ITC Holdings Corp. (Form: 10-Q, Received: 11/04/2016 06:10:36)

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Accelerated filer o

Non-accelerated filer o

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)



þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Quarterly Period Ended September 30, 2016



o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-32576

ITC HOLDINGS CORP.

(Exact Name of Registrant as Specified in Its Charter)



Michigan (State or Other Jurisdiction of Incorporation or Organization)		32-0058047 (I.R.S. Employer Identification No.)

27175 Energy Way

Novi, MI 48377

(Address Of Principal Executive Offices, Including Zip Code)

(248) 946-3000

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the Registrant is a shell company ( as defined in Rule 12b-2 of the Exchange Act ). Yes o No þ

All shares of outstanding common stock of ITC Holdings Corp. are held by its parent company, ITC Investment Holdings Inc., which is an indirect subsidiary of Fortis Inc. and GIC Private Limited. There were 224,203,112 shares of common stock, no par value, outstanding as of November 3, 2016 .

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ITC Holdings Corp.

Form 10-Q for the Quarterly Period Ended September 30, 2016

INDEX



	Page
Part I. Financial Information	5
Item 1. Financial Statements	5
Condensed Consolidated Statements of Financial Position (Unaudited)	5
Condensed Consolidated Statements of Operations (Unaudited)	6
Condensed Consolidated Statements of Comprehensive Income (Unaudited)	7
Condensed Consolidated Statements of Cash Flows (Unaudited)	8
Notes to Condensed Consolidated Financial Statements (Unaudited)	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3. Quantitative and Qualitative Disclosures About Market Risk	41
Item 4. Controls and Procedures	42
Part II. Other Information	42
Item 1. Legal Proceedings	42
Item 1A. Risk Factors	42
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds	46
Item 5A. Other Information	46
Item 6. Exhibits	47
Signatures	48
Exhibit Index

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DEFINITIONS

Unless otherwise noted or the context requires, all references in this report to:

ITC Holdings Corp. and its subsidiaries


•	“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;


•	“ITC Grid Development” are references to ITC Grid Development, LLC, a wholly-owned subsidiary of ITC Holdings;


•	“ITC Holdings” are references to ITC Holdings Corp. and not any of its subsidiaries;


•	“ITC Interconnection” are references to ITC Interconnection LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;


•	“ITC Midwest” are references to ITC Midwest LLC, a wholly-owned subsidiary of ITC Holdings;


•	“ITCTransmission” are references to International Transmission Company, a wholly-owned subsidiary of ITC Holdings;


•	“METC” are references to Michigan Electric Transmission Company, LLC, a wholly-owned subsidiary of MTH;


•	“MISO Regulated Operating Subsidiaries” are references to ITCTransmission, METC and ITC Midwest together;


•	“MTH” are references to Michigan Transco Holdings, LLC, the sole member of METC and an indirect wholly-owned subsidiary of ITC Holdings;


•	“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest and ITC Great Plains together; and


•	“We,” “our” and “us” are references to ITC Holdings together with all of its subsidiaries.

Other definitions


•	“Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS Energy Corporation;


•	“DTE Electric” are references to DTE Electric Company, a wholly-owned subsidiary of DTE Energy Company;


•	“FERC” are references to the Federal Energy Regulatory Commission;


•	“Fortis” are references to Fortis Inc.;


•	“FortisUS” are references to FortisUS Inc., an indirect subsidiary of Fortis;


•	“FPA” are references to the Federal Power Act;


•	“GIC” are references to GIC Private Limited;


•	“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;


•	“kV” are references to kilovolts (one kilovolt equaling 1,000 volts);


•	“kW” are references to kilowatts (one kilowatt equaling 1,000 watts);


•	“LIBOR” are references to the London Interbank Offered Rate;


•	“Merger” are references to the merger with Fortis, whereby ITC Holdings merged with Merger Sub and subsequently became an indirect subsidiary of FortisUS;


•	“Merger Agreement” are references to the agreement between Fortis, FortisUS, Merger Sub and ITC Holdings for the Merger;


•	“Merger Sub” are references to Element Acquisition Sub, Inc., an indirect subsidiary of Fortis that merged into ITC Holdings in the Merger;


•	“MISO” are references to the Midcontinent Independent System Operator, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Midwestern United States and Manitoba, Canada, and of which ITCTransmission, METC and ITC Midwest are members;


•	“NERC” are references to the North American Electric Reliability Corporation;


•	“NYSE” are references to the New York Stock Exchange;

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•	“RTO” are references to Regional Transmission Organizations; and


•	“SPP” are references to Southwest Power Pool, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the South Central United States, and of which ITC Great Plains is a member.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)



	September 30,			December 31,
(in thousands, except share data)	2016			2015
ASSETS
Current assets
Cash and cash equivalents	$	8,938		$	13,859
Accounts receivable	137,942			104,262
Inventory	28,564			25,777
Regulatory assets	22,262			14,736
Prepaid and other current assets	13,403			10,608
Total current assets	211,109			169,242
Property, plant and equipment (net of accumulated depreciation and amortization of $1,562,532 and $1,487,713, respectively)	6,555,627			6,109,639
Other assets
Goodwill	950,163			950,163
Intangible assets (net of accumulated amortization of $30,736 and $28,242, respectively)	43,525			45,602
Regulatory assets	238,213			233,376
Deferred financing fees (net of accumulated amortization of $1,853 and $1,277, respectively)	1,885			2,498
Other	51,165			44,802
Total other assets	1,284,951			1,276,441
TOTAL ASSETS	$	8,051,687		$	7,555,322
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	139,045		$	124,331
Accrued compensation	26,788			24,123
Accrued interest	45,656			52,577
Accrued taxes	28,748			44,256
Regulatory liabilities	137,014			44,964
Refundable deposits from generators for transmission network upgrades	6,295			2,534
Debt maturing within one year	185,825			395,105
Other	24,030			31,034
Total current liabilities	593,401			718,924
Accrued pension and postretirement liabilities	65,353			61,609
Deferred income taxes	964,588			735,426
Regulatory liabilities	251,187			254,788
Refundable deposits from generators for transmission network upgrades	32,975			18,077
Other	29,738			23,075
Long-term debt	4,298,329			4,034,352
Commitments and contingent liabilities (Notes 4 and 11)
STOCKHOLDERS’ EQUITY
Common stock, without par value, 300,000,000 shares authorized, 153,432,671 and 152,699,077 shares issued and outstanding at September 30, 2016 and December 31, 2015, respectively	849,210			829,211
Retained earnings	969,761			875,595
Accumulated other comprehensive (loss) income	(2,855		)	4,265
Total stockholders’ equity	1,816,116			1,709,071
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	8,051,687		$	7,555,322

See notes to condensed consolidated financial statements (unaudited).

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except per share data)	2016			2015			2016			2015
OPERATING REVENUES	$	253,451		$	273,189		$	831,628		$	820,734
OPERATING EXPENSES
Operation and maintenance	30,326			32,721			82,533			88,309
General and administrative	35,752			33,677			130,922			107,064
Depreciation and amortization	39,599			36,890			117,840			106,903
Taxes other than income taxes	22,645			20,463			68,444			61,629
Other operating (income) and expenses — net	(293		)	(206		)	(839		)	(675		)
Total operating expenses	128,029			123,545			398,900			363,230
OPERATING INCOME	125,422			149,644			432,728			457,504
OTHER EXPENSES (INCOME)
Interest expense — net	55,843			51,398			158,064			150,070
Allowance for equity funds used during construction	(10,002		)	(6,421		)	(26,442		)	(21,434		)
Other income	(408		)	(384		)	(1,149		)	(804		)
Other expense	1,254			1,372			3,635			2,969
Total other expenses (income)	46,687			45,965			134,108			130,801
INCOME BEFORE INCOME TAXES	78,735			103,679			298,620			326,703
INCOME TAX PROVISION	29,097			38,106			114,019			121,662
NET INCOME	$	49,638		$	65,573		$	184,601		$	205,041
Basic earnings per common share	$	0.32		$	0.42		$	1.21		$	1.32
Diluted earnings per common share	$	0.32		$	0.42		$	1.20		$	1.31
Dividends declared per common share	$	0.2155		$	0.1875		$	0.5905		$	0.5125

See notes to condensed consolidated financial statements (unaudited).

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
NET INCOME	$	49,638		$	65,573		$	184,601		$	205,041
OTHER COMPREHENSIVE INCOME (LOSS)
Derivative instruments, net of tax (Note 7)	239			(2,169		)	(7,532		)	(910		)
Available-for-sale securities, net of tax (Note 7)	(18		)	18			412			21
TOTAL OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX	221			(2,151		)	(7,120		)	(889		)
TOTAL COMPREHENSIVE INCOME	$	49,859		$	63,422		$	177,481		$	204,152

See notes to condensed consolidated financial statements (unaudited).

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ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)



	Nine months ended
	September 30,
(in thousands)	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	184,601		$	205,041
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	117,840			106,903
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest	8,450			1,164
Deferred income tax expense	220,309			76,103
Allowance for equity funds used during construction	(26,442		)	(21,434		)
Other	22,872			14,950
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(34,449		)	(24,523		)
Inventory	(2,746		)	1,401
Prepaid and other current assets	(2,902		)	(4,317		)
Accounts payable	33,230			(1,120		)
Accrued compensation	3,202			(1,520		)
Accrued interest	(6,921		)	(8,896		)
Accrued taxes	(15,508		)	(15,566		)
Other current liabilities	(2,048		)	132
Estimated refund related to return on equity complaints	87,734			40,269
Other non-current assets and liabilities, net	(145		)	17,701
Net cash provided by operating activities	587,077			386,288
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(560,607		)	(460,110		)
Other	3,898			(14,969		)
Net cash used in investing activities	(556,709		)	(475,079		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	599,460			225,000
Borrowings under revolving credit agreements	790,000			909,400
Net issuance of commercial paper, net of discount	39,487			218,983
Retirement of long-term debt	(139,344		)	—
Repayments of revolving credit agreements	(872,500		)	(1,053,200		)
Repayment of term loan credit agreements	(361,000		)	—
Issuance of common stock	12,604			12,322
Dividends on common and restricted stock	(90,277		)	(79,697		)
Refundable deposits from generators for transmission network upgrades	28,798			3,458
Repayment of refundable deposits from generators for transmission network upgrades	(10,140		)	(11,442		)
Repurchase and retirement of common stock	(9,449		)	(21,931		)
Forward contracts of accelerated share repurchase program	—			(115,000		)
Other	(22,928		)	(2,676		)
Net cash (used in) provided by financing activities	(35,289		)	85,217
NET DECREASE IN CASH AND CASH EQUIVALENTS	(4,921		)	(3,574		)
CASH AND CASH EQUIVALENTS — Beginning of period	13,859			27,741
CASH AND CASH EQUIVALENTS — End of period	$	8,938		$	24,167

See notes to condensed consolidated financial statements (unaudited).

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1 . GENERAL

These condensed consolidated financial statements should be read in conjunction with the notes to the consolidated financial statements as of and for the year ended December 31, 2015 included in ITC Holdings’ annual report on Form 10-K for such period.

The accompanying condensed consolidated financial statements have been prepared using accounting principles generally accepted in the United States of America (“GAAP”) and with the instructions to Form 10-Q and Rule 10-01 of Securities and Exchange Commission (“SEC”) Regulation S-X as they apply to interim financial information. Accordingly, they do not include all of the information and notes required by GAAP for complete financial statements. These accounting principles require us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

The condensed consolidated financial statements are unaudited, but in our opinion include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results for the interim period. The interim financial results are not necessarily indicative of results that may be expected for any other interim period or the fiscal year.

Supplementary Cash Flows Information



	Nine months ended
	September 30,
(in thousands)	2016		2015
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	155,848	$	153,350
Income taxes paid (a)	22,743		49,599
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment and other long-lived assets (b)	$	99,754	$	85,386
Allowance for equity funds used during construction	26,442		21,434

____________________________


(a)	Amount for the nine months ended September 30, 2016 does not include the income tax refund of $128.2 million received from the Internal Revenue Service (“IRS”) in August 2016, which resulted from the election of bonus depreciation as described in Note 4 .


(b)	Amounts consist of accrued liabilities for construction, labor, materials and other costs that have not been included in investing activities. These amounts have not been paid for as of September 30, 2016 or 2015 , respectively, but will be or have been included as a cash outflow from investing activities when paid.

2 . THE MERGER

On February 9, 2016 , Fortis Inc. (“Fortis”), FortisUS Inc. (“FortisUS”), Element Acquisition Sub Inc. (“Merger Sub”) and ITC Holdings entered into an agreement and plan of merger (the “Merger Agreement”), pursuant to which Merger Sub would merge with and into ITC Holdings with ITC Holdings continuing as a surviving corporation and becoming a majority owned indirect subsidiary of FortisUS (the “Merger”). On April 20, 2016, FortisUS assigned its rights, interest, duties and obligations under the Merger Agreement to ITC Investment Holdings Inc. (“Investment Holdings”), a subsidiary of FortisUS formed to complete the Merger. On the same date, Fortis reached a definitive agreement with GIC Private Limited (“GIC”) for GIC to acquire an indirect 19.9% equity interest in ITC Holdings and debt securities to be issued by Investment Holdings for aggregate consideration of $1.228 billion in cash upon completion of the Merger. On October 14, 2016 , ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement consistent with the terms described above. On the same date, the common shares of ITC Holdings were delisted from the New York Stock Exchange (“NYSE”) and the common shares of Fortis were listed and began trading on the NYSE. Fortis continues to have its shares listed on the Toronto Stock Exchange.

In the Merger, ITC Holdings shareholders received $22.57 in cash and 0.7520 Fortis common shares for each share of common stock of ITC Holdings (the “Merger consideration”). Upon completion of the Merger, ITC Holdings shareholders held approximately 27% of the common shares of Fortis. Under the Merger Agreement, outstanding options to acquire common stock of ITC Holdings vested immediately prior to closing and were converted into the right to receive the difference between the Merger consideration and the exercise price of each option in cash, restricted stock vested immediately prior to closing and was converted into the right to receive the Merger consideration in cash and performance shares vested immediately prior to closing at the higher of target or actual performance through the effective time of the Merger and were converted into the

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right to receive the Merger consideration in cash. The Merger consideration for purposes of settling the share-based compensation awards was $45.72 .

For the three and nine months ended September 30, 2016 , we expensed external legal, advisory and financial services fees related to the Merger of $2.0 million and $24.3 million , respectively, and certain internal labor and associated costs related to the Merger of approximately $3.1 million and $9.4 million , respectively, recorded within general and administrative expenses on the condensed consolidated statement of operations. In addition, subsequent to September 30, 2016 through the date of this filing, we have incurred external legal, advisory and financial services fees and certain internal labor and associated costs related to the Merger of approximately $75 million , including approximately $41 million of expense recognized due to the accelerated vesting of the share-based compensation awards described above. The external and internal costs related to the Merger will not be included as components of revenue requirement at our Regulated Operating Subsidiaries as they were incurred by ITC Holdings.

