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

2016 Partners in Business Meeting October 12, 2016

Welcome

2016 Partners in Business Meeting October 12, 2016

Simon S. Whitelocke

Vice President, ITC Holdings Corp., and President, ITC Michigan

Connecting Energy Infrastructure

The Value of ITC

• Changing generation mix
• Clean Power Plan
• Distributed generation/Microgrids
• Demand response/efficiency programs
• Physical and cyber security
• Rate concerns

Our common purpose: Serving electricity customers Our common issues: A changing energy landscape

Common Purpose, Common Issues

Deliver customer benefits unique to ITC’s business model:

• Improve and maintain system reliability
• Reduce system congestion
• Expand access to competitive energy markets
• Facilitate interconnection of new generation
• Lower overall cost of delivered energy

ITC’s Commitment Since Inception

Fortis’ Operations

Regulated Gas Regulated Electric Long-Term Contracted Generation AB BC ON NY PEI NL AZ Turks and Caicos Islands Grand Cayman Belize

• Fortis Inc. and ITC have entered into an agreement and plan of

merger pursuant to which Fortis will acquire ITC.

• Fortis is a leader in the North American electric and gas utility
• business. Its regulated utilities serve more than three million

customers across Canada and in the United States and the Caribbean.

• ITC will operate as a stand-alone company under Fortis.
• Stable rates: transaction not expected to have an adverse impact

to customers, service or rates.

• Continued focus on customers.
• Employees retained, community presence maintained.
• Proven management team.
• Expanded platform for long-term grid development.

Data as of May 2016

Fortis – ITC Transaction

Changes in the Energy Industry Impact Transmission Locally

Generation:

• Many base load plants will be retired
• New forms of generation (wind, solar, biofuels, etc.)

coming online New Demands / Uses:

• Demand response, efficiency programs, electric vehicles

Policy Focus:

• Increased attention to grid security, environment

and creation of related energy policies

• Changes outside the state affect Michigan
• Proposed revisions to the 2008 laws have a focus on energy waste and

customer choice

A robust transmission grid is needed to support these changes

The Challenge in Michigan

Challenges

Michigan Economy

Michigan Economy

M A R K E T E F F I C I E N C Y R E N E WA B L E E N E R G Y R E L I A B L E E L E C T R I C I T Y

Since our formation in 2003, ITC has made significant investments here in Michigan to build a reliable grid that supports new generation sources, more affordable electricity and greater economic growth.

ITC Impact

Modernizing and Maintaining the Transmission Grid

ITC has steadily reduced the average number of outages on the three transmission systems we have acquired beginning in 2003.

Value of ITC: Reliable Electricity

• ITC has connected more than 5,200 megawatts of

wind energy production capacity to the grid in Iowa, Minnesota, Michigan, Kansas and Oklahoma.

• Customer benefit: Our investments in

transmission projects across the ITC Michigan and ITC Midwest footprints enabled wind farms to be

• ptimally located.

This resulted in customer savings of $587 million between 2008 and 2014 in avoided renewable energy capital costs, according to ICF.

Value of ITC: Renewable Energy

Breakout of customer savings between 2008 and 2014 in avoided renewable energy capital costs, according to ICF International:

• Michigan projects saved customers

approximately $250 million in avoided renewable energy production costs.

Value of ITC: Renewable Energy

Breakout of customer savings between 2010 and 2015 in reduced energy production costs in the MISO region due to decreased system congestion, according to ICF:

• Savings to Michigan customers: $111 million

Value of ITC: Market Efficiency

Economy and Jobs

Predicted transmission investment of $12 to $16 billion in the U.S. from 2010 to 2030 is estimated to stimulate:

• $30 to $40 billion in annual economic activity.
• Support 150,000 to 200,000 full-time jobs each

year over the 20-year period.

Study: “Employment and Economic Benefits of Transmission Infrastructure Investment in the U.S. and Canada” – The Brattle Group/WIRES, 2011

Value of Transmission: Other Perspectives

Economy and Jobs - Michigan

ITC’s transmission investments and operations support the economy and jobs in Michigan:

• In 2014, ITC Michigan’s operating expenses helped

support 3,000 direct and indirect jobs, and $270 million in spending throughout the state’s economy.

