Business Meeting October 12, 2016 Kwafo Adarkwa Manager, Regulatory Strategy

  28. Overview  New MPSC Commissioner  MISO Study Request  Resource Adequacy

  29. New MPSC Commissioner Rachael Eubanks was appointed by Governor Rick Snyder to the Michigan Public Service Commission, for a term beginning Aug. 1 and expiring July 2, 2017, as she completes the remainder of a six-year term. Background: • 13 years in public finance, most recently as a director at Robert W. Baird & Co. Inc. During her 10-year tenure at Baird, she completed over $22 billion in bond financings, primarily for the State of Michigan, Michigan State Building Authority, Michigan Finance Authority and other state agencies. • Served as a financial advisor on a $185 million issuance for the Public Lighting Authority of Detroit that financed a complete overhaul of the city’s street lighting system amidst its bankruptcy proceedings. • Holds a bachelor’s degree in economics from the University of Michigan.

  30. MISO Study Request In August, the Michigan Agency for Energy submitted a written request to MISO requesting a more holistic study of transmission and generation expansion in Michigan.  The request was made for the State to better understand the potential production cost savings, reliability and resource adequacy benefits of transmission and generation expansion.  This request looks for MISO to conduct a near- and long-term study of the state with a particular focus on Zone 2 in the eastern UP and Zone 7, which encompasses most of the lower peninsula.  ITC, Wolverine and the Canadian province of Ontario all submitted letters supporting this study work.

  31. Resource Adequacy As has been past practice, the MPSC received comments in its annual summer capacity docket ( U-17792).  Several years ago in response to projected pending resource adequacy shortfalls, the Commission asked respondents to identify any near-term (summer 2016) and longer-term (5 years) issues on the system that would adversely affect reliability.  All of the state’s investor owned utilities and a myriad of other parties, including ITC, filed comments in the docket.  ITC’s comments reinforced the idea that the transmission system was strong and noted no anticipated issues on the transmission system over the periods in question.  ITC’s comments also spoke about the on -going need for information on pending generation retirements in order to plan the transmission system accordingly.

  32. Federal Regulatory Update 2016 Partners in Business Meeting October 12, 2016 Nathan Benedict Manager, Regulatory Strategy

  33. FERC Update Nelson Dewey (Wisconsin) Retirement Commissioner Commissioner Colette Honorable Cheryl LaFleur Term expires: 2017 Term expires: 2019 Chairman Commissioner Norman Bay Tony Clark Term expires: 2018 Left Commission in September

  34. ROE Update  1 st Complaint  Final decision issued September 28, 2016  FERC ordered:  Base ROE set at 10.32 percent Dubuque  Total ROE with incentives not to exceed 11.35 percent Retirement  September 28, 2016 effective date  2 nd Complaint  ALJ initial decision issued in June 2016  Final decision expected May 2017

  35. Phase-Angle Regulators In September, FERC issued an Order denying regional cost allocation for the Phase-Angle Regulators  In 2011, MISO and ITC made a joint filing proposing a regional cost allocation methodology to collect a portion of the cost for the Phase-Angle Regulators (PARs) from NYISO and PJM.  FERC’s order requires within:  30 days – compliance filing to change the MISO tariff  60 days – refund report

  36. Order 1000 Update In June, FERC held a technical conference on Competitive Transmission Development processes  Topics included:  Cost containment provisions  The relationship between competitive transmission development and transmission incentives  Other ratemaking issues  Regional and interregional transmission planning  Parties (including ITC) filed Post-Technical Conference comments on October 3

  37. Seams Update FERC ruled on NIPSCO’s complaint against the MISO -PJM interregional planning process  MISO must reduce from 345 kV to 100 kV its voltage threshold for interregional economic projects  MISO must also remove its $5M cost threshold  The regions must eliminate the third, separate interregional cost-benefit analysis  MISO and PJM made compliance filings in June  ITC and NIPSCO jointly protested, arguing that the FERC Order also applies to MISO’s seam with SPP

  38. Generator Interconnection Technical Conference held on AWEA’s proposed reforms to the pro forma Generator Interconnection Agreement  Topics included:  Current state of the Generator Interconnection Queue  Improving transparency and timing of Interconnection Studies  Interconnection issues for energy storage resources  MISO expected to file latest queue reforms in October

  39. Bonus Depreciation FERC ordered ITC Midwest to recalculate its Attachment O transmission revenue requirements to simulate the taking of bonus depreciation  Conforming changes were made to Facility Service Agreement calculations  Elected bonus depreciation in 2016 for all ITC operating companies  Effects of bonus depreciation included in 2017 projected rates  Continue to elect going forward  Issue is currently on appeal

  40. Break

  41. System Performance 2016 Partners in Business Meeting October 12, 2016 Vinit Gupta Director, Operations Engineering

  42. Reliability Performance • ITC participates in various Transmission Reliability Benchmarking Studies. • Studies provides insight into relative performance as well as performance trends over the years. • METC and ITCT have consistently performed in the top decile or top quartile.