See Note 11 for legal matters associated with the Merger with Fortis.

3 . RECENT ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

Amendment to the Balance Sheet Presentation of Debt Issuance Costs

In April 2015, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that amends the balance sheet presentation of debt issuance costs. This new standard requires debt issuance costs to be shown as a direct deduction from the carrying amount of the related debt, consistent with debt discounts. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. On January 1, 2016, we adopted this guidance retrospectively and have applied this change to all amounts presented in our condensed consolidated statements of financial position. The following shows the impact of this adoption on our previously reported consolidated statement of financial position as of December 31, 2015:



(in thousands)	Reported		Adjustment			Adjusted
Deferred financing fees (net of accumulated amortization)	$	29,298	$	(26,800	)	$	2,498
Debt maturing within one year	395,334		(229		)	395,105
Long-term debt	4,060,923		(26,571		)	4,034,352

We have accounted for this adoption as a change in accounting principle that is required due to a change in the authoritative accounting guidance. In connection with implementing this guidance, we adopted an accounting policy to present unamortized debt issuance costs associated with revolving credit agreements, commercial paper and other similar arrangements as an asset that is amortized over the life of the particular arrangement. In addition, we present debt issuance costs incurred prior to the associated debt funding as an asset for all other debt arrangements. This standard did not impact our consolidated statements of operations or cash flows.

Recently Issued Pronouncements

We have considered all new accounting pronouncements issued by the FASB and concluded the following accounting guidance, which has not yet been adopted by us, may have a material impact on our consolidated financial statements.

Revenue Recognition

In May 2014, the FASB issued authoritative guidance requiring entities to apply a new model for recognizing revenue from contracts with customers. The guidance will supersede the current revenue recognition guidance and require entities to evaluate their revenue recognition arrangements using a five-step model to determine when a customer obtains control of a transferred good or service. The guidance is effective for annual reporting periods beginning after December 15, 2017 and may be adopted using a full or modified retrospective approach. We do not expect the guidance to have a material impact on our consolidated results of operations, cash flows or financial position. However, we are still evaluating the disclosure requirements, the impacts of the recent clarifying amendments that have been issued by the FASB and the transition method we will elect to adopt the guidance.

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Classification and Measurement of Financial Instruments

In January 2016, the FASB issued authoritative guidance amending the classification and measurement of financial instruments. The guidance requires entities to carry most investments in equity securities at fair value and recognize changes in fair value in net income, unless the investment results in consolidation or equity method accounting. Additionally, the new guidance amends certain disclosure requirements associated with the fair value of financial instruments. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The guidance is required to be adopted using a modified retrospective approach, with limited exceptions. We are currently assessing the impacts this guidance will have on our consolidated financial statements, including our disclosures.

Accounting for Leases

In February 2016, the FASB issued authoritative guidance on accounting for leases, which impacts accounting by lessees as well as lessors. The new guidance creates a dual approach for lessee accounting, with lease classification determined in accordance with principles in existing lease guidance. Income statement presentation differs depending on the lease classification; however, both types of leases result in lessees recognizing a right-of-use asset and a lease liability, with limited exceptions. Under existing accounting guidance, operating leases are not recorded on the balance sheet of lessees. The new guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and will be applied using a modified retrospective approach, with possible optional practical expedients. Early adoption is permitted. We are currently assessing the impacts this guidance will have on our consolidated financial statements, including our disclosures.

Simplification of Employee Share-Based Payment Accounting

In March 2016, the FASB issued authoritative guidance that simplifies several aspects of the accounting for employee share-based payment transactions. The new guidance (1) requires that an entity recognize all excess tax benefits and tax deficiencies as income tax benefit or expense in the income statement, (2) allows an entity to elect as an accounting policy either to estimate forfeitures (as currently required) or account for forfeitures when they occur, (3) modifies the current exception to liability classification of an award when an employer uses a net-settlement feature to withhold shares to meet the employer’s minimum statutory tax withholding requirement to apply if the withholding amount does not exceed the maximum statutory tax rate and (4) specifies the statement of cash flow presentation for excess tax benefits and cash payments to taxing authorities when shares are withheld to meet tax withholding requirements. Though the new guidance is not effective until January 1, 2017, we expect to early adopt the guidance in the fourth quarter of 2016. The various amendments require different transition methods including modified retrospective approach through a cumulative effect adjustment to retained earnings, prospective adoption and retrospective adoption. Assuming we adopt the guidance in the fourth quarter of 2016, we expect to record an adjustment to beginning retained earnings for excess tax benefits generated in years prior to adoption that were previously unrecognized. In addition, we expect to record an income tax benefit related to stock-based compensation that vested during 2016.

Classification of Certain Cash Receipts and Cash Payments on the Statement of Cash Flows

In August 2016, the FASB issued authoritative guidance on the classification of certain cash receipts and cash payments in the statement of cash flows to address diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The guidance should be applied retrospectively but may be applied prospectively if retrospective application would be impracticable. We are currently assessing the impacts this guidance will have on our classification of activity in our statement of cash flows.

4 . REGULATORY MATTERS

Regional Cost Allocation Refund

In October 2010, MISO and ITCTransmission made a filing with the Federal Energy Regulatory Commission (“FERC”) under Section 205 of the FPA to revise the MISO tariff to establish a methodology to allocate and recover costs of ITCTransmission’s Phase Angle Regulating Transformers (“PARs”) among MISO and other FERC-approved Regional Transmission Organizations (“RTOs”), New York Independent System Operator and PJM Interconnection (“other RTOs”). In December 2010, the FERC accepted the proposed revisions, subject to refund, while setting them for hearing and settlement procedures. On September 22, 2016, the FERC issued an order largely affirming the presiding administrative law judge’s initial decision issued in December 2012, which stated, among other things, that MISO and ITCTransmission failed to show

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that the other RTOs will benefit from the operation of ITCTransmission’s PARs. The FERC order requires ITCTransmission to provide refunds within 30 days for excess amounts collected from customers at the other RTOs. As a result of the FERC order, ITCTransmission will collect these revenues from network customers instead, resulting in an increase in network revenues and a decrease in regional cost sharing revenues and no material impact on total operating revenue or net income for the three and nine months ended September 30, 2016 . ITCTransmission has recorded $28.7 million for this refund, including interest, in current liabilities on the condensed consolidated statements of financial position as of September 30, 2016 , which resulted in a reduction to regional cost sharing revenues and an offsetting increase to network revenues for the three and nine months ended September 30, 2016 . This refund, including interest, was provided to the other RTOs in October 2016. The timing for collection from our network customers of the amount refunded to the other RTOs has not yet been determined, but is expected to occur no later than 2018.

ITC Interconnection

ITC Interconnection was formed in 2014 by ITC Holdings to pursue transmission investment opportunities. On June 1, 2016, ITC Interconnection acquired certain transmission assets from a merchant generating company and placed a newly constructed 345 kV transmission line in service. As a result, ITC Interconnection became a transmission owner in PJM Interconnection, and is subject to rate-regulation by the FERC. The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement with the merchant generating company. The financial results of ITC Interconnection are currently not material to our consolidated financial statements.

MISO Funding Policy for Generator Interconnections

On June 18, 2015, the FERC issued an order initiating a proceeding, pursuant to Section 206 of the Federal Power Act (“FPA”), to examine MISO’s funding policy for generator interconnections, which allows a transmission owner to unilaterally elect to fund network upgrades and recover such costs from the interconnection customer. In this order, the FERC suggested the MISO funding policy be revised to require mutual agreement between the interconnection customer and transmission owner to utilize the election to fund network upgrades. On January 8, 2016, MISO made a compliance filing to revise its funding policy to adopt the FERC suggestion to require mutual agreement between the customer and transmission owner (“TO”), with an effective date of June 24, 2015. ITCTransmission, METC and ITC Midwest (“MISO Regulated Operating Subsidiaries”), along with another MISO TO, are currently appealing the FERC’s orders on this issue. We do not expect the resolution of this proceeding to have a material impact on our consolidated results of operations, cash flows or financial condition.

MISO Formula Rate Template Modifications Filing

On October 30, 2015, our MISO Regulated Operating Subsidiaries requested modifications, pursuant to Section 205 of the FPA, to certain aspects of their respective FERC-approved formula rate templates (“formula rate templates”) which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. Our MISO Regulated Operating Subsidiaries requested an effective date of January 1, 2016 for the proposed template changes. On December 30, 2015, the FERC conditionally accepted the formula rate template modifications and required a further compliance filing, which was made on February 8, 2016. On April 14, 2016, the FERC issued an order accepting the February 8, 2016 compliance filing, effective January 1, 2016. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that resulted in the joint applicants recovering excess amounts from customers. As of September 30, 2016 and December 31, 2015 , our MISO Regulated Operating Subsidiaries had recorded an aggregate refund liability of $4.4 million and $10.4 million , respectively.

Challenges Regarding Bonus Depreciation

On December 18, 2015, Interstate Power and Light Company (“IP&L”) filed a formal challenge (“IP&L challenge”) with the FERC against ITC Midwest on certain inputs to ITC Midwest’s formula rates. The IP&L challenge alleged that ITC Midwest has unreasonably and imprudently opted out of using bonus depreciation in the calculation of its federal income tax expense and thereby unduly increased the transmission charges for transmission service to customers. On March 11, 2016, the FERC granted the IP&L challenge in part by requiring ITC Midwest to recalculate its revenue requirements, effective January 1, 2015, to simulate the election of bonus depreciation for 2015. The FERC denied IP&L’s request that ITC Midwest be required to elect bonus depreciation in any past or future years; however, stakeholders will be able to challenge any decision by ITC Midwest not to take bonus depreciation in future years. On June 8, 2016, the FERC denied ITC Midwest’s request for

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rehearing of the March 11, 2016 order. On August 3, 2016, ITC Midwest filed a petition for review of the FERC’s March 11, 2016 and June 8, 2016 orders in the United States Court of Appeals, District of Columbia Circuit. On September 8, 2016, ITC Midwest filed a motion to defer the petition pending the issuance of a private letter ruling from the IRS. In a separate but related matter, on April 15, 2016, Consumers Energy Company filed a formal challenge, or in the alternative, a complaint under Section 206 of the FPA, with the FERC against METC relating to METC’s historical practice of opting out of using bonus depreciation. On July 8, 2016, the FERC denied Consumers Energy Company’s formal challenge and dismissed the complaint without prejudice.

Rate of Return on Equity Complaints

See “Rate of Return on Equity Complaints” in Note 11 for a discussion of the complaints.

Cost-Based Formula Rate Templates with True-Up Mechanism

The transmission revenue requirements at our Regulated Operating Subsidiaries are set annually, using formula rate templates, and remain in effect for a one -year period. By completing their formula rate templates on an annual basis, our Regulated Operating Subsidiaries are able to make adjustments to reflect changing operational data and financial performance, including the amount of network load on their transmission systems (for our MISO Regulated Operating Subsidiaries), operating expenses and additions to property, plant and equipment when placed in service, among other items. The formula rate templates do not require further action or FERC filings each year, although the template inputs remain subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use formula rate templates to calculate their respective annual revenue requirements unless the FERC determines any template to be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable. See “Rate of Return on Equity Complaints” in Note 11 for detail on return on equity (“ROE”) matters including incentive adders approved by the FERC in 2015.

Our formula rate templates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue requirements. Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula rate templates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in future revenue requirements and thus flows through to customer bills within two years under the provisions of the formula rate templates.

The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the nine months ended September 30, 2016 :



(in thousands)	Total
Net regulatory liability as of December 31, 2015	$	(2,564	)
Net refund of 2014 revenue deferrals and accruals, including accrued interest	16,785
Net revenue deferral for the nine months ended September 30, 2016	(24,503		)
Net accrued interest payable for the nine months ended September 30, 2016	(732		)
Net regulatory liability as of September 30, 2016	$	(11,014	)

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Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, are recorded in the condensed consolidated statements of financial position at September 30, 2016 as follows:



(in thousands)	Total
Current assets	$	22,262
Non-current assets	18,678
Current liabilities	(15,714		)
Non-current liabilities	(36,240		)
Net regulatory liability as of September 30, 2016	$	(11,014	)

5 . GOODWILL AND INTANGIBLE ASSETS

Goodwill

At September 30, 2016 and December 31, 2015 , we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173.4 million , $453.8 million and $323.0 million , respectively, which resulted from the ITCTransmission acquisition, the METC acquisition and ITC Midwest’s asset acquisition, respectively.

Intangible Assets

We have recorded intangible assets as a result of the METC acquisition in 2006. The carrying value of these assets was $28.9 million and $31.2 million (net of accumulated amortization of $29.5 million and $27.2 million ) as of September 30, 2016 and December 31, 2015 , respectively.

We have also recorded intangible assets for payments made by and obligations of ITC Great Plains to certain TOs to acquire rights, which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including the KETA Project and the Kansas V-Plan Project. The carrying amount of these intangible assets was $14.6 million and $14.4 million (net of accumulated amortization of $1.2 million and $1.0 million ) as of September 30, 2016 and December 31, 2015 , respectively.

During each of the three month periods ended September 30, 2016 and 2015 , we recognized $0.8 million of amortization expense of our intangible assets, and we recognized $2.5 million during each of the nine month periods ended September 30, 2016 and 2015 . For each of the next five years, we expect the annual amortization of our intangible assets that have been recorded as of September 30, 2016 to be $3.3 million per year.

6 . DEBT

Derivative Instruments and Hedging Activities

We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 6.05% Senior Notes, due January 31, 2018. As of September 30, 2016 , ITC Holdings had $384.3 million outstanding under the 6.05% Senior Notes.



Interest Rate Swaps (in millions, except percentages)	Notional Amount		Weighted Average Fixed Rate	Original Term	Effective Date
July 2016 swaps	$	75.0	1.616%	10 years	January 2018
August 2016 swap	25.0		1.599%	10 years	January 2018
Total	$	100.0

The 10-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and pay interest semi-annually at various fixed rates effective for the 10-year period beginning January 31, 2018, after the agreements have been terminated. The agreements include a mandatory early termination provision and will be terminated no later than the effective date of the interest rate swaps of January 31, 2018. The interest rate swaps have been determined to be highly effective at offsetting changes in the fair value of the forecasted interest cash flows associated with the expected

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debt issuance, resulting from changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation.

The interest rate swaps qualify for cash flow hedge accounting treatment, whereby any gain or loss recognized from the trade date to the effective date for the effective portion of the hedge is recorded net of tax in accumulated other comprehensive income (“AOCI”). This amount will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. As of September 30, 2016 , the fair value of the derivative instruments was an asset of less than $0.1 million and a liability of $0.2 million . None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 10 for additional fair value information.