• About 70% of ITC Michigan’s capital investments

from 2007-2014 remained in the state, supporting employees and vendors.

Source: Anderson Economic Group analysis of data sourced from ITC Holdings Corp.

Value of Transmission: Other Perspectives

Today: Traditional RTO planning is focused primarily on reliability and incremental fixes. Call for reform: Rapidly evolving energy landscape – shift in generation mix, emerging technology and environmental regulation – requires new approach. What’s needed: More proactive, anticipatory approach to transmission planning at RTOs to address long-term uncertainties. What’s at stake: Transmission planning reforms could save electricity customers as much as $47 billion annually.

Whitepaper: “Well-Planned Electric Transmission Saves Customer Costs: Improved Transmission Planning is Key to the Transition to a Carbon-Constrained Future.” – Prepared by economists at The Brattle Group, 2016

Electric transmission can save customers billions in transition to a low-carbon future.

Planning Reform – WIRES Report

Toward a Better, Stronger Grid

Common Purpose: Ensuring the connection between consumers and the energy they need is efficient, reliable and cost-effective. Common Issues: Evolving energy landscape. Transmission’s backbone role in electricity delivery must be factored into planning the grid of the future. ITC’s commitment:

• Good stewards of the grid
• Respect for the environment
• Assess development opportunities from the perspective of

what is good for customers and the grid

Utilities | Regulators | Communities | Planners | Customers | Stakeholders

Our Partners in Business

ITC’s focus on transmission and grid development drives operational excellence and delivers superior value for customers, communities and other stakeholders.

Thank You

Chairman and Chief Executive Officer General Sports and Entertainment, LLC

Andrew D. Appleby

Break

2016 Partners in Business Meeting October 12, 2016

ITCTransmission and Michigan Electric Transmission Company 2017 Projected Rates

Zach Paquette

Principal Regulatory Analyst

Agenda

• Discuss the 2017 Projected Formula Rate posting
• Walk through the timeline and calculation of the Projected

2017 Revenue Requirement

• For each company discuss the calculation and key drivers of

the Projected Rates

• Describe the next steps for Stakeholders

Contents of the 2017 Projected Rate Posting

On August 31, 2016, ITCTransmission and METC posted the 2017 projected rates and supporting documents on the MISO and OASIS websites.

Documents included in the posting:

• Workable populated Att. O Rate Template
• Underlying work papers, including:
• Attachment O, GG, MM Workpapers
• Schedule 1 Expense Projected Rates
• Accounting disclosures

On October 7, 2016 ITCTransmission and METC reposted 2017 projected rates to reflect the order in EL14-12.

Formula Rate Protocol Cycle

April July October January April

Projected Rate year

(Jan 1 – Dec 31)

Informational* Filing

(Mar 15)

FERC Form 1

(Apr 18)

Prior year True-Up

(Jun 1)

Projected Rate for Next year

(Sep 1)

Informational Exchange Period

(Jun 1 – Dec 1)

Informal Challenge Due

(Jan 31)

Formal Challenge Due

(Apr 15)

Protocols Open Review Process Rate Posting Timeline

* Includes complete True-Up and projected rate postings published the prior year.

FERC ordered all MISO Transmission Owners to lower their Base ROE and established a maximum ROE Transmission Owners are allowed to charge.

Base ROE:

10.32%

Applicable Adders

Independence RTO

Max ROE

11.35% The FERC Authorized ROE is in effect from September 27, 2016 going forward (until further FERC decisions). Charges during the 15 month refund period (Nov 12, 2013 – Feb 11, 2015) are subject to refund and will be refunded as a credit to customer bills in 2017.