  43. Sustained Outages per Circuit, All Voltages, Excludes External Cause, 2015 In this study, a Number of Sustained Outages per Circuit, All Voltages, Excludes External, 2015 total of 11 U.S. 0.30 Second systems Quartile Top Quartile 0.25 participated 0.20 comprising 30% of 0.15 U.S./Canada circuits. 0.10 Lower is better 0.05 0.00 ITC Transmission METC All Participants

  44. Sustained Outages per Circuit, 100 kV and Above, 2015 In another study, Average Circuit Outage Frequency - Sustained, 2015, 100kV and Above ITC benchmarked performance against 80% of U.S./Canada Outages per Circuit circuits and approximately 60 Lower is better systems. METC ITCT Q1 Q2 All Q3

  45. Reliability Performance Over Time Average Circuit Sustained Outages Trend 0.18 0.16 0.14 0.12 Outages Per Circuit 0.1 0.08 0.06 0.04 0.02 Lower is better 0 2011 2012 2013 2014 2015 METC ACOF (Exclude Ext) ITCT ACOF (Exclude Ext) 5 Year P10 (Top Decile) 5 Year Q1 (Top Quartile) 5 Year Q2 (Median) Linear (METC ACOF (Exclude Ext)) Linear (ITCT ACOF (Exclude Ext))

  46. Systematic Approach to Outage Reduction Outage cause analysis provides feedback for both the maintenance plan and capital improvements METC-PROPORTION OF SUSTAINED OUTAGES BY CAUSE 2011-2015 EQUIPMENT 9% SYSTEM-PROT EXTERNAL 5% 24% LINES 22% HUMAN 12% OTHER 1% WEATHER VEGETATION 12% 8% UNKNOWN LIGHTNING 3% 4%

  47. Systematic Approach to Outage Reduction ITCT-PROPORTION OF SUSTAINED OUTAGES BY CAUSE 2011-2015 EQUIPMENT SYSTEM-PROT LINES WEATHER 5% 7% 7% 3% LIGHTNING 4% VEGETATION 1% UNKNOWN 0% OTHER EXTERNAL 2% 67% HUMAN 4%

  48. Primary Frequency Control NERC Reliability Guideline

  49. Frequency Response Problem • Consider a sudden loss of 1000 MW generation. • Law of energy conservation requires the 1000 MW to be supplied to interconnect. • Power is provided by extracting it from the kinetic energy stored as inertial energy in the rotating mass of all of the synchronized turbine-generators and motors on the interconnection. • This results reduced speed of rotating equipment on interconnection resulting in reduced interconnection frequency.

  50. Frequency Response Problem • Any load that does not change with interconnection frequency (such as resistive loads) will not contribute to load damping or frequency response. • Generator governors sense the frequency decline and issue control action to increase mechanical energy to turbine which in turn increases turbine speed. • Until additional mechanical energy can be injected frequency continues to decline.

  51. Primary Frequency Control • Actions provided by prime mover governors in an interconnection to arrest and stabilize frequency in response to frequency deviations. Primary Frequency Control comes from local control. • As traditional rotating generators are replaced by electronically coupled resources, such as wind turbines and solar voltaic resources (which provide less overall system inertia), the speed of delivery of governor response should increase.

  52. NERC Reliability Guideline • In December 2015, NERC published a reliability guideline for Primary Frequency Control http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Forms/AllItems.aspx • In order to provide sustained primary frequency response, it is essential that the prime mover governor, plant controls and remote plant controls are coordinated. The lack of coordination between governor and load control systems will reduce primary frequency response, increase generator movement, and could increase grid instability.

  53. NERC Reliability Guideline • Recommended settings for Eastern Interconnection • Deadband: Not to exceed +/- 36 millihertz (59.964 Hz to 60.036 Hz) • Droop

  54. Capital Projects 2016 Partners in Business Meeting October 12, 2016 Jason Sutton Manager, Project Engineering

  55. Capital Projects Update ITC Transmission

  56. Genesee Pumping • Two new LDC interconnection requests by DTE to serve Genesee County Pumping. • Micah was completed & energized in the spring. • Klam construction is complete. • Anticipated commissioning is December 2016.

  57. Stone Pool Substation • Involves the construction of a new 120-13.2 kV substation with five 120kV breakers & the construction of a 0.3 mile 120 kV underground circuit. • Project Drivers: – Serve load being taken from the old PLD system and future load growth in the Midtown area. • Substation construction along with the 120 kV underground circuit work is expected to begin in October. • Commissioning is scheduled to occur in the spring of 2017.