In June 2016, we terminated $300.0 million of 10 -year interest rate swap contracts that managed the interest rate risk associated with the unsecured Notes issued by ITC Holdings described below. A summary of the terminated interest rate swaps is provided below:



Interest Rate Swaps (in millions, except percentages)	Amount		Weighted Average Fixed Rate of Interest Rate Swaps	Comparable Reference Rate of Notes	Loss on Derivatives		Settlement Date
10-year interest rate swaps	$	300.0	1.99%	1.37%	$	17.2	June 2016

The interest rate swaps qualified for cash flow hedge accounting treatment and the loss of $17.2 million was recognized in June 2016 for the effective portion of the hedges and recorded net of tax in AOCI. This amount is being amortized as a component of interest expense over the life of the related debt. The ineffective portion of the hedges was recognized in the condensed consolidated statement of operations for the nine months ended September 30, 2016 and was not material.

METC

On April 26, 2016, METC issued $200.0 million of 3.90% Senior Secured Notes, due April 26, 2046. The proceeds were used to repay the $200.0 million borrowed under METC’s term loan credit agreement. The METC Senior Secured Notes were issued under its first mortgage indenture and secured by a first mortgage lien on substantially all of its real property and tangible personal property.

ITC Holdings

Commercial Paper Program

ITC Holdings has an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400.0 million outstanding at any one time. As of September 30, 2016 , ITC Holdings had approximately $135.9 million of commercial paper issued and outstanding under the program, with a weighted-average interest rate of 0.8% and weighted average remaining days to maturity of 16 days . The proceeds from issuances under the program during the nine months ended September 30, 2016 were used to repay and retire the $139.3 million of ITC Holdings’ 5.875% Senior Notes, due September 30, 2016, and for general corporate purposes, including the repayment of borrowings under ITC Holdings’ revolving credit agreement. The amount outstanding as of September 30, 2016 was classified as debt maturing within one year in the condensed consolidated statements of financial position.

Unsecured Notes

On July 5, 2016, ITC Holdings issued $400.0 million aggregate principal amount of unsecured 3.25% Notes, due June 30, 2026 . The proceeds from the issuance were used to repay the $161.0 million outstanding under ITC Holdings’ term loan credit agreement and for general corporate purposes, primarily the repayment of indebtedness outstanding under ITC Holdings’ commercial paper program discussed above. These Notes were issued under ITC Holdings’ indenture, dated April 18, 2013.

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Revolving Credit Agreements

At September 30, 2016 , ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available:



(in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity			Weighted Average Interest Rate on Outstanding Balance		Commitment Fee Rate (b)
ITC Holdings	$	400.0	$	7.0	$	393.0	(c)	1.8%	(d)	0.175	%
ITCTransmission	100.0		41.6		58.4			1.4%	(e)	0.10	%
METC	100.0		25.8		74.2			1.4%	(e)	0.10	%
ITC Midwest	250.0		104.3		145.7			1.4%	(e)	0.10	%
ITC Great Plains	150.0		58.7		91.3			1.4%	(e)	0.10	%
Total	$	1,000.0	$	237.4	$	762.6

____________________________


(a)	Included within long-term debt.


(b)	Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.

(c)

ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary. While outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was $257.1 million as of September 30, 2016 .


(d)	Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.25% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month LIBOR, plus an applicable margin of 0.25%, subject to adjustments based on ITC Holdings’ credit rating.


(e)	Loans bear interest at a rate equal to LIBOR plus an applicable margin of 1.00% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month LIBOR, subject to adjustments based on the borrower’s credit rating.

On April 7, 2016, each of ITC Holdings and its Regulated Operating Subsidiaries amended its respective unsecured revolving credit agreement to allow for the consummation of the Merger.

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries, selling or otherwise disposing of all or substantially all of our assets and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and maintaining certain interest coverage ratios. As of September 30, 2016 , we were not in violation of any debt covenant.

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7 . STOCKHOLDERS’ EQUITY

The changes in stockholders’ equity for the nine months ended September 30, 2016 were as follows:



									Accumulated
									Other			Total
	Common Stock					Retained			Comprehensive			Stockholders’
(in thousands, except share and per share data)	Shares		Amount			Earnings			Income (Loss)			Equity
BALANCE, DECEMBER 31, 2015	152,699,077		$	829,211		$	875,595		$	4,265		$	1,709,071
Net income	—		—			184,601			—			184,601
Repurchase and retirement of common stock	(215,791	)	(9,449		)	—			—			(9,449		)
Dividends declared ($0.5905 per share)	—		—			(90,435		)	—			(90,435		)
Stock option exercises	473,519		11,376			—			—			11,376
Shares issued under the Employee Stock Purchase Plan	40,219		1,228			—			—			1,228
Issuance of restricted stock (a)	464,395		—			—			—			—
Forfeiture of restricted stock	(22,750	)	—			—			—			—
Forfeiture of performance shares	(5,998	)	—			—			—			—
Share-based compensation, net of forfeitures	—		16,685			—			—			16,685
Other comprehensive loss, net of tax	—		—			—			(7,120		)	(7,120		)
Other	—		159			—			—			159
BALANCE, SEPTEMBER 30, 2016	153,432,671		$	849,210		$	969,761		$	(2,855	)	$	1,816,116

____________________________


(a)	On May 19, 2016 , pursuant to the 2015 Long-Term Incentive Plan, we granted 453,219 shares of restricted stock, which vested as part of the closing of the Merger on October 14, 2016 as described in Note 2 .

The changes in stockholders’ equity for the nine months ended September 30, 2015 were as follows:



									Accumulated
									Other			Total
	Common Stock					Retained			Comprehensive			Stockholders’
(in thousands, except share and per share data)	Shares		Amount			Earnings			Income (Loss)			Equity
BALANCE, DECEMBER 31, 2014	155,140,967		$	923,191		$	741,550		$	4,816		$	1,669,557
Net income	—		—			205,041			—			205,041
Repurchase and retirement of common stock	(667,487	)	(21,931		)	—			—			(21,931		)
Dividends declared ($0.5125 per share)	—		—			(79,691		)	—			(79,691		)
Stock option exercises (a)	1,165,435		10,599			—			—			10,599
Shares issued under the Employee Stock Purchase Plan	55,905		1,723			—			—			1,723
Issuance of restricted stock	254,711		—			—			—			—
Forfeiture of restricted stock	(53,197	)	—			—			—			—
Issuance of performance shares	287,464		—			—			—			—
Forfeiture of performance shares	(6,713	)	—			—			—			—
Share-based compensation, net of forfeitures	—		12,461			—			—			12,461
Forward contracts of accelerated share repurchase program	—		(115,000		)	—			—			(115,000		)
Other comprehensive loss, net of tax	—		—			—			(889		)	(889		)
Other	—		(6		)	—			—			(6		)
BALANCE, SEPTEMBER 30, 2015	156,177,085		$	811,037		$	866,900		$	3,927		$	1,681,864

____________________________


(a)	An additional 37,941 shares of our common stock were issued during the three months ended December 31, 2015 for stock option exercises. Total shares of 1,203,376 were issued during the year ended December 31, 2015 due to the exercise of stock options.

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Accumulated Other Comprehensive Income

The following table provides the components of changes in AOCI for the three and nine months ended September 30, 2016 and 2015 :



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Balance at the beginning of period	$	(3,076	)	$	6,078		$	4,265		$	4,816
Derivative instruments
Reclassification of net loss relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $266 and $100 for the three months ended September 30, 2016 and 2015, respectively, and net of tax of $458 and $261 for the nine months ended September 30, 2016 and 2015, respectively)	375			111			605			372
Loss on interest rate swaps relating to interest rate cash flow hedges (net of tax of $98 and $1,639 for the three months ended September 30, 2016 and 2015, respectively, and net of tax of $5,865 and $920 for the nine months ended September 30, 2016 and 2015, respectively)	(136		)	(2,280		)	(8,137		)	(1,282		)
Derivative instruments, net of tax	239			(2,169		)	(7,532		)	(910		)
Available-for-sale securities
Unrealized net (loss) gain on available-for-sale securities (net of tax of $13 for the three months ended September 30, 2016 and 2015, and net of tax of $296 and $15 for the nine months ended September 30, 2016 and 2015, respectively)	(18		)	18			412			21
Available-for-sale securities, net of tax	(18		)	18			412			21
Total other comprehensive income (loss), net of tax	221			(2,151		)	(7,120		)	(889		)
Balance at the end of period	$	(2,855	)	$	3,927		$	(2,855	)	$	3,927

The amount of net loss relating to interest rate cash flow hedges to be reclassified from AOCI to interest expense for the 12-month period ending September 30, 2017 is expected to be approximately $2.5 million .

The Merger

On October 14, 2016, ITC Holdings became a wholly-owned subsidiary of Investment Holdings, which is an indirect subsidiary of Fortis and GIC, upon the closing of the Merger. On the same date, the common shares of ITC Holdings were delisted from the NYSE. Refer to Note 2 for further details of the Merger.

8 . EARNINGS PER SHARE

We report both basic and diluted EPS. Our restricted stock contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing EPS. A reconciliation of both calculations for the three and nine months ended September 30, 2016 and 2015 is presented in the following table:

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	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except share, per share data and percentages)	2016			2015			2016			2015
Numerator:
Net income	$	49,638		$	65,573		$	184,601		$	205,041
Less: dividends declared and paid — common and restricted shares	(32,999		)	(29,230		)	(90,277		)	(79,697		)
Undistributed earnings	16,639			36,343			94,324			125,344
Percentage allocated to common shares (a)	99.3		%	99.3		%	99.3		%	99.3		%
Undistributed earnings — common shares	16,523			36,089			93,664			124,467
Add: dividends declared and paid — common shares	32,766			29,036			89,656			79,136
Numerator for basic and diluted earnings per common share	$	49,289		$	65,125		$	183,320		$	203,603
Denominator:
Basic earnings per common share — weighted average common shares outstanding	152,028,595			154,836,673			151,754,084			154,348,478
Incremental shares for stock options, employee stock purchase plan shares and performance shares — weighted average assumed conversion	1,189,049			687,035			1,126,616			1,104,516
Diluted earnings per common share — adjusted weighted average shares and assumed conversion	153,217,644			155,523,708			152,880,700			155,452,994
Per common share net income:
Basic	$	0.32		$	0.42		$	1.21		$	1.32
Diluted	$	0.32		$	0.42		$	1.20		$	1.31

____________________________



(a)	Weighted average common shares outstanding	152,028,595		154,836,673		151,754,084		154,348,478
	Weighted average restricted shares (participating securities)	1,088,340		1,040,212		1,025,033		1,127,490
	Total	153,116,935		155,876,885		152,779,117		155,475,968
	Percentage allocated to common shares	99.3	%	99.3	%	99.3	%	99.3	%

The incremental shares for stock options and employee stock purchase plan (“ESPP”) shares are included in the diluted EPS calculation using the treasury stock method, unless the effect of including them would be anti-dilutive. Additionally, performance shares are included in the diluted EPS calculation using the treasury stock method when the performance metric is substantively measurable as of the end of the reporting period and has been met under the assumption the end of the reporting period was the end of the performance period. The outstanding stock options, ESPP shares and performance shares and the anti-dilutive stock options and ESPP shares excluded from the diluted EPS calculations were as follows:



	2016	2015
Outstanding stock options, ESPP shares and performance shares (as of September 30)	3,613,464	4,138,180
Anti-dilutive stock options and ESPP shares (for the three and nine months ended September 30)	—	1,059,106

The Merger

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9 . RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Pension Plan Benefits

We have a qualified defined benefit pension plan (“retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on years of benefit service, average final compensation and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is to contribute amounts necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974, plus additional amounts as we determine appropriate. During the nine months ended September 30, 2016 , we contributed $2.8 million to the retirement plan. We do not expect to make any additional contributions to this plan in 2016.

We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. We contributed $5.2 million to the supplemental benefit plans during the nine months ended September 30, 2016 . We do not expect to make any additional contributions to these plans in 2016.

Net periodic benefit cost for the pension plans, by component, was as follows for the three and nine months ended September 30, 2016 and 2015 :



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Service cost	$	1,602		$	1,624		$	4,810		$	4,872
Interest cost	872			924			2,616			2,772
Expected return on plan assets	(931		)	(960		)	(2,795		)	(2,879		)
Amortization of prior service credit	(5		)	(10		)	(13		)	(31		)
Amortization of unrecognized loss	877			1,061			2,629			3,182
Net pension cost	$	2,415		$	2,639		$	7,247		$	7,916

Other Postretirement Benefits

We provide certain postretirement health care, dental and life insurance benefits for eligible employees. During the nine months ended September 30, 2016 , we contributed $5.6 million to the postretirement benefit plan. We expect to make estimated additional contributions of $1.7 million to the postretirement benefit plan in 2016.

Net postretirement benefit plan cost, by component, was as follows for the three and nine months ended September 30, 2016 and 2015 :



	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Service cost	$	1,855		$	2,121		$	5,565		$	6,364
Interest cost	631			620			1,891			1,858
Expected return on plan assets	(531		)	(463		)	(1,592		)	(1,389		)
Amortization of unrecognized loss	—			125			—			375
Net postretirement cost	$	1,955		$	2,403		$	5,864		$	7,208

Defined Contribution Plan

We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $0.9 million and $0.8 million for the three months ended September 30, 2016 and 2015 , respectively, and $3.4 million and $3.2 million for the nine months ended September 30, 2016 and 2015 , respectively.

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10 . FAIR VALUE MEASUREMENTS

The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the nine months ended September 30, 2016 and the year ended December 31, 2015 , there were no transfers between levels.

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at September 30, 2016 , were as follows:



	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
(in thousands)	(Level 1)		(Level 2)			(Level 3)
Financial assets measured on a recurring basis:
Mutual funds — fixed income securities	$	42,231	$	—		$	—
Mutual funds — equity securities	1,049		—			—
Interest rate swap derivative	—		7			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(240		)	—
Total	$	43,280	$	(233	)	$	—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2015 , were as follows:



	Fair Value Measurements at Reporting Date Using
	Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs
(in thousands)	(Level 1)		(Level 2)			(Level 3)
Financial assets measured on a recurring basis:
Cash and cash equivalents — cash equivalents	$	49	$	—		$	—
Mutual funds — fixed income securities	35,813		—			—
Mutual funds — equity securities	976		—			—
Interest rate swap derivative	—		112			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(3,548		)	—
Total	$	36,838	$	(3,436	)	$	—

As of September 30, 2016 and December 31, 2015 , we held certain assets and liabilities that are required to be measured at fair value on a recurring basis. The assets included in the table consist of investments recorded within cash and cash equivalents and other long-term assets, including investments held in a trust associated with our supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. Our cash and cash equivalents consisted of money market funds that are recorded at cost plus accrued interest to approximate fair value. Our mutual funds consist of publicly traded mutual funds and are recorded at fair value based on observable trades for identical securities in an active market. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value. Gain and losses are recorded in earnings for investments classified as trading securities and other comprehensive income for investments classified as available-for-sale.