FERC ROE Order

ITCTransmission

2017 Attachment O - Projected Formula Rate

Base ROE:

10.32%

Independence Adder RTO Adder

150 BP

Capped ROE

11.35% Impacts of ROE Change to 2017 Projected Rates

9/1 Posting 10/7 Posting WACC 10.23% 8.71% Return on Rate Base $172.7M $147.1M Income Taxes $90.7M $74.4M Credits and Offset $160.2M $141.1M

Rate Effects of the New ROE

Steps to Derive the Projected 2017 Net Revenue Requirement

2017 Projected Rate Base

$1,688,570,538

Weighted Average Cost of Capital

8.71%

Step 1 Allowed Return

$147,110,886

Operating Expenses + Income Taxes

$254,094,539

Step 2 Projected 2017 Revenue Req.

$260,061,009

2015 True-Up Under Recovery

$3,982,460

Step 4 Projected 2017 Net Revenue Requirement

$293,034,703

Step 5 Gross Revenue Requirement

$401,205,425

Revenue Credits/Offsets

$141,144,416

Step 3 PARS Refund

$28,991,234

ITCTransmission’s 2017 Network Rate is $2.856/kW-Mo

Represents increases from 2016 to 2017 Projected rates Represents decreases from 2016 to 2017 Projected rates

* Total may not reconcile to 2016 projected rate change due to rounding

PARS Refund

$29M | Increase due to refund of previous PARS credits to PJM/NYISO

Change in True-Up Adjustment

$11M over recovery in 2014 | $4M under recovery in 2015

Higher Plant Balances

$161M in Capital Additions | Stone Pool, Fitz Transformer

Fewer Credits and Offsets

$10M Fewer MM/GG Credits | $5M PARS

ROE Order

$(23)M | Lower Return on Rate Base, Income Taxes

Deferred Taxes

$(100)M | Election of Bonus Depreciation $2.540 $2.856

Pars Refund TU Net Plant Offsets Depreciati

• n

… A&G/OM ROE Change Deferred Taxes

$0.282 $0.168 $0.164 $0.155 $0.056 $0.019 $(0.399) $(0.128)

Key Drivers

Accounting Change – Cost Allocation for Shared Assets

• During 2016, ITC made refinements to the method of allocating the costs
• f 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.

METC

2017 Attachment O - Projected Formula Rate

Base ROE:

10.32%

Independence Adder RTO Adder

150 BP

Capped ROE

11.35% 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

Rate Effects of the New ROE

Steps to Derive the Projected 2017 Net Revenue Requirement

2017 Projected Rate Base

$1,335,635,609

Weighted Average Cost of Capital

8.45%

Step 1 Allowed Return

$112,832,851

Operating Expenses + Income Taxes

$213,296,008

Step 2 Projected 2017 Revenue Req.

$230,439,239

2015 True-Up Over Recovery

$(2,874,558)

Step 4 Projected 2017 Net Revenue Requirement

$227,564,681

Step 5 Gross Revenue Requirement

$326,128,859

Revenue Credits/Offsets

$95,689,620

Step 3

METC’s 2017 Network Rate is $2.873/kW-Mo

Represents increases from 2016 to 2017 Projected rates Represents decreases from 2016 to 2017 Projected rates

Higher Plant Balances

$223M in Capital Additions | Battle Creek rebuild, Ludington Breaker Replacement

Change in True-Up Adjustment

$7M | Lower over-recovery

Higher Depreciation, A&G, O&M and Tax Expenses

$5M Taxes | $3M Depreciation Expense | $3M A&G

ROE

$(9)M | Lower Return on Rate Base | Lower Income taxes | Lower Credits/Offsets

Deferred Taxes

$(89)M | Election of Bonus Depreciation $2.776 $2.873

Net Plant TU TOIT Depreciation Expense Offsets A&G O&M ROE Deferred Taxes CWC/MS

$0.323 $0.109 $0.044 $0.043 $0.043 $0.035 $(0.342) $(0.145) $(0.013)

Key Drivers

Accounting Change – Cost Allocation for Shared Assets

• During 2016, ITC made refinements to the method of allocating the costs
• f 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