  58. Capital Projects Update METC

  59. Battle Creek-Island Rd. Rebuild • ITC is rebuilding 23.9 miles from Battle Creek to Island Rd with 954 ACSR conductor, including equipment upgrades at Island Rd. • Project Drivers: – Poor performance which contributed to various outages. – Increased maintenance spending projections. – Projections of the occurrence of potential long-term sustained outages. • A line outage is scheduled for October and will run through the completion the work in February 2017.

  60. Blackstone-Marshall Rebuild • ITC will rebuild 34.51 miles from Marshall to Blackstone with 954 ACSR conductor, including the upgrade of the line entrance trainers and CT’s at Blackstone. • Project Drivers: – Potential increased failure rates due to age of infrastructure – Projected overloads. • The line is about 70% complete but was put back in service for the summer. • A line outage is scheduled for early October and will run through the remainder of the project to allow for the complete wreck out of the old line. • Anticipated commissioning is January 2017.

  61. Blackstone-Marshall Rebuild Maines Rd Switch Pole Marshall-Blackstone Rebuild

  62. Plum-Stover Rebuild • ITC will rebuild 9 miles from Plum to Stover with 954 ACSR conductor. • Project Drivers: – Projected overloads. • The rebuild is scheduled to begin in October with completion expected in January 2017.

  63. Weeds Lake • Involves the construction of a new 345-138 kV substation with three 345kV breakers and six 138kV breakers along with a 300/400/500 MVA, 345/138kV transformer. • Project Drivers: – Transformer overloads at Argenta when 2 of 3 transformers are out (shutdown plus contingency). • Substation construction was completed in April, 2016, but commissioning was delayed to this fall to avoid the lengthy commissioning process during high summer loads. • The 345 kV side of the substation is now commissioned. Commissioning of the 138 kV side of the substation is underway and will be completed by December.

  64. Weeds Lake

  65. Recently Completed Projects ITC Transmission Completed Drivers  Newburgh-Wayne 120 kV Reconductor 1/15/16 Relieve overloads due to the retirement of Trenton Channel units 7-8.  Temple Substation 2/19/16 Accommodate new loads including the new hockey stadium.  Southfield-Sunset 120 kV Rebuild 6/2/16 Relieve potential overloads.  Bloomfield-Hamlin 120 kV Rebuild 8/15/16 Relieve potential overloads.  J327 (Algonquin Power) Wind Farm 8/31/16 Connect new 150 MW wind farm. METC  Delhi-Tompkins 138 kV Rebuild 1/20/16 High structure failure rate.  North Belding-Marquette 138 kV Rebuild 2/15/16 Aging wood poles; high projected maintenance.  J392 Alpine Interconnection 6/10/16 New interconnection with Wolverine Power.

  66. Future Projects 2016 Partners in Business Meeting October 12, 2016 LaMont Durr Principal Engineer, Planning

  67. Overview • Project Overview • Project Types • ITC Assessment Process • Future Projects (submitted into the 2016 and 2017 MTEP processes)

  68. Project Overview ITC Planning Phase  ITC performs assessments each year to identify system enhancements necessary to meet future demands and keep the system reliable Regional Planning  Projects are submitted to Midcontinent Independent System Operator (MISO) for open and transparent regional review Design  Once identified in regional plan, and approved for construction by ITC management, design commences Construction  Final step before operation

  69. Project Types Baseline Reliability Projects Interconnection Projects  Projects that mitigate ITC Planning Criteria  Projects that are initiated by violations “outside” Entities  Load Interconnection Projects  Thermal Overloads, voltage, stability or short circuit violations  Generation Interconnection Projects Asset Renewal Projects  Projects to replace existing ITC equipment  Asset renewal drivers are combinations of the following:  Equipment maintenance history  Equipment end-of-life identification  Operating performance (outage history)  Reliability exposure/impact

  70. ITC Assessment Process ITC Assessment Process (as required by NERC TPL-001-4)  Three time periods studied each year (2-year, 5-year & 10 years out)  Peak, off peak and light load studies  Typical sensitivities performed:  Ludington generating and pumping  Various transactions in and out of Canada  Average (50/50) and above average (70/30) load forecasts used  Thermal (flow on line vs. capacity of line) and voltage analysis performed  System studied with all transmission elements in service and with combinations of one or more elements out  Identify system constraints following ITC Planning Criteria which adheres to mandatory NERC Transmission Planning Standards  Plans developed for projected criteria violations and shared with external stakeholders via the MISO Transmission Expansion Planning (MTEP) process  Previously planned projects restudied for continued need

  71. Custer – Monroe 120 kV Rebuild Baseline Reliability Project  Circuits overloads for various N-1 and N- 2 contingencies (NERC categories P1 thru P7) Custer – Monroe Rebuild  Outages limit generation from the Monroe units Rebuild approximately 3 miles of the Custer to Monroe 120 kV circuit Transmission line located in Monroe county Projected In Service Date – December 2019

Recommend

More recommend