The asset and liability related to derivatives consist of interest rate swaps discussed in Note 6 . The fair value of our interest rate swap derivatives is determined based on a discounted cash flow (“DCF”) method using LIBOR swap rates, which are observable at commonly quoted intervals.

We also held non-financial assets that are required to be measured at fair value on a non-recurring basis. These consist of goodwill and intangible assets. We did not record any impairment charges on long-lived assets and no other significant events occurred requiring non-financial assets and liabilities to be measured at fair value (subsequent to initial recognition) during the nine months ended September 30, 2016 . For additional information on our goodwill and intangible assets, please refer to the notes to the consolidated financial statements as of and for the year ended December 31, 2015 included in our Form 10-K for such period and to Note 5 of this Form 10-Q.

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Fair Value of Financial Assets and Liabilities

Fixed Rate Debt

Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $4,592.1 million and $3,879.7 million at September 30, 2016 and December 31, 2015 , respectively. These fair values represent Level 2 measurements under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, net of discount and deferred financing fees and excluding revolving and term loan credit agreements and commercial paper, was $4,110.9 million and $3,653.6 million at September 30, 2016 and December 31, 2015 , respectively.

Revolving and Term Loan Credit Agreements

At September 30, 2016 and December 31, 2015 , we had a consolidated total of $237.4 million and $680.9 million , respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.

Other Financial Instruments

The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the short-term nature of these instruments.

11 . COMMITMENTS AND CONTINGENT LIABILITIES

Environmental Matters

We are subject to federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of solid and hazardous wastes and hazardous materials, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities relating to investigation and remediation of contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as properties currently owned or operated by us. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.

Our assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties that we own or operate have been used for many years, and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained polychlorinated biphenyls, or PCBs. Our facilities and equipment are often situated on or near property owned by others so that, if they are the source of contamination, others’ property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that we do not own and transmission assets that we own or operate are sometimes commingled at our transmission stations with distribution assets owned or operated by our transmission customers.

Some properties in which we have an ownership interest or at which we operate are, or are suspected of being, affected by environmental contamination. We are not aware of any pending or threatened claims against us with respect to environmental contamination relating to these properties, or of any investigation or remediation of contamination at these properties, that entail costs likely to materially affect us. Some facilities and properties are located near environmentally sensitive areas such as wetlands.

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Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While we do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, the liabilities and costs imposed on our business could be significant if such a relationship is established or accepted. We are not aware of any pending or threatened claims against us for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.

Litigation

We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, eminent domain and vegetation management activities, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss.

Michigan Sales and Use Tax Audit

The Michigan Department of Treasury has conducted sales and use tax audits of ITCTransmission for the audit periods April 1, 2005 through June 30, 2008 and October 1, 2009 through September 30, 2013. The Michigan Department of Treasury has denied ITCTransmission’s claims of the industrial processing exemption from use tax that it has taken beginning January 1, 2007. The exemption claim denials resulted in use tax assessments against ITCTransmission. ITCTransmission filed administrative appeals to contest these use tax assessments.

In a separate, but related case involving a Michigan-based public utility that made similar industrial processing exemption claims, the Michigan Supreme Court ruled in July 2015 that the electric system, which involves altering voltage, constitutes an exempt, industrial processing activity. However, the ruling further held the electric system is also used for other functions that would not be exempt, and remanded the case to the Michigan Court of Claims to determine how the exemption applies to assets that are used in electric distribution activities. On March 30, 2016, ITCTransmission withdrew its administrative appeals, and subsequently filed a civil action in the Michigan Court of Claims seeking to have the use tax assessments at issue canceled. This litigation is currently in the discovery stage. Given the preliminary status of this litigation, ITCTransmission cannot estimate the timing of any potential tax assessments or refunds.

The amount of use tax associated with the exemptions taken by ITCTransmission through September 30, 2016 is estimated to be approximately $20.2 million , including interest. This amount includes approximately $10.6 million , including interest, assessed for the audit periods noted above. ITCTransmission believes it is probable that portions of the use tax assessments will be sustained upon resolution of this matter and has recorded $9.5 million and $5.9 million for this contingent liability, including interest, as of September 30, 2016 and December 31, 2015 , respectively, primarily as an increase to property, plant and equipment, which is a component of revenue requirement in our cost-based formula rate.

METC has also taken the industrial processing exemption, estimated to be approximately $10.4 million for open periods. METC has not been assessed any use tax liability and has not recorded any contingent liability as of September 30, 2016 associated with this matter. In the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission and METC would record the additional use tax primarily as an increase to the cost of property, plant and equipment, as the majority of purchases for which the exemption was taken relate to equipment purchases associated with capital projects.

Rate of Return on Equity Complaints

On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed a complaint with the FERC under Section 206 of the FPA (the “Initial Complaint”), requesting that the FERC find the current 12.38% MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including ITCTransmission, METC and ITC Midwest, to no longer be just and reasonable. The complainants sought a FERC order reducing the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15% , reducing the equity component of our capital structure from the FERC approved 60% to 50% and terminating the ROE adders currently approved for certain ITC Holdings operating companies, including adders currently utilized by ITCTransmission and METC.

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On June 19, 2014, in a separate Section 206 complaint against the regional base ROE rate for ISO New England TOs, the FERC adopted a new methodology for establishing base ROE rates for electric transmission utilities. The new methodology is based on a two-step DCF analysis that uses both short-term and long-term growth projections in calculating ROE rates for a proxy group of electric utilities. The previous methodology used only short-term growth projections. The FERC also reiterated that it can apply discretion in determining how ROE rates are established within a zone of reasonableness and reiterated its policy for limiting the overall ROE rate for any company, including the base and all applicable adders, at the high end of the zone of reasonableness set by the two-step DCF methodology. The new method presented in the ISO New England ROE case will be used in resolving the MISO ROE case.

On October 16, 2014, the FERC granted the complainants’ request in part by setting the base ROE for hearing and settlement procedures, while denying all other aspects of the Initial Complaint. The FERC found that the complainants failed to show that the use of actual or FERC-approved capital structures that include more than 50% equity is unjust and unreasonable. The FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives. The order reiterated that any TO’s total ROE rate is limited by the top end of a zone of reasonableness and the TO’s ability to implement the full amount of previously granted ROE adders may be affected by the outcome of the hearing. The FERC set the refund effective date for the Initial Complaint as November 12, 2013.

On December 22, 2015, the presiding administrative law judge issued an initial decision on the Initial Complaint. On September 28, 2016, the FERC issued an order (the “September 2016 Order”) affirming the presiding administrative law judge’s initial decision and setting the base ROE at 10.32% , with a maximum ROE of 11.35% , effective for the period from November 12, 2013 through February 11, 2015 (the “Initial Refund Period”). Additionally, the rates established by the September 2016 Order will be used prospectively from the date of the order until a new approved rate is established by the Second Complaint described below, which result in an ROE used currently by ITCTransmission, METC and ITC Midwest of 11.35% , 11.35% and 11.32% , respectively. The September 2016 Order requires all MISO TOs, including our MISO Regulated Operating Subsidiaries, to provide refunds within 30 days for the Initial Refund Period. The estimated refund for the Initial Complaint resulting from this FERC order, including interest, is $117.4 million for our MISO Regulated Operating Subsidiaries, recorded in current liabilities on the condensed consolidated statements of financial position. On October 21, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for an extension of nine months to provide refunds until July 28, 2017, which was granted by the FERC on October 28, 2016. Additionally, on October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for rehearing of the September 2016 Order regarding the future exclusion of certain short-term growth projections in the two-step DCF analysis.

On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the “Second Complaint”) by Arkansas Electric Cooperative Corporation, Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative, Inc., seeking a FERC order to reduce the base ROE used in the formula transmission rates of our MISO Regulated Operating Subsidiaries to 8.67% , with an effective date of February 12, 2015. On March 11, 2015, the MISO TOs filed an answer to the Second Complaint with the FERC supporting the current base ROE as just and reasonable. On June 18, 2015, the FERC accepted the Second Complaint and set it for hearing and settlement procedures. The FERC also set the refund effective date for the Second Complaint as February 12, 2015.

On October 20, 2015, the MISO TOs filed expert witness testimony in the Second Complaint proceeding supporting the existing base ROE as just and reasonable. However, in the event that the FERC elects to change the base ROE, the testimony included a recommendation of a 10.75% base ROE for the period from February 12, 2015 through May 11, 2016 (the “Second Refund Period”). Updated data to be considered in establishing any new base ROE was filed by the parties to the Second Complaint in January 2016, including a recommendation in the updated MISO TO expert witness testimony to use a 10.96% base ROE. On June 30, 2016, the presiding administrative law judge issued an initial decision on the Second Complaint, which recommended a base ROE of 9.70% for the Second Refund Period, with a maximum ROE of 10.68% . The initial decision is a non-binding recommendation to the FERC on the Second Complaint, and all parties, including the MISO TOs and the complainants, have filed briefs contesting various parts of the proposed findings and recommendations. In resolving the Second Complaint, we expect the FERC to establish a new base ROE and zone of reasonable returns that will be used, along with any ROE adders, to calculate the refund liability for the Second Refund Period. We anticipate a FERC order on the Second Complaint in 2017.

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for the period from November 12, 2013 through September 30, 2016 . As of September 30, 2016 , our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $255.7 million for the Initial Complaint and Second Complaint, representing the best estimate of the probable aggregate refunds based on the resolution of the Initial Complaint in the September 2016 Order. As of December 31, 2015 , our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $168.0 million , which represented the low end of the range of potential refunds as of that date, as there was no best estimate within the range of refunds at that time. The recognition of this estimated liability resulted in the following impacts to our condensed consolidated results of operations:



	Three months ended						Nine months ended
	September 30,						September 30,
(in millions)	2016			2015			2016			2015
Increase (decrease) in:
Operating revenues	$	(55.0	)	$	(18.0	)	$	(80.7	)	$	(38.8	)
Interest expense	3.9			0.5			7.0			1.4
Estimated net income (a)	(35.7		)	(11.2		)	(53.4		)	(24.5		)

____________________________


(a)	Includes an effect on net income of $27.1 million for the three and nine months ended September 30, 2016 for revenue initially recognized in 2015, 2014 and 2013. There was no effect on net income for the three and nine months ended September 30, 2015 for revenue initially recognized in a prior period.

It is possible the outcome of these matters could differ from the estimated range of losses and materially affect our consolidated results of operations due to the uncertainty of the calculation of an authorized base ROE along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC. As of September 30, 2016 , our MISO Regulated Operating Subsidiaries had a total of approximately $2.9 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point reduction in the authorized ROE would reduce annual consolidated net income by approximately $2.9 million .

In a separate but related matter, in November 2014, METC, ITC Midwest and other MISO TOs filed a request with the FERC, under FPA Section 205, for authority to include a 50 basis point incentive adder for RTO participation in each of the TOs’ formula rates. On January 5, 2015, the FERC approved the use of this incentive adder, effective January 6, 2015. Additionally, ITC Midwest filed a request with the FERC, under FPA Section 205, in January 2015 for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently authorized for ITCTransmission and METC. On March 31, 2015, the FERC approved the use of a 50 basis point incentive adder for independence, effective April 1, 2015. On April 30, 2015, ITC Midwest filed a request with the FERC for rehearing on the approved incentive adder for independence and this request was subsequently denied by the FERC on January 6, 2016. An appeal of the FERC’s decision has been filed. Beginning September 28, 2016, these incentive adders have been applied to METC’s and ITC Midwest’s base ROEs in establishing their total authorized ROE rates, subject to the maximum ROE limitation in the September 2016 Order of 11.35% .

Challenges Regarding Bonus Depreciation

See “Challenges Regarding Bonus Depreciation” in Note 4 for discussion of these challenges.

Legal Matters Associated with the Merger

Following the announcement of the Merger, four putative state class action lawsuits were filed by purported shareholders of ITC Holdings on behalf of a purported class of ITC Holdings shareholders. Initially, the four actions ( Paolo Guerra v. Albert Ernst, et al. , Harvey Siegelman v. Joseph L. Welch, et al. , Alan Poland v. Fortis Inc., et al. , Sanjiv Mehrotra v. Joseph L. Welch, et al.) were filed in the Oakland County Circuit Court of the State of Michigan. The complaints name as defendants a combination of ITC Holdings and the individual members of the ITC Holdings board of directors, Fortis, FortisUS and Merger Sub. The complaints generally allege, among other things, that (1) ITC Holdings’ directors breached their fiduciary duties in connection with the Merger Agreement, (including, but not limited to, various alleged breaches of duties of good faith, loyalty, care and independence), (2) ITC Holdings’ directors failed to take appropriate steps to maximize shareholder value and claims that the Merger Agreement contains several deal protection provisions that are unnecessarily preclusive and (3) a combination of ITC Holdings, Fortis, FortisUS and Merger Sub aided and abetted the purported breaches of fiduciary duties. The complaints seek class action certification and a variety of relief including, among other things, enjoining defendants from completing the Merger, unspecified rescissory and compensatory damages, and costs, including attorneys’ fees and expenses. The Siegelman case was voluntarily dismissed by the plaintiff on March 22, 2016. On March 23, 2016, the state

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court entered an order directing that the related cases be consolidated under the caption In re ITC Holdings Corporation Shareholder Litigation. On April 8, 2016, Poland filed an amended complaint to add derivative claims on behalf of ITC Holdings.

On March 14, 2016, the Guerra state court action was dismissed by the plaintiff and refiled in the United States District Court, Eastern District of Michigan, as Paolo Guerra v. Albert Ernst, et al . The federal complaint names the same defendants (plus FortisUS), asserts the same general allegations and seeks the same types of relief as in the state court cases. On March 25, 2016, Guerra amended his federal complaint. The amended complaint dropped Fortis US, Fortis and Merger Sub as defendants and added claims alleging that the defendants violated Sections 14(a) and 20(a) of the Exchange Act because the preliminary proxy statement/prospectus, filed with the SEC in connection with the special meeting of shareholders to approve the Merger Agreement, was allegedly materially misleading and allegedly omitted material facts that were necessary to render it non-misleading.

Another lawsuit was filed on April 8, 2016 in the United States District Court, Eastern District of Michigan captioned Harold Severance v. Joseph L. Welch et al. against the individual members of the ITC Holdings board of directors, Fortis, FortisUS and Merger Sub, asserting the same general allegations and seeking the same type of relief as Guerra .

On April 22, 2016, the Mehrotra state court action was dismissed by the plaintiff and refiled in the United States District Court, Eastern District of Michigan, as Sanjiv Mehrotra v. Joseph L. Welch, et al . With the exception of Fortis, the federal complaint names the same defendants and asserts the same general allegations as the other federal complaints.