• 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

Next Steps

ITCTransmission

Appendix

ITCT’s Projected Rate Increased by $0.316

Description 2017 Projected 2016 Projected Increase/ (Decrease) Variance %

Projected Gross Plant in Service $2,701,029,380 $2,540,041,000 $160,988,380 Accumulated Depreciation 787,058,880 755,009,000 32,049,880 Deferred Income Taxes (293,699,463) (192,744,863) (100,954,600) 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

Step 1: Calculation of ITCTranmsission’s Rate Base

Rate Base Components 2017 Projected Amount 2016 Projected Amount Increase/ (Decrease) Variance % 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%

Overview of 2017 Planned Capital Additions

Dubuque Retirement Marshalltown Construction Nelson Dewey (Wisconsin) Retirement

• The development of the annual Rate Base begins with a

forecast of planned capital additions.

• The ITCTransmission 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.

2017 Planned Transfers to Plant in Service

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

Grand Total for ITCTransmission's Planned Transfers to Plant in Service

General Plant Facilities $1,164,182 Information Technology 10,965,509 Security Improvements 581,356 Contractors 1,511,525 Total General Plant $14,222,572

$132,691,816

Step 2: Calculation of ITCTransmission’s Projected Rate of Return and Allowed Return

Cost of Capital Weight Projected Cost 2017 Projected WACC 2016 Projected WACC Increase/ (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)% Allowed Return 2017 Projected Amount 2016 Projected Amount Increase/ (Decrease) Increase/ (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

Step 3: ITCTransmission’s Projected Operating Expenses and Total Gross Revenue Requirement

Operating Expense 2017 Projected Amount 2016 Projected Amount Increase/ (Decrease) Variance % 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

Step 4: ITCTransmission’s Projected Revenue Requirement after Credits & Offsets

Revenue Requirement & Revenue Credits/Offsets 2017 Projected Amount 2016 Projected Amount Increase/ (Decrease) Variance % 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

Step 5: ITCTransmission’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

METC

Appendix

METC’s Projected Rate Increased by $0.097

Descriptions 2017 Projected 2016 Projected Increase/ (Decrease) Variance %

Projected Gross Plant in Service $1,977,520,490 $1,754,324,000 $223,196,490 Accumulated Depreciation 456,283,810 433,490,000 22,793,810 Deferred Income Taxes (280,869,579) (191,115,211) (89,754,368) ADIT Deferral/M&S/Prepayment/CWC 95,268,508 103,388,656 (8,120,148)

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%

Credits/Offsets (Sch. 26, 26A, PTP, rents) ($95,689,620) ($99,086,614) $3,396,994 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

Step 1: Calculation of METC’s Rate Base

Rate Base Components 2017 Projected Amount 2016 Projected Amount Increase (Decrease) Variance % 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

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.