On June 8, 2016, the state court denied a motion for summary disposition filed by ITC Holdings and the individual members of the ITC Holdings board of directors. ITC Holdings voluntarily made supplemental disclosures related to the Merger in response to certain allegations, which are set forth in a Form 8-K filed with the SEC on June 13, 2016. Nothing in those supplemental disclosures shall be deemed an admission of the legal necessity or materiality under applicable laws of any of the disclosures set forth therein.

On July 6, 2016, the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC Holdings and the individual members of the ITC Holdings board of directors reserved the right to oppose any such claim.

On July 8, 2016, the plaintiffs in Poland filed a motion for class certification. On July 13, 2016, ITC Holdings and the individual members of the ITC Holdings board of directors filed their respective answers to the amended complaint in Poland . On July 19, 2016, the Poland state court issued a scheduling order, which, among other things, requires the parties to complete discovery by March 10, 2017, and sets a trial date for June 5, 2017. On July 25, 2016, the Poland state court issued an order allowing a new plaintiff, Washtenaw County Employees’ Retirement System, to intervene in the Poland case.

We believe the remaining lawsuit is without merit and intend to vigorously defend against it. Additional lawsuits arising out of or relating to the Merger Agreement or the Merger may be filed in the future. See Note 2 for additional discussion on the Merger.

12 . SEGMENT INFORMATION

We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise, including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses. As discussed in Note 4 , during the second quarter of 2016, ITC Interconnection became a transmission owner in the FERC-approved RTO, PJM Interconnection. As a result, the newly regulated transmission business at ITC Interconnection is included, along with our Regulated Operating Subsidiaries, in the regulated operations segment as of June 1, 2016. The following tables show our financial information by reportable segment:



	Three months ended						Nine months ended
OPERATING REVENUES:	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Regulated operations (a)	$	261,156		$	273,012		$	839,126		$	820,452
ITC Holdings and other	93			334			688			720
Intercompany eliminations	(7,798		)	(157		)	(8,186		)	(438		)
Total Operating Revenues	$	253,451		$	273,189		$	831,628		$	820,734

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	Three months ended						Nine months ended
INCOME BEFORE INCOME TAXES:	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Regulated operations (a)	$	119,862		$	138,532		$	439,288		$	436,990
ITC Holdings and other	(41,127		)	(34,853		)	(140,668		)	(110,287		)
Total Income Before Income Taxes	$	78,735		$	103,679		$	298,620		$	326,703



	Three months ended						Nine months ended
NET INCOME:	September 30,						September 30,
(in thousands)	2016			2015			2016			2015
Regulated operations (a)	$	74,965		$	85,971		$	272,085		$	269,491
ITC Holdings and other	49,638			65,573			184,601			205,041
Intercompany eliminations	(74,965		)	(85,971		)	(272,085		)	(269,491		)
Total Net Income	$	49,638		$	65,573		$	184,601		$	205,041



TOTAL ASSETS:	September 30,			December 31,
(in thousands)	2016			2015
Regulated operations	$	7,969,771		$	7,463,557
ITC Holdings and other	4,253,150			4,147,915
Reconciliations / Intercompany eliminations (b)	(4,171,234		)	(4,056,150		)
Total Assets	$	8,051,687		$	7,555,322

____________________________


(a)	Amount includes the results of operations from ITC Interconnection for the period June 1, 2016 through September 30, 2016 .


(b)	Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our subsidiaries in the regulated operations segment as compared to the classification in our condensed consolidated statements of financial position.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities, the outlook for our business and the electric transmission industry, expectations with respect to various legal and regulatory proceedings and the Merger with Fortis based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “projects,” “likely” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are based on estimates and assumptions and subject to significant risks and uncertainties which could cause our actual results, performance and achievements to differ materially from those expressed in, or implied by, these statements, including, among others, the risks and uncertainties listed in “Item 1A Risk Factors” of our Form 10-K for the year ended December 31, 2015 , and the following:


•	Certain elements of our Regulated Operating Subsidiaries’ formula rates can be and have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows.

•

Our actual capital investment may be lower than planned, which would cause a lower than anticipated rate base and would therefore result in lower revenues and earnings compared to our current expectations. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot provide assurance that we will be able to initiate or complete any of these investments. In addition, we expect to incur expenses related to the pursuit of development opportunities, which may be higher than forecasted.


•	The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.


•	Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.


•	If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of collection of our revenues would be delayed.


•	Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.


•	A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete construction projects in a timely manner.


•	We contract with third parties to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.


•	Hazards associated with high-voltage electricity transmission may result in suspension of our operations or the imposition of civil or criminal penalties.


•	We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.

•

We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.


•	Acts of war, terrorist attacks, cyber attacks, natural disasters, severe weather and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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•	ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to fulfill our cash obligations.


•	We have a considerable amount of debt and our reliance on debt financing may limit our ability to fulfill our debt obligations and/or to obtain additional financing.


•	Certain provisions in our debt instruments limit our financial and operating flexibility.


•	Adverse changes in our credit ratings may negatively affect us.


•	ITC Holdings and its subsidiaries are subject to business uncertainties during the period of integration with Fortis that could adversely affect ITC Holdings’ financial results.


•	We will continue to incur substantial transaction-related costs in connection with the Merger.


•	We are the target of securities class action and derivative lawsuits, which could result in substantial costs and diversion of management’s time and resources.

Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events or otherwise.

OVERVIEW

Through our Regulated Operating Subsidiaries and ITC Interconnection, we operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and upgrade the transmission networks to support new generating resources interconnecting to our transmission systems. We also are pursuing development projects not within our existing systems, which are likewise intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.

As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates, as discussed in Note 4 to the condensed consolidated financial statements under “— Cost-Based Formula Rate Templates with True-Up Mechanism.”

Our Regulated Operating Subsidiaries’ primary operating responsibilities include maintaining, improving and expanding their transmission systems to meet their customers’ ongoing needs, scheduling outages on system elements to allow for maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded.

We derive nearly all of our revenues from providing electric transmission service over our Regulated Operating Subsidiaries’ transmission systems to investor-owned utilities, such as DTE Electric, Consumers Energy and IP&L, and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers as well as from transaction-based capacity reservations on our transmission systems.

Significant recent matters that influenced our financial position and results of operations and cash flows for the nine months ended September 30, 2016 or that may affect future results include:

•

Our capital expenditures of $560.6 million at our Regulated Operating Subsidiaries and ITC Interconnection during the nine months ended September 30, 2016 as described below under “— Capital Investment and Operating Results Trends,” resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;


•	Debt issuances as described in Note 6 to the condensed consolidated financial statements and borrowings under our revolving credit agreements in 2016 and 2015 to fund capital investment at our Regulated Operating Subsidiaries and ITC Interconnection as well as for general corporate purposes;

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•	Debt maturing within one year of $185.8 million as of September 30, 2016 and the potentially higher interest rates associated with the additional financing required to repay this debt;

•

Recognition of the liability for the refund and potential refund relating to the rate of return on equity (“ROE”) complaints, as described in Note 11 to the condensed consolidated financial statements, which resulted in a total estimated pre-tax reduction of revenue and additional interest of $58.9 million and $87.7 million and an estimated after-tax reduction to net income of $35.7 million and $53.4 million for the three and nine months ended September 30, 2016 , respectively;

•

Election of bonus depreciation for tax years 2015 and 2016 as well as the simulation of ITC Midwest’s 2015 revenue requirement with the election of bonus depreciation. The total impact from these matters was lower revenues of approximately $4.2 million and $13.2 million and lower net income of approximately $2.5 million and $7.9 million , for the three and nine months ended September 30, 2016 , respectively. These matters also resulted in additional net deferred income tax liabilities of approximately $145.4 million as of September 30, 2016 , and a corresponding income tax refund of $128.2 million , which was received from the Internal Revenue Service (“IRS”) in August 2016;

•

Recognition of the refund liability, including interest, associated with regional cost allocation as described in Note 4 to the condensed consolidated financial statements, which resulted in a reduction to regional cost sharing revenues and an offsetting increase to network revenues for the three and nine months ended September 30, 2016 . This refund, including interest, was provided to New York Independent System Operator and PJM Interconnection (“other RTOs”) in October 2016. The timing for collection from our network customers of the amount refunded to the other RTOs has not yet been determined, but is expected to occur no later than 2018; and

•

As a result of the Merger with Fortis consummated on October 14, 2016, ITC Holdings became an indirect subsidiary of Fortis as described below under “— Capital Project Updates and Other Recent Developments — The Merger.” For the three and nine months ended September 30, 2016 , we expensed external legal, advisory and financial services fees of $2.0 million and $24.3 million , respectively, and certain internal labor and associated costs of approximately $3.1 million and $9.4 million , respectively, related to the Merger, recorded within general and administrative expenses. In addition, subsequent to September 30, 2016 through the date of this filing, we have incurred external legal, advisory and financial services fees and certain internal labor and associated costs related to the Merger of approximately $75 million , including approximately $41 million of expense recognized due to the accelerated vesting of the share-based compensation awards described in Note 2 to the condensed consolidated financial statements. Certain amounts of the external costs are not expected to be deductible for income tax purposes. The external and internal costs related to the Merger are not included as components of revenue requirement as they were incurred at ITC Holdings.

These items are discussed in more detail throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Capital Project Updates and Other Recent Developments

The Merger

On February 9, 2016, ITC Holdings entered into the Merger Agreement with Fortis, FortisUS and Merger Sub. On April 20, 2016, Fortis reached a definitive agreement with GIC Private Limited for GIC to acquire an indirect 19.9% equity interest in ITC Holdings upon completion of the Merger. On October 14, 2016, ITC Holdings and Fortis completed the Merger contemplated by the Merger Agreement. On the same date, the common shares of ITC Holdings were delisted from the NYSE and the common shares of Fortis were listed and began trading on the NYSE. Fortis continues to have its shares listed on the Toronto Stock Exchange. As a result of the Merger, Merger Sub merged with and into ITC Holdings with ITC Holdings continuing as the surviving corporation and becoming a majority owned indirect subsidiary of FortisUS. In the Merger, ITC Holdings shareholders received $22.57 in cash and 0.7520 Fortis common shares for each share of common stock of ITC Holdings. Refer to Note 2 to the condensed consolidated financial statements for further details on the Merger.

Development Bonuses

We recognized general and administrative expenses of $0.9 million during the nine months ended September 30, 2016 and $0.3 million and $10.1 million during the three and nine months ended September 30, 2015 , respectively, for bonuses for certain development projects, including the successful completion of certain milestones relating to projects at ITC Great Plains. We did not recognize any general and administrative expenses for development bonuses during the three months ended September 30, 2016 .

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Regional Infrastructure Projects

2011 MISO Multi-Value Projects

In December 2011, MISO approved a portfolio of Multi-Value Projects (“MVPs”) which includes portions of four MVPs that we will construct, own and operate. The four MVPs are located in south central Minnesota, northern and southeast Iowa, southwest Wisconsin, and northeast Missouri and are in various stages of construction at ITC Midwest.

Thumb Loop Project

The Thumb Loop Project, constructed by ITCTransmission, consists of a 140-mile, double-circuit 345 kV transmission line and related substations that now serves as the backbone of the transmission system needed to accommodate future wind development projects in the Michigan counties of Tuscola, Huron, Sanilac and St. Clair. The final phase of the Thumb Loop Project was placed in-service in May 2015. Through September 30, 2016 , ITCTransmission has invested $503.5 million in the Thumb Loop Project and any further investment to complete this project is not expected to be material.

ITC Interconnection

ITC Interconnection was formed in 2014 by ITC Holdings to pursue transmission investment opportunities. On June 1, 2016, ITC Interconnection acquired certain transmission assets from a merchant generating company and placed a newly constructed 345 kV transmission line in service. As a result, ITC Interconnection became a transmission owner in the FERC-approved RTO, PJM Interconnection, and is subject to rate-regulation by the FERC. The revenues earned by ITC Interconnection are based on its facilities reimbursement agreement with the merchant generating company. The financial results of ITC Interconnection are currently not material to our consolidated financial statements.

Rate of Return on Equity Complaints

On November 12, 2013, certain parties filed a joint complaint with the FERC under Section 206 of the FPA (the “Initial Complaint”), requesting that the FERC find the current 12.38% MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including ITCTransmission, METC and ITC Midwest, to no longer be just and reasonable. The complainants sought a FERC order reducing the base ROE used in the formula transmission rates for our MISO Regulated Operating Subsidiaries to 9.15% , reducing the equity component of our capital structure from the FERC approved 60% to 50% and terminating the ROE adders currently approved for certain ITC Holdings operating companies, including adders currently utilized by ITCTransmission and METC.

On December 22, 2015, the presiding administrative law judge issued an initial decision on the Initial Complaint. On September 28, 2016, the FERC issued an order (the “September 2016 Order”) affirming the presiding administrative law judge’s initial decision and setting the base ROE at 10.32% , with a maximum ROE of 11.35% , effective for the period from November 12, 2013 through February 11, 2015 (the “Initial Refund Period”). Additionally, the rates established by the September 2016 Order will be used prospectively from the date of the order until a new approved rate is established by the Second Complaint described below, which result in an ROE used currently by ITCTransmission, METC and ITC Midwest of 11.35% , 11.35% and 11.32% , respectively. The September 2016 Order requires all MISO TOs, including ITCTransmission, METC and ITC Midwest, to provide refunds within 30 days for the Initial Refund Period. The estimated refund for the Initial Complaint resulting from this FERC order, including interest, is $117.4 million for our MISO Regulated Operating Subsidiaries, recorded in current liabilities on the condensed consolidated statements of financial position. On October 21, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for an extension of nine months to provide refunds until July 28, 2017, which was granted by the FERC on October 28, 2016. Additionally, on October 28, 2016, the MISO TOs, including our MISO Regulated Operating Subsidiaries, filed a request with the FERC for rehearing of the September 2016 Order regarding the future exclusion of certain short-term growth projections in the two-step DCF analysis.

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On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the “Second Complaint”) by separate complainants, seeking a FERC order to reduce the base ROE used in the formula transmission rates of our MISO Regulated Operating Subsidiaries to 8.67% , with an effective date of February 12, 2015. On March 11, 2015, the MISO TOs filed an answer to the Second Complaint with the FERC supporting the current base ROE as just and reasonable. On June 18, 2015, the FERC accepted the Second Complaint and set it for hearing and settlement procedures. The FERC also set the refund effective date for the Second Complaint as February 12, 2015.

In addition to the estimated refund for the Initial Complaint noted above, we believe it is probable that a refund will be required in connection with the Second Complaint. As of September 30, 2016 , the estimated range of aggregate refunds for both the Initial Complaint and Second Complaint is expected to be from $219.0 million to $255.7 million on a pre-tax basis for the period from November 12, 2013 through September 30, 2016 . As of September 30, 2016 , our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $255.7 million for the Initial Complaint and Second Complaint, representing the best estimate of the probable aggregate refunds based on the resolution of the Initial Complaint in the September 2016 Order. As of December 31, 2015 , our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $168.0 million , which represented the low end of the range of potential refunds as of that date, as there was no best estimate within the range of refunds at that time. The recognition of this estimated liability resulted in the following impacts to our condensed consolidated results of operations:



	Three months ended						Nine months ended
	September 30,						September 30,
(in millions)	2016			2015			2016			2015
Increase (decrease) in:
Operating revenues	$	(55.0	)	$	(18.0	)	$	(80.7	)	$	(38.8	)
Interest expense	3.9			0.5			7.0			1.4
Estimated net income	(35.7		)	(11.2		)	(53.4		)	(24.5		)

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MISO Formula Rate Template Modifications Filing

On October 30, 2015, our MISO Regulated Operating Subsidiaries requested modifications, pursuant to Section 205 of the FPA, to certain aspects of their respective formula rate templates which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. Our MISO Regulated Operating Subsidiaries requested an effective date of January 1, 2016 for the proposed template changes. On December 30, 2015, the FERC conditionally accepted the formula rate template modifications and required a further compliance filing, which was made on February 8, 2016. On April 14, 2016, the FERC issued an order accepting the February 8, 2016 compliance filing, effective January 1, 2016. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that resulted in the joint applicants recovering excess amounts from customers. As of September 30, 2016 and December 31, 2015 , our MISO Regulated Operating Subsidiaries had recorded an aggregate refund liability of $4.4 million and $10.4 million , respectively.

Challenges Regarding Bonus Depreciation

On December 18, 2015, IP&L filed a formal challenge (“IP&L challenge”) with the FERC against ITC Midwest on certain inputs to ITC Midwest’s formula rates. The IP&L challenge alleged that ITC Midwest has unreasonably and imprudently opted out of using bonus depreciation in the calculation of its federal income tax expense and thereby unduly increased the transmission charges for transmission service to customers. On March 11, 2016, the FERC granted the IP&L challenge in part by requiring ITC Midwest to recalculate its revenue requirements, effective January 1, 2015, to simulate the election of bonus depreciation for 2015. The FERC denied IP&L’s request that ITC Midwest be required to elect bonus depreciation in any past or future years; however, stakeholders will be able to challenge any decision by ITC Midwest not to take bonus depreciation in future years. On June 8, 2016, the FERC denied ITC Midwest’s request for rehearing of the March 11, 2016 order. On August 3, 2016, ITC Midwest filed a petition for review of the FERC’s March 11, 2016 and June 8, 2016 orders in the United States Court of Appeals, District of Columbia Circuit. On September 8, 2016, ITC Midwest filed a motion to defer the petition pending the issuance of a private letter ruling from the IRS. Additionally, on April 15, 2016, Consumers Energy Company filed a formal challenge, or in the alternative, a complaint under Section 206 of the FPA, with the FERC against METC relating to METC’s historical practice of opting out of using bonus depreciation. On July 8, 2016, the FERC denied Consumers Energy Company’s formal challenge and dismissed the complaint without prejudice.

These condensed consolidated financial statements reflect the election of bonus depreciation for tax years 2015 and 2016 and the corresponding effects on 2016 revenue requirements for our Regulated Operating Subsidiaries. Additionally, as required by the March 11, 2016 FERC order, we have simulated the election of bonus depreciation for ITC Midwest’s 2015 revenue requirement and included the impact of the corresponding refund obligation in these condensed consolidated financial statements. The total impact from reflecting the election of bonus depreciation as described above was lower revenues of $4.2 million and $13.2 million and lower net income of approximately $2.5 million and $7.9 million for the three and nine months ended September 30, 2016 , respectively, as compared to the same period if bonus depreciation was not reflected. These matters also resulted in additional net deferred income tax liabilities of approximately $145.4 million as of September 30, 2016 , and a corresponding income tax refund of $128.2 million , which was received from the IRS in August 2016. We are unable to predict the final outcome of this matter; however, the election of bonus depreciation will result in higher cash flows in the year of the election and reduce our rate base and therefore decrease our revenues and net income over the tax lives of the eligible assets. Bonus depreciation is currently enacted through 2019, with certain provisions that allow for an additional year of eligibility for certain property with long construction periods. If bonus depreciation is elected for a given year, we estimate that, based on an amount of tax additions that may be eligible for bonus depreciation representative of our investment plans in the near term, the higher deferred tax liabilities and the corresponding reduced rate base could reduce revenues recognized by us initially for that year by $15 million to $20 million , with a corresponding reduction to annual net income of $9 million to $12 million (disregarding any favorable effects from the use of the potential cash tax savings), with the negative effect on annual revenues and net income relating to each year’s election decreasing each year over the tax lives of the assets.

Cost-Based Formula Rate Templates with True-Up Mechanism

Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rate templates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under their cost-based formula rate templates, each of our Regulated Operating Subsidiaries separately calculates a revenue requirement based on financial information specific to each company. The calculation of projected revenue requirement for a future period is used to establish the transmission rate used for billing purposes. The calculation of actual revenue requirements

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for a historic period is used to calculate the amount of revenues recognized in that period and determine the over- or under-collection for that period.

Under these formula rate templates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current basis, rather than lagging. The formula rate templates for a given year initially utilize forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our cost-based formula rate templates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns.

Revenue Accruals and Deferrals — Effects of Monthly Peak Loads

For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based formula rates that contain a true-up mechanism, our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is generally impacted by weather and economic conditions and seasonally shaped with higher load in the summer months when cooling demand is higher.

ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month and, therefore, peak load does not have a seasonal effect on operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP.

Capital Investment and Operating Results Trends

We expect a long-term upward trend in revenues and earnings, subject to the impact of any rate changes and required refunds resulting from the resolution of the ROE complaints as described in Note 11 to the condensed consolidated financial statements. The primary factor that is expected to continue to increase our revenues and earnings in future years is increased rate base that would result from our anticipated capital investment, in excess of depreciation, from our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. In addition, our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that would position us for long-term growth. Investments in property, plant and equipment, when placed in-service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries.

Our Regulated Operating Subsidiaries and ITC Interconnection strive for high reliability of their systems and improvement in system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe that we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.

We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to (1) rebuild existing property, plant and equipment; (2) upgrade the system to address demographic changes that have impacted transmission load and the changing role that

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transmission plays in meeting the needs of the wholesale market, including accommodating the siting of new generation or increasing import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards. The following table shows our actual and expected capital expenditures at our Regulated Operating Subsidiaries and ITC Interconnection:



	Actual Capital		Forecasted
	Expenditures for the		Capital
	nine months ended		Expenditures
(in millions)	September 30, 2016		2017 — 2021
Expenditures for property, plant and equipment (a)	$	560.6	$	2,811

____________________________


(a)	Amounts represent the cash payments to acquire or construct property, plant and equipment, as presented in the condensed consolidated statements of cash flows. These amounts exclude non-cash additions to property, plant and equipment for the allowance for equity funds used during construction as well as accrued liabilities for construction, labor and materials that have not yet been paid.

Refer to “Item 1 Business — Development of Business — Development Projects” in our Form 10-K for the year ended December 31, 2015 for a discussion of our development projects. We are pursuing projects that could result in a significant amount of capital investment, but are not able to estimate the amounts we ultimately expect to achieve or the timing of such investments.

Investments in property, plant and equipment could vary due to, among other things, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain any necessary financing for such expenditures, limitations on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a result of legal proceedings, variances between estimated and actual costs of construction contracts awarded and the potential for greater competition for new development projects. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects and other factors beyond our control.

RESULTS OF OPERATIONS

Results of Operations and Variances



	Three months ended									Percentage		Nine months ended									Percentage
	September 30,						Increase			increase		September 30,						Increase			increase
(in thousands)	2016			2015			(decrease)			(decrease)		2016			2015			(decrease)			(decrease)
OPERATING REVENUES	$	253,451		$	273,189		$	(19,738	)	(7.2	)%	$	831,628		$	820,734		$	10,894		1.3	%
OPERATING EXPENSES
Operation and maintenance	30,326			32,721			(2,395		)	(7.3	)%	82,533			88,309			(5,776		)	(6.5	)%
General and administrative	35,752			33,677			2,075			6.2	%	130,922			107,064			23,858			22.3	%
Depreciation and amortization	39,599			36,890			2,709			7.3	%	117,840			106,903			10,937			10.2	%
Taxes other than income taxes	22,645			20,463			2,182			10.7	%	68,444			61,629			6,815			11.1	%
Other operating (income) and expenses — net	(293		)	(206		)	(87		)	42.2	%	(839		)	(675		)	(164		)	24.3	%
Total operating expenses	128,029			123,545			4,484			3.6	%	398,900			363,230			35,670			9.8	%
OPERATING INCOME	125,422			149,644			(24,222		)	(16.2	)%	432,728			457,504			(24,776		)	(5.4	)%
OTHER EXPENSES (INCOME)
Interest expense — net	55,843			51,398			4,445			8.6	%	158,064			150,070			7,994			5.3	%
Allowance for equity funds used during construction	(10,002		)	(6,421		)	(3,581		)	55.8	%	(26,442		)	(21,434		)	(5,008		)	23.4	%
Other income	(408		)	(384		)	(24		)	6.3	%	(1,149		)	(804		)	(345		)	42.9	%
Other expense	1,254			1,372			(118		)	(8.6	)%	3,635			2,969			666			22.4	%
Total other expenses (income)	46,687			45,965			722			1.6	%	134,108			130,801			3,307			2.5	%
INCOME BEFORE INCOME TAXES	78,735			103,679			(24,944		)	(24.1	)%	298,620			326,703			(28,083		)	(8.6	)%
INCOME TAX PROVISION	29,097			38,106			(9,009		)	(23.6	)%	114,019			121,662			(7,643		)	(6.3	)%
NET INCOME	$	49,638		$	65,573		$	(15,935	)	(24.3	)%	$	184,601		$	205,041		$	(20,440	)	(10.0	)%

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Operating Revenues

Three months ended September 30, 2016 compared to three months ended September 30, 2015

The following table sets forth the components of and changes in operating revenues:



														Percentage
	2016					2015					Increase			increase
(in thousands)	Amount			Percentage		Amount			Percentage		(decrease)			(decrease)
Network revenues	$	240,215		94.8	%	$	205,527		75.2	%	$	34,688		16.9	%
Regional cost sharing revenues	55,867			22.0	%	85,616			31.3	%	(29,749		)	(34.7	)%
Point-to-point	5,637			2.2	%	3,922			1.4	%	1,715			43.7	%
Scheduling, control and dispatch	3,540			1.4	%	3,328			1.2	%	212			6.4	%
Other	3,168			1.3	%	1,383			0.5	%	1,785			129.1	%
Recognition of rate refund liability	(54,976		)	(21.7	)%	(26,587		)	(9.6	)%	(28,389		)	106.8	%
Total	$	253,451		100.0	%	$	273,189		100.0	%	$	(19,738	)	(7.2	)%

The recognition of the refund liability associated with regional cost allocation, described in Note 4 to the condensed consolidated financial statements, resulted in a reduction to regional cost sharing revenues of $28.7 million and an offsetting increase to network revenues during the three months ended September 30, 2016 .

Network revenues also increased partially due to higher net revenue requirements at our Regulated Operating Subsidiaries during the three months ended September 30, 2016 as compared to the same period in 2015 . Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service. The increases in network revenues were partially offset by the election of bonus depreciation as described in Note 4 to the condensed consolidated financial statements.

The recognition of the liability for the refund and potential refund relating to the ROE complaints, described in Note 11 to the condensed consolidated financial statements, resulted in a reduction to operating revenues of $55.0 million and $26.6 million during the three months ended September 30, 2016 and 2015 , respectively. We are not able to estimate whether any required refunds would be applied to all components of revenue listed in the table above or only certain components.

Operating revenues for the three months ended September 30, 2016 include revenue accruals and deferrals as described in Note 4 to the condensed consolidated financial statements.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015

The following table sets forth the components of and changes in operating revenues:



														Percentage
	2016					2015					Increase			increase
(in thousands)	Amount			Percentage		Amount			Percentage		(decrease)			(decrease)
Network revenues	$	647,660		77.9	%	$	595,782		72.6	%	$	51,878		8.7	%
Regional cost sharing revenues	225,891			27.2	%	240,949			29.4	%	(15,058		)	(6.2	)%
Point-to-point	13,609			1.6	%	11,972			1.5	%	1,637			13.7	%
Scheduling, control and dispatch	10,432			1.3	%	9,691			1.2	%	741			7.6	%
Other	14,729			1.7	%	9,763			1.2	%	4,966			50.9	%
Recognition of rate refund liability	(80,693		)	(9.7	)%	(47,423		)	(5.9	)%	(33,270		)	70.2	%
Total	$	831,628		100.0	%	$	820,734		100.0	%	$	10,894		1.3	%

Network revenues also increased partially due to higher net revenue requirements at our Regulated Operating Subsidiaries during the nine months ended September 30, 2016 as compared to the same period in 2015 . Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service. The increases in network revenues were partially offset by the election of bonus depreciation as described in Note 4 to the condensed consolidated financial statements.

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The decrease in regional cost sharing revenues described above was partially offset by additional capital projects identified by MISO and SPP as eligible for regional cost sharing and these projects being placed in-service, in addition to higher accumulated investment for the Thumb Loop Project and Kansas V-Plan Project.

The recognition of the liability for the refund and potential refund relating to the ROE complaints, described in Note 11 to the condensed consolidated financial statements, resulted in a reduction to operating revenues of $80.7 million and $47.4 million during the nine months ended September 30, 2016 and 2015 , respectively. We are not able to estimate whether any required refunds would be applied to all components of revenue listed in the table above or only certain components.

Operating revenues for the nine months ended September 30, 2016 include revenue accruals and deferrals as described in Note 4 to the condensed consolidated financial statements.

Operating Expenses

Operation and maintenance expenses

Three months ended September 30, 2016 compared to three months ended September 30, 2015

Operation and maintenance expenses decreased due primarily to lower expenses associated with structure and overhead line maintenance activities and rent, partially offset by higher vegetation management requirements.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015

Operation and maintenance expenses decreased due primarily to lower vegetation management requirements and expenses associated with rent and structure maintenance activities.

General and administrative expenses

Three months ended September 30, 2016 compared to three months ended September 30, 2015

General and administrative expenses increased due primarily to higher compensation and benefit expenses of $4.9 million due to retention bonuses relating to the Merger, personnel additions and additional stock compensation expense. This increase was partially offset by a $2.4 million decrease in professional services such as legal and advisory services fees, which were related primarily to various development initiatives.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015

General and administrative expenses increased due primarily to a $24.3 million increase in external legal, advisory and consulting services relating to the Merger and a $13.4 million increase in compensation and benefit expenses due to retention bonuses relating to the Merger, personnel additions and additional stock compensation expense. These increases were partially offset by a $9.3 million decrease in development bonus expenses as described under “Capital Project Updates and Other Recent Developments — Development Bonuses.”