2017 Planned Transfers to Plant in Service

MISO ID Project Name Projected Amount Reliability - Infrastructure Improvements 4143 Verona - Marshall 138KV TE Upgrade $26,870 4147 Battle Creek Island Road 138KV Rebl 19,980,642 4150 Verona-Argenta 138kV TE upgrade 153,301 4510 Battle Creek to Morrow #1 138kV Sag 284,499 4539 Hemphill Control Relocation 3,776,437 4542 Morrow Control Relocation 730,080 4556 Blackstone 138 kV Second Bus-Relay 783,842 4557 Croton to Four Mile 138 kV Circuit 197,130 8170 Leoni to Page Ave 138kV Relay 77,175 9945 Breaker Replacement Program - METC 10,369,406 9945 METC Relay Betterment Project 6,480,117 9945 METC Wood Pole Replacement Program 9,919,608 9945 Potential Device Replacement Progra 1,271,401 9945 Disconnect Switch Replacements 3,424,851 9945 METC NERC Protection Compliance 1,195,618 9945 Mio 138kV Switch Replacement 688,573 9945 Transformer Replacement Program 4,782,471 9945 Miscellaneous - Reliability/Infrast 2,296,026 9972 Four Mile Control Relocation 3,555,859 9975 Verona Control Relocation 2,964,029 10286 Campbell 138kV remv breaker 588 89,671 METC Rights of Way Acquisition 3,586,853 Engineering Design 597,809 ERUC- Reactionary Capital Work 597,809 T-Value Mitigation to lower (MAD) 1,209,208 Total for Reliability - Infrastructure Improvements $79,039,286 MISO ID Project Name Projected Amount Reliability - System Capacity Improvements 3599 Palisades 345KV Station Equipment $753,800 3926 Dort 138kV Terminal Equipment Upgrd 244,440 4154 North Belding 138kV Terminal Equipm 109,671 4505 Bass Creek-Sternberg 138kV Sag Rem 249,375 4509 Argenta-Battle Creek 345kV Sag Rem 2,474,929 4524 Emmet-Livingston 138kV Sag Remediat 181,897 8067 Beals Road 138kV Station Equi Upgrd 398,994 8078 Donaldson Creek 33.3 MVAR Capacitor 414,194 8080 Coldwater 138kV Capacitor 3,880,910 8096 Roosevelt-Gaines 345 kV Sag Remed 383,475 8109 Gaylord-Livingston 138kV Sag Remed 51,179 8119 Pole Top Switch Additions 3,586,853 8127 Ludington 345 kV Breaker Replacemnt 8,527,045 8144 Meyer 345-138kV Station 4,484 8460 Grand Blanc BOC Hemphill 138kV Sag 76,393 8461 Cobb-Sternberg 138kV Sag Remediate 306,976 8540 Claremont-Layton 138kV Sag Remediat 491,787 9945 Transformer Refurbish Program 478,247 9945 METC Misc Line Equip Replacement 3,725,201 10384 Verona-Barnum Creek Jct 138kV Sag 1,078,303 METC NERC CIP-006 717,371 Total for Reliability - System Capacity Improvements $28,135,523 MISO ID Project Name Projected Amount Customer Connections 2486 Haakwood Substation Interconnection $286,948 4537 Faussett CE Interconnection 408,801 4537 Benston 138kV GOAB Installation 285,677 4537 Laperell Interconnetion 286,948 9422 Coldwater Interconnection 10,972,787 Total for Customer Connections $12,241,161

Grand Total for METC's Planned Transfers to Plant in Service $126,065,163

General Plant Facilities - METC $597,228 METC Station Security 489,757 Contractors - METC 5,562,208 Total General Plant $6,649,192

Step 2: Calculation of METC’s Projected Rate of Return and Allowed Return

Cost of Capital Weight Projected Cost 2017 Projected WACC 2016 Projected WACC Increase/ (Decrease) 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)% Allowed Return 2017 Projected Amount 2016 Projected Amount Increase/ (Decrease) Variance % Rate Base $ 1,335,635,609 $ 1,233,107,445 x Rate of Return (above) 8.45% 9.87% = Allowed Return* $112,832,851 $121,690,507 $(8,857,656) (7.28)%

* Totals may not reconcile due to rounding

Step 3: METC’s Projected Operating Expenses and Total Gross Revenue Requirement

Operating Expense 2017 Projected Amount 2016 Projected Amount Increase/ (Decrease) Variance % 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

Step 4: METC’s Projected Revenue Requirement after Credits & Offsets

Revenue Requirement & Revenue Credits/Offsets 2017 Projected Amount 2016 Projected Amount Increase/ (Decrease) Variance % 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

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

2016 Partners in Business Meeting October 12, 2016

Michigan Regulatory Update

Kwafo Adarkwa

Manager, Regulatory Strategy

Overview

• New MPSC Commissioner
• MISO Study Request
• Resource Adequacy

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

• ver $22 billion in bond financings, primarily for the State of Michigan,

Michigan State Building Authority, Michigan Finance Authority and

• ther 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.

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.

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.

2016 Partners in Business Meeting October 12, 2016

Federal Regulatory Update

Nathan Benedict

Manager, Regulatory Strategy

FERC Update

Nelson Dewey (Wisconsin) Retirement

Commissioner Cheryl LaFleur Term expires: 2019 Chairman Norman Bay Term expires: 2018 Commissioner Colette Honorable Term expires: 2017 Commissioner Tony Clark Left Commission in September

ROE Update

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

Dubuque Retirement

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

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

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

Generator Interconnection

• 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 Technical Conference held on AWEA’s proposed reforms to the pro forma Generator Interconnection Agreement

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

Break

2016 Partners in Business Meeting October 12, 2016

System Performance

Vinit Gupta

Director, Operations Engineering

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.