Depreciation and amortization expenses

Three and nine months ended September 30, 2016 compared to three and nine months ended September 30, 2015

Depreciation and amortization expenses increased due primarily to a higher depreciable base resulting from property, plant and equipment in-service additions.

Taxes other than income taxes

Three and nine months ended September 30, 2016 compared to three and nine months ended September 30, 2015

Taxes other than income taxes increased due to higher property tax expenses due primarily to our Regulated Operating Subsidiaries’ 2015 capital additions, which are included in the assessments for 2016 personal property taxes.

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Other Expenses (Income)

Three and nine months ended September 30, 2016 compared to three and nine months ended September 30, 2015

Interest Expense

Interest expense increased due primarily to the additional interest expense associated with the refund liability relating to the ROE complaints described in Note 11 to the condensed consolidated financial statements and long-term debt issuances subsequent to September 30, 2015, which were used for refinancing of current debt maturities and general corporate purposes.

Allowance for Equity Funds Used During Construction

Allowance for Equity Funds Used During Construction (“AFUDC equity”) decreased due primarily to lower balances of construction work in progress eligible for AFUDC equity during 2016.

Income Tax Provision

Three months ended September 30, 2016 compared to three months ended September 30, 2015

Our effective tax rates for the three months ended September 30, 2016 and 2015 were 37.0% and 36.8% , respectively. Our effective tax rate in both periods exceeded our 35% statutory federal income tax rate due primarily to state income taxes as well as the non-deductibility of certain costs incurred to facilitate the consummation of the Merger, partially offset by the tax effects of AFUDC equity which reduced the effective tax rate. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision. We recorded a state income tax provision of $3.0 million (net of federal deductibility) during the three months ended September 30, 2016 compared to a state income tax provision of $3.8 million (net of federal deductibility) for the three months ended September 30, 2015 .

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015

Our effective tax rates for the nine months ended September 30, 2016 and 2015 were 38.2% and 37.2% , respectively. Our effective tax rate in both periods exceeded our 35% statutory federal income tax rate due primarily to state income taxes as well as the non-deductibility of certain costs incurred to facilitate the consummation of the Merger, partially offset by the tax effects of AFUDC equity which reduced the effective tax rate. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision. We recorded a state income tax provision of $11.6 million (net of federal deductibility) during the nine months ended September 30, 2016 compared to a state income tax provision of $11.9 million (net of federal deductibility) for the nine months ended September 30, 2015 .

LIQUIDITY AND CAPITAL RESOURCES

We expect to maintain our approach to fund our future capital requirements with cash from operations at our Regulated Operating Subsidiaries and ITC Interconnection, our existing cash and cash equivalents, issuances under our commercial paper program and amounts available under our revolving credit agreements (the terms of which are described in Note 6 to the condensed consolidated financial statements). In addition, we may from time to time secure debt funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:


•	Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “— Capital Investment and Operating Results Trends.”


•	Fund business development expenses and related capital expenditures. We are pursuing development activities for transmission projects that will continue to result in the incurrence of development expenses and could result in significant capital expenditures.


•	Fund working capital requirements.


•	Fund our debt service requirements, including principal repayments and periodic interest payments. We expect our interest payments to increase each year as a result of additional debt expected to be incurred to fund our capital expenditures and for general corporate purposes.

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•	Fund contributions to our retirement benefit plans, as described in Note 9 to the condensed consolidated financial statements. We expect to make additional contributions of approximately $1.7 million to these plans in 2016.

In addition to the expected capital requirements above, any adverse determinations relating to the regulatory matters or contingencies described in Notes 4 and 11 to the condensed consolidated financial statements would result in additional capital requirements.

We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and fund capital investments. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any of our other subsidiaries as well as the proceeds raised from the sale of our debt securities. Each of our Regulated Operating Subsidiaries and ITC Interconnection, while wholly owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.

We expect to continue to utilize our commercial paper program and revolving credit agreements as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of September 30, 2016 , we had consolidated indebtedness under our revolving credit agreements of $237.4 million , with unused capacity under our revolving credit agreements of $762.6 million . Additionally, ITC Holdings had $135.9 million of commercial paper issued and outstanding as of September 30, 2016 , with the ability to issue an additional $264.1 million under the commercial paper program. See Note 6 to the condensed consolidated financial statements for a detailed discussion of the commercial paper program and our revolving credit agreements as well as the debt issuances and use of proceeds in 2016.

As of September 30, 2016 , we had approximately $50.0 million of fixed rate debt maturing within one year, which we expect to refinance with long-term debt. To address our long-term capital requirements as well as repay fixed rate debt maturing within one year, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed if we experience difficulties in accessing capital. We expect to be able to obtain such additional financing as needed, in amounts and upon terms that will be reasonably satisfactory to us due to our strong credit ratings and our historical ability to obtain financing.

Credit Ratings

Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money, and should not be viewed as a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.



Issuer	Issuance	Standard and Poor’s Ratings Services (a)	Moody’s Investor Service, Inc. (b)
ITC Holdings	Senior Unsecured Notes	BBB+	Baa2
ITC Holdings	Commercial Paper	A-2	Prime-2
ITCTransmission	First Mortgage Bonds	A	Al
METC	Senior Secured Notes	A	A1
ITC Midwest	First Mortgage Bonds	A	A1
ITC Great Plains	First Mortgage Bonds	A	A1

___________________________

(a)

On June 8, 2015, Standard and Poor’s Ratings Services (“Standard and Poor’s”) assigned a short-term issuer credit rating to ITC Holdings, which applies to the commercial paper program discussed in Note 6 to the condensed consolidated financial statements. Additionally, on October 18, 2016, Standard and Poor’s reaffirmed the senior unsecured credit rating of ITC Holdings and the secured credit ratings of the Regulated Operating Subsidiaries as well as revised the outlook of the issuer credit ratings of ITC Holdings and the Regulated Operating Subsidiaries to stable from negative, subsequent to the completion of the Merger. Refer to Note 2 to the condensed consolidated financial statements for details on the Merger.

(b)

On June 9, 2015, Moody’s Investor Service, Inc. (“Moody’s”) assigned a short-term commercial paper rating to ITC Holdings, which applies to the commercial paper program discussed in Note 6 to the condensed consolidated financial statements. Additionally, on April 15, 2016, Moody’s reaffirmed the credit ratings for the associated debt for ITC Holdings, ITCTransmission, ITC Midwest and ITC Great Plains. On April 26, 2016, Moody’s assigned a senior secured rating to

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METC’s 3.90% Senior Secured Note issuance described in Note 6 to the condensed consolidated financial statements. All of the credit ratings have a stable outlook.

Covenants

Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions as well as require us to meet certain financial ratios, which are described in Note 6 to the condensed consolidated financial statements and in our Form 10-K for the fiscal year ended December 31, 2015 . As of September 30, 2016 , we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving credit agreements would increase.

Cash Flows From Operating Activities

Net cash provided by operating activities was $587.1 million and $386.3 million for the nine months ended September 30, 2016 and 2015 , respectively. The increase in cash provided by operating activities was due primarily to receipt of the income tax refund of $128.2 million from the IRS in August 2016 and lower income taxes paid of $26.9 million during the nine months ended September 30, 2016 compared to the same period in 2015 , which both resulted from the election of bonus depreciation as described in Note 4 to the condensed consolidated financial statements. Additionally, the cash received from operating revenues increased by $60.8 million during the nine months ended September 30, 2016 compared to the same period in 2015 . These increases were partially offset by an increase in payments of operating expenses of $19.3 million .

Cash Flows From Investing Activities

Net cash used in investing activities was $556.7 million and $475.1 million for the nine months ended September 30, 2016 and 2015 , respectively. The increase in cash used in investing activities was due primarily to higher investments in property, plant and equipment and timing of payments of investments in property, plant and equipment during the nine months ended September 30, 2016 compared to the same period in 2015 .

Cash Flows From Financing Activities

Net cash used in financing activities was $35.3 million for the nine months ended September 30, 2016 as compared to the net cash provided by financing activities of $85.2 million for the nine months ended September 30, 2015 . The decrease in cash provided by financing activities was due primarily to a net decrease of $299.7 million in amounts outstanding under our revolving and term loan credit agreements, a decrease of $179.5 million in net issuances of commercial paper under our commercial paper program and an increase in payments of $139.3 million to retire long-term debt during the nine months ended September 30, 2016 compared to the same period in 2015 . These decreases were partially offset by an increase in long-term debt issuances of $374.5 million and higher net proceeds of $26.6 million associated with refundable deposits for transmission network upgrades. Additionally, during the nine months ended September 30, 2015 , we paid $115.0 million in connection with our accelerated share repurchase program. See Note 6 to the condensed consolidated financial statements on the issuances and retirement of long-term debt.

CONTRACTUAL OBLIGATIONS

Our contractual obligations are described in our Form 10-K for the year ended December 31, 2015 . There have been no material changes to that information since December 31, 2015 , other than the items listed below and described in Note 6 to the condensed consolidated financial statements:


•	Changes in amounts borrowed under our unsecured, unguaranteed revolving credit agreements;


•	Changes in commercial paper issued under the commercial paper program for ITC Holdings;


•	The issuance of $200.0 million of secured 3.90% Senior Notes, due April 26, 2046, by METC, which repaid the $200.0 million borrowed under METC’s term loan credit agreement;


•	The issuance of $400.0 million of unsecured 3.25% Notes, due June 30, 2026, by ITC Holdings, which repaid the $161.0 million outstanding under ITC Holdings’ term loan credit agreement and indebtedness under ITC Holdings’ commercial paper program;

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•	The repayment and retirement in September 2016 of $139.3 million of 5.875% ITC Holdings Senior Notes, due September 30, 2016, with the proceeds from the issuance of commercial paper under ITC Holdings’ commercial paper program;


•	The refund of $28.7 million required by the FERC order issued on September 22, 2016 associated with regional cost allocation, which was provided to the other RTOs in October 2016. See “Regional Cost Allocation” in Note 4 to the condensed consolidated financial statements for discussion on this matter; and


•	The refund of $117.4 million required by the FERC order issued on September 28, 2016 for the Initial Complaint. See “Rate of Return on Equity Complaints” in Note 11 to the condensed consolidated financial statements for a discussion of the complaint.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of these condensed consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events. These estimates and judgments, in and of themselves, could materially impact the condensed consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment. The accounting policies discussed in “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our Form 10-K for the fiscal year ended December 31, 2015 are considered by management to be the most important to an understanding of the consolidated financial statements because of their significance to the portrayal of our financial condition and results of operations or because their application places the most significant demands on management’s judgment and estimates about the effect of matters that are inherently uncertain. There have been no material changes to that information during the nine months ended September 30, 2016 .

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 3 to the condensed consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Fixed Rate Debt

Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper, was $4,592.1 million at September 30, 2016 . The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving credit agreements and commercial paper, was $4,110.9 million at September 30, 2016 . We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, at September 30, 2016 . An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at September 30, 2016 would decrease the fair value of debt by $172.6 million , and a decrease in interest rates of 10% at September 30, 2016 would increase the fair value of debt by $185.9 million at that date.

Revolving Credit Agreements

At September 30, 2016 , we had a consolidated total of $237.4 million outstanding under our revolving credit agreements, which are variable rate loans and fair value approximates book value. A 10% increase or decrease in borrowing rates under the revolving credit agreements compared to the weighted average rates in effect at September 30, 2016 would increase or decrease interest expense by $0.3 million , respectively, for an annual period with a constant borrowing level of $237.4 million .

Commercial Paper

At September 30, 2016 , ITC Holdings had $135.9 million of commercial paper issued and outstanding, net of discount, under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value. A 10% increase or decrease in interest rates for commercial paper would increase or decrease interest expense by $0.1 million for an annual period with a continuous level of commercial paper outstanding of $135.9 million .

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Derivative Instruments and Hedging Activities

We use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. In June 2016, we terminated $300.0 million of 10-year interest rate swap contracts that managed the interest rate risk associated with the unsecured Notes issued by ITC Holdings described in Note 6 to the condensed consolidated financial statements.

As of September 30, 2016 , we held 10-year interest rate swap contracts with a notional amount of $100.0 million , which manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 6.05% Senior Notes, due January 31, 2018. As of September 30, 2016 , ITC Holdings had $384.3 million outstanding under the 6.05% Senior Notes. See Note 6 to the condensed consolidated financial statements for further discussion on these interest rate swaps.

Other

As described in our Form 10-K for the fiscal year ended December 31, 2015 , we are subject to commodity price risk from market price fluctuations, and to credit risk primarily with DTE Electric, Consumers Energy and IP&L, our primary customers. There have been no material changes in these risks during the nine months ended September 30, 2016 .

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with a company have been detected.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the three months ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Note 4 to the condensed consolidated financial statements for discussion of the challenges against ITC Midwest and METC relating to the use of bonus depreciation as well as Note 11 to the condensed consolidated financial statements for a description of recent developments in the ROE complaints filed against all MISO TOs, including our MISO Regulated Operating Subsidiaries, and pending litigation associated with the Merger with Fortis.

ITEM 1A. RISK FACTORS

In view of the recent completion of our Merger with a subsidiary of Fortis and the recent developments with respect to the ROE complaints involving our MISO Regulated Operating Subsidiaries, we are amending and restating, in the manner set

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forth below, (a) the risk factor entitled “Certain elements of our Regulated Operating Subsidiaries’ formula rates can be and have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows.” and (b) all of the risk factors set forth under “Risks Relating to Our Corporate and Financial Structure” and “Risks Relating to the Merger,” in each case as previously disclosed in “Item 1A Risk Factors” of our Form 10-K for the year ended December 31, 2015 . Other than the foregoing, there have been no material changes to the risk factors set forth in “Item 1A Risk Factors” of our Form 10-K for the year ended December 31, 2015 .

Certain elements of our Regulated Operating Subsidiaries’ formula rates can be and have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows.