Lower is better

0.00 0.05 0.10 0.15 0.20 0.25 0.30 ITC Transmission METC All Participants

Number of Sustained Outages per Circuit, All Voltages, Excludes External, 2015

Second Quartile Top Quartile

In this study, a total of 11 U.S. systems participated comprising 30% of U.S./Canada circuits.

Sustained Outages per Circuit, All Voltages, Excludes External Cause, 2015

Lower is better

In another study, ITC benchmarked performance against 80% of U.S./Canada circuits and approximately 60 systems.

Sustained Outages per Circuit, 100 kV and Above, 2015

METC ITCT Q1 Q2 All Q3 Outages per Circuit

Average Circuit Outage Frequency - Sustained, 2015, 100kV and Above

Reliability Performance Over Time

0.02 0.04 0.06 0.08 0.1 0.12 0.14 0.16 0.18 2011 2012 2013 2014 2015

Outages Per Circuit

Average Circuit Sustained Outages Trend

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))

Lower is better

Systematic Approach to Outage Reduction

Outage cause analysis provides feedback for both the maintenance plan and capital improvements

EQUIPMENT 9% SYSTEM-PROT 5% LINES 22% WEATHER 12% LIGHTNING 4% UNKNOWN 3% VEGETATION 8% OTHER 1% HUMAN 12% EXTERNAL 24%

METC-PROPORTION OF SUSTAINED OUTAGES BY CAUSE 2011-2015

Systematic Approach to Outage Reduction

EQUIPMENT 5% SYSTEM-PROT 7% LINES 7% WEATHER 3% LIGHTNING 4% UNKNOWN 0% VEGETATION 1% OTHER 2% HUMAN 4% EXTERNAL 67%

ITCT-PROPORTION OF SUSTAINED OUTAGES BY CAUSE 2011-2015

NERC Reliability Guideline

Primary Frequency Control

• 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.

Frequency Response Problem

• Any load that does not change with interconnection frequency

(such as resistive loads) will not contribute to load damping

• r 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.

Frequency Response Problem

• 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.

Primary Frequency Control

• 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.

NERC Reliability Guideline

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

NERC Reliability Guideline

2016 Partners in Business Meeting October 12, 2016

Capital Projects

Jason Sutton

Manager, Project Engineering

Capital Projects Update

ITC Transmission

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.

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.

Capital Projects Update

METC

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

• utages.
• A line outage is scheduled for October

and will run through the completion the work in February 2017.

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.

Blackstone-Marshall Rebuild

Marshall-Blackstone Rebuild Maines Rd Switch Pole

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.

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.

Weeds Lake

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.

2016 Partners in Business Meeting October 12, 2016

Future Projects

LaMont Durr

Principal Engineer, Planning

Overview

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

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

Project Types

Baseline Reliability Projects

• Projects that mitigate ITC Planning Criteria

violations

• Thermal Overloads, voltage, stability or short

circuit violations

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

Interconnection Projects

• Projects that are initiated by

“outside” Entities

• Load Interconnection Projects
• Generation Interconnection Projects

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

Custer – Monroe 120 kV Rebuild

Baseline Reliability Project

• Circuits overloads for various N-1 and N-

2 contingencies (NERC categories P1 thru P7)

• 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

Custer – Monroe Rebuild

Whiting – Custer 138 kV Rebuild

Baseline Reliability Project

• Circuits overloads for various N-1 and N-2

contingencies (NERC categories P1 thru P7)

• Outages limit generation from the Monroe

units

• Existing circuit limit deliverability of

generation interconnection project J419 (100 MW solar plant in Washtenaw county)

Rebuild approximately 10 miles of the Whiting to Custer 138 kV circuit Transmission line located in Monroe county Projected In Service Date – June 2018

Whiting – Custer Rebuild

Garfield – Hemphill 138 kV Rebuild

Baseline Reliability Project

• Circuits overloads for various N-2

contingencies (NERC categories P6 and P7)

• Outages limit generation from the Karn

units

Rebuild approximately 10 miles of the Garfield – Hemphill 138 kV circuit Transmission line located in Genesee county Projected In Service Date – December 2019

Garfield – Hemphill Rebuild

Karn – Saginaw River 138 kV Rebuild

Baseline Reliability Project

• Circuits overloads for various N-2

contingencies (NERC category P6)

• Outages limit generation from the Karn

units

Rebuild approximately 3 miles of the Karn to Saginaw River 138 kV circuit Transmission line located in Bay and Saginaw counties Projected In Service Date – December 2019

Karn – Saginaw River Rebuild

Bell Rd. – Cornell 138 kV Rebuild

Baseline Reliability Project

• Circuits overloads for various N-2

contingencies (NERC category P6)

• Outages limit generation from the Karn

units

Rebuild approximately 4 miles of the Bell Rd. to Cornell 138 kV circuit Transmission line located in Saginaw and Shiawassee counties Projected In Service Date – December 2019

Bell Rd. – Cornell Rebuild

Buck Creek 138 kV Switching Station

Baseline Reliability Project

• Thermal and voltage issues for various N-

1 and N-2 contingencies (NERC categories P1 thru P7)

• Outages limit flow into the heavily loaded

Grand Rapids area

Expand the Buck Creek 138 kV to by cutting the Beals – Hazelwood 138 kV circuit into it Station located in Kent County Projected In Service Date – December 2020 Thermal Issues Voltage Issues Beals – Hazelwood circuit Buck Creek

Batavia – Barnum Creek Jct. 138 kV Rebuild

Asset Renewal Project

• Circuit towers are more than 60 years old which

lends itself to higher maintenance

• High outage history – poor operating performance
• Circuit is expected to be highly loaded in future

studies

• Circuit ranked in the top 20 circuits identified for

rebuild considering outage history, age, condition and circuit importance

Rebuild approximately 22 miles of the Batavia to Barnum Creek Jct. 138 kV circuit Transmission lines located in Branch and Calhoun counties Projected In Service Date – December 2020

Batavia – Barnum Creek Jct. Rebuild

Coldwater Interconnection Project

Load Interconnection Project Two Phase Project

• First Phase – Build new 138 kV station

(Newton), connect 138 kV line from Newton to Michigan Ave 138 kV, convey existing 138 kV circuit from Coldwater to Michigan Ave to METC, and rebuild the Verona to Barnum Creek Jct. 138 kV circuit

• Second Phase – Build new 138 kV station

(Wagner) and connect 138 kV line from Wagner 138 kV to Newton 138 kV

Project located in the Branch and Calhoun counties Projected In Service Date

• First Phase – April 2017
• Second Phase – December 2018

Coldwater Phase 1

Michigan Ave 138 kV Newton 138 kV Wagner 138 kV

Coldwater Phase 2 Verona – Barnum Creek Rebuild

Included in Phase 1

Other Load Interconnection Projects

Macomb County

• Skylark 120 kV

Wayne County

• Cyril 120 kV
• Explorer 120 kV
• Mercury 120 kV

Kent County

• Pyramid 138 kV

Skylark 120 kV Mercury & Explorer 120 kV Cyril 120 kV Pyramid 138 kV

Generation Interconnection Projects

All Generators that have executed GIAs

• J301 – 101 MW wind (Huron County)
• J308 – 301 MW wind (Huron County)
• J321 – 151 MW wind (Sanilac County)
• J340 – 100 MW wind (Huron County)
• J419 – 100 MW solar (Washtenaw County)

J301 J308 J321 J340 J419

2016 Partners in Business Meeting October 12, 2016

2016 ITC Stakeholder Relations Customer Survey Results

Karen Hilton

Partner, ScottMadden, Inc.

Next Up:

• Afternoon Networking
• Golf & Boxed Lunch
• Dining Room and MSU Athletics Tour

Thank You For Attending!