Our Regulated Operating Subsidiaries provide transmission service under rates regulated by the FERC. The FERC has approved the cost-based formula rate templates used by our Regulated Operating Subsidiaries to calculate their respective annual revenue requirements, but it has not expressly approved the amount of actual capital and operating expenditures to be used in the formula rates. All aspects of our Regulated Operating Subsidiaries’ rates approved by the FERC, including the formula rate templates, the rates of return on the actual equity portion of their respective capital structures and the approved targeted capital structures, are subject to challenge by interested parties at the FERC, or by the FERC on its own initiative in a proceeding under Section 206 of the FPA. In addition, interested parties may challenge the annual implementation and calculation by our Regulated Operating Subsidiaries of their projected rates and formula rate true up pursuant to their approved formula rate templates under the Regulated Operating Subsidiaries' formula rate implementation protocols. End-use consumers and entities supplying electricity to end-use consumers may also attempt to influence government and/or regulators to change the rate setting methodologies that apply to our Regulated Operating Subsidiaries, particularly if rates for delivered electricity increase substantially. If a challenger can establish that any of these aspects are unjust, unreasonable, unduly discriminatory or preferential, then the FERC will make appropriate prospective adjustments to them and/or disallow any of our Regulated Operating Subsidiaries’ inclusion of those aspects in the rate setting formula. This could result in lowered rates and/or refunds of amounts collected, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In November 2013, certain parties filed a joint complaint with the FERC under Section 206 of the FPA, requesting that the FERC find the base rate of return on equity for all MISO transmission owners, including ITCTransmission, METC and ITC Midwest, to be unjust and unreasonable. The joint complainants sought a FERC order reducing the base rate of return on equity used in the MISO transmission owners’ formula transmission rate, reducing the targeted equity component of MISO transmission owners’ capital structures and terminating the return on equity adders approved for ITCTransmission and METC. Although the FERC issued an order rejecting the November 2013 complaint as to the capital structures and ITCTransmission's and METC’s equity adders, a hearing was ordered on the November 2013 complaint's allegations as to the base rate of return on equity for all MISO transmission owners. On December 22, 2015, the presiding administrative law judge issued an initial decision recommending to the FERC a reduction in the base rate of return on equity of the MISO Transmission owners from 12.38% to 10.32%, with a maximum rate of 11.35%. On September 28, 2016, the FERC issued an order affirming the presiding administrative law judge’s initial decision, with the new rates to become effective immediately and for the period from November 12, 2013 through February 11, 2015. In February 2015, an additional complaint was filed under Section 206 of the FPA seeking a FERC order reducing the base rate of return on equity for all MISO transmission owners, including for our MISO Regulated Operating Subsidiaries, to 8.67%. On June 30, 2016, the presiding administrative law judge issued an initial decision on the February 2015 complaint, which recommended a base rate of return on equity of 9.70% for the period from February 12, 2015 through May 11, 2016, with a maximum rate of 10.68%. In resolving the February 2015 complaint, we expect the FERC to establish a new base rate and zone of reasonable returns that will be used, along with any incentive adders, to calculate the refund liability for the period from February 12, 2015 through May 11, 2016. A decision from the FERC on the February 2015 complaint is anticipated in 2017. In 2016, 2015 and 2014, we adjusted revenues downward to accrue for the refund liability based on our estimate of the outcome of these complaints. An unfavorable resolution of the second complaint in excess of the amount accrued for the refund liability could significantly reduce our future revenues and net income and therefore could have a material adverse effect on our future results of operations, cash flows and financial condition.

Risks Relating to Our Corporate and Financial Structure

ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to fulfill our cash obligations.

As a holding company with no business operations, ITC Holdings’ material assets consist primarily of the stock and membership interests in our subsidiaries. Our only sources of cash are dividends and other payments received by us from time

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to time from our subsidiaries, proceeds raised from the sale of our securities and borrowings under our various credit agreements. Each of our subsidiaries, however, is legally distinct from us and has no obligation, contingent or otherwise, to make funds available to us. The ability of each of our Regulated Operating Subsidiaries and our other subsidiaries to pay dividends and make other payments to us is subject to, among other things, the availability of funds, after taking into account capital expenditure requirements, the terms of its indebtedness, applicable state laws and regulations of the FERC and the FPA. Our Regulated Operating Subsidiaries target a FERC-approved capital structure of 60% equity and 40% debt that may limit the ability of our Regulated Operating Subsidiaries to use net assets for the payment of dividends to ITC Holdings. In addition, ITC Holdings’ right to receive any assets of any subsidiary, and therefore the right of its creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors. If ITC Holdings does not receive cash or other assets from our subsidiaries, it may be unable to pay principal and interest on its indebtedness.

We have a considerable amount of debt and our reliance on debt financing may limit our ability to fulfill our debt obligations and/or to obtain additional financing.

We have a considerable amount of debt and our consolidated indebtedness includes various debt securities and borrowings, which utilize indentures, revolving and term loan credit agreements and commercial paper, that we rely on as sources of capital and liquidity. This financing strategy can have several important consequences, including, but not limited to, the following:


•	If future cash flows are insufficient, we may not be able to make principal or interest payments on our debt obligations, which could result in the occurrence of an event of default under one or more of those debt instruments.


•	We may need to increase our indebtedness in order to make the capital expenditures and other expenses or investments planned by us.

•

Our indebtedness has the general effect of reducing our flexibility to react to changing business and economic conditions insofar as they affect our financial condition. A substantial portion of the dividends and payments in lieu of taxes we receive from our subsidiaries will be dedicated to the payment of interest on our indebtedness, thereby, reducing the funds available for working capital and capital expenditures.

•

We currently have debt instruments outstanding with short-term maturities or relatively short remaining maturities. Our ability to secure additional financing prior to or after these facilities mature, if needed, may be substantially restricted by the existing level of our indebtedness and the restrictions contained in our debt instruments. Additionally, the interest rates at which we might secure additional financings may be higher than our currently outstanding debt instruments or higher than forecasted at any point in time, which could adversely affect our business, financial condition, results of operations and cash flows.


•	Market conditions could affect our access to capital markets, restrict our ability to secure financing to make the capital expenditures and investments and pay other expenses planned by us which could adversely affect our business, financial condition, cash flows and results of operations.

We may incur substantial additional indebtedness in the future. The incurrence of additional indebtedness would increase the risks described above.

Certain provisions in our debt instruments limit our financial and operating flexibility.

Our debt instruments on a consolidated basis, including senior notes, secured notes, first mortgage bonds, revolving and term loan credit agreements and commercial paper, contain numerous financial and operating covenants that place significant restrictions on, among other things, our ability to:


•	incur additional indebtedness;


•	engage in sale and lease-back transactions;


•	create liens or other encumbrances;


•	enter into mergers, consolidations, liquidations or dissolutions, or sell or otherwise dispose of all or substantially all of our assets;


•	create and acquire subsidiaries; and


•	pay dividends or make distributions on our stock or on the stock or member capital of our subsidiaries.

Our debt instruments also require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios. Our ability to comply with these and other requirements and restrictions may be affected by changes in economic or business conditions, results of operations or other events beyond our control. A failure to comply with the obligations contained

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in any of our debt instruments could result in acceleration of related debt and the acceleration of debt under other instruments evidencing indebtedness that may contain cross-acceleration or cross-default provisions.

Adverse changes in our credit ratings may negatively affect us.

Our ability to access capital markets is important to our ability to operate our business. Increased scrutiny of the energy industry and the impact of regulation, as well as changes in our financial performance and unfavorable conditions in the capital markets could result in credit agencies reexamining our credit ratings. A downgrade in our credit ratings could restrict or discontinue our ability to access capital markets at attractive rates and increase our borrowing costs. A rating downgrade could also increase the interest we pay on commercial paper and under our revolving and term loan credit agreements .

Risks Related to the Merger

ITC Holdings and its subsidiaries are subject to business uncertainties during the period of integration with Fortis that could adversely affect ITC Holdings’ financial results.

Uncertainty about the effect of the Merger on employees or vendors and others, including contractors, may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate key personnel, and could cause vendors, contractors and others that deal with us to seek to change existing business relationships. Employee retention and recruitment may continue to be challenging after the completion of the Merger, as current employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees retire, depart or fail to accept employment with ITC Holdings or its subsidiaries due to the uncertainty of employment and difficulty of integration or a desire not to remain with the combined company, we may incur significant costs in identifying, hiring, and retaining replacements for departing employees, which could have a material adverse effect on our business operations and financial results. In addition, integration-related issues may place a significant burden on management, employees and internal resources which could otherwise have been devoted to other business opportunities. The diversion of management’s attention and any delays or difficulties encountered in connection with the Merger and the integration of ITC Holdings’ operations with Fortis could have an adverse effect on our business, financial results or financial condition. The integration process may also result in additional and unforeseen expenses.

We will continue to incur substantial transaction-related costs in connection with the Merger.

We expect to continue to incur additional costs in connection with the Merger and integrating our operations with Fortis and do not expect savings from elimination of duplicative costs to offset these costs. Such costs may be material and could continue to have a material adverse effect on our future results of operations, cash flows and financial condition.

We are the target of securities class action and derivative lawsuits, which could result in substantial costs and diversion of management’s time and resources.

Securities class action lawsuits and derivative lawsuits are often brought against companies that have entered into merger agreements. There is currently a class action lawsuit pending against us and our directors in connection with the Merger. We are not able to predict the outcome of this action or others that may be brought, nor can we predict the amount of time and expense that will be required to resolve the actions. Even if the lawsuits are without merit, defending against these claims can result in substantial costs to us and divert management’s time and resources.

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ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth the repurchases of common stock for the quarter ended September 30, 2016 :



Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (in millions)
Period	Total Number of Shares Purchased	Average Price Paid per Share
July (a)	1,365	$	46.51	—	$	—
August (a)	2,710	46.29		—	—
September (a)	1,818	45.69		—	—
Total (b)	5,893	$	46.16	—

____________________________


(a)	Shares acquired were delivered to us by employees as payment of tax withholding obligations due to us upon the vesting of restricted stock.


(b)	Amount does not include 18,683 shares deemed issued and repurchased for accounting purposes in connection with the payment of the exercise price and tax withholding obligations relating to net option exercises.

On October 14, 2016, the common shares of ITC Holdings were delisted from the NYSE upon the closing of the Merger with Fortis such that going forward, we will have no publicly announced share repurchase authorization. Refer to Note 2 to the condensed consolidated financial statements for further details of the Merger.

ITEM 5A. OTHER INFORMATION

At the effective time of the Merger, ITC Holdings’ articles of incorporation were amended and restated in accordance with the terms of the Merger Agreement (the “Restated Articles of Incorporation”), and were filed as an exhibit to its Form 8-K on October 14, 2016. On October 31, 2016, a certificate of correction was filed with the State of Michigan correcting the number of outstanding shares noted in Article III of the Restated Articles of Incorporation. A copy of the Restated Articles of Incorporation, as corrected, is filed as Exhibit 3.1 to this Form 10-Q.

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ITEM 6. EXHIBITS

The following exhibits are filed as part of this report (unless otherwise noted to be previously filed, and therefore incorporated herein by reference). Our SEC file number is 001-32576.



Exhibit No.			Description of Document

3.1			Restated Articles of Incorporation of ITC Holdings Corp., as corrected

3.2			Sixth Amended and Restated Bylaws of ITC Holdings Corp (filed with Registrant’s Form 8-K filed on October 12, 2016)

4.45			Third Supplemental Indenture, dated as of July 5, 2016, between the Company and Wells Fargo Bank, National Association, as trustee, together with form of 3.25% Note due 2026 (filed with Registrant’s Form 8-K filed on July 5, 2016)

10.167			Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Joseph L. Welch (filed with Registrant’s Form 8-K filed on October 12, 2016)

10.168			Letter Agreement, dated as of October 14, 2016, between ITC Holdings Corp. and Linda H. Blair (filed with Registrant’s Form 8-K filed on October 12, 2016)

10.169			Amended Employment Agreement, dated as of October 12, 2016, between ITC Holdings Corp. and Rejji P. Hayes (filed with Registrant’s Form 8-K filed on October 12, 2016)

10.170			Amended and Restated Generator Interconnection Agreement by and among Michigan Electric Transmission Company, LLC, Consumers Energy Company and the Midcontinent Independent System Operator, Inc., dated as of October 24, 2016

31.1			Certification of Chief Executive Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2			Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32			Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS			XBRL Instance Document

101.SCH			XBRL Taxonomy Extension Schema

101.CAL			XBRL Taxonomy Extension Calculation Linkbase

101.DEF			XBRL Taxonomy Extension Definition Database

101.LAB			XBRL Taxonomy Extension Label Linkbase

101.PRE			XBRL Taxonomy Extension Presentation Linkbase

Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: November 4, 2016



ITC HOLDINGS CORP.
By:	/s/ Linda H. Blair
	Linda H. Blair
	President and Chief Executive Officer (duly authorized officer)


By:	/s/ Gretchen L. Holloway
	Gretchen L. Holloway
	Vice President, Chief Financial Officer and Treasurer (principal financial and accounting officer)

EXHIBIT 3.1

RESTATED ARTICLES OF INCORPORATION

ITC HOLDINGS CORP.

Pursuant to the provisions of Act 284, Public Acts of 1972, the undersigned corporation executes the following Articles:

1. The present name of the corporation is: ITC Holdings Corp.

2. The identification number assigned by the Bureau is: 405-95C.

3. The former name(s) of the corporation are: None.

4. The date of filing the original Articles of Incorporation was: November 8, 2002.

The following Restated Articles of Incorporation supersede the Amended and Restated Articles of Incorporation, as amended, for the corporation:

ARTICLE I

Name

The name of the corporation (the “ Corporation ”) is: ITC Holdings Corp.

ARTICLE II

Purpose

The Corporation is formed to engage in any activity within the purposes for which corporations may be formed under the Michigan Business Corporation Act, as amended (the “ MBCA ”).

ARTICLE III

Capital Stock

The total number of shares which the Corporation shall have authority to issue: 235,000,000 shares of Common Stock, with no par value of which 226,607,715 shares of Common Stock shall be issued on the date hereof.

ARTICLE IV

Registered Office and Resident Agent

The name of the resident agent is The Corporation Company. The address and mailing address of the registered office of the Corporation is 40600 Ann Arbor Rd E Ste 201, Plymouth, Michigan, 48170.

ARTICLE V

Limitation of Director Liability; Indemnification

No director of the corporation shall be personally liable to the corporation or its shareholders for money damages for any action taken, or any failure to take any action, except liability for any of the following: (1) the amount of a financial benefit received by a director to which he or she is not entitled; (2) intentional infliction of harm on the corporation or its shareholders; (3) a violation of §551 of the MBCA, the Michigan Compiled Laws Annotated 450.1551, Michigan Statutes Annotated 21.200(551); or (4) an intentional violation of criminal law. If the MBCA hereafter is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability contained herein, shall be limited to the fullest extent permitted by the MBCA as so amended. No amendment or repeal of this Article V shall apply to or have any effect on the liability or alleged liability of any director of the corporation for or with respect to any acts or omissions of such director occurring prior to such amendment or repeal.

To the maximum extent permitted by the MBCA, the corporation shall indemnify any person who was or is a party to or is threatened to be made a party to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative, formal or informal, including any appeal, by reason of the fact that the person is or was a director or officer of the corporation, or, while serving as a director, officer, employee or agent of the corporation, is or was serving at the request of the corporation as a director, officer, member, partner, trustee, employee, fiduciary, or agent of another foreign or domestic corporation, partnership, limited liability company, joint venture, trust, or other enterprise, including service with respect to employee benefit plans or public service or charitable organizations, against expenses (including actual and reasonable attorney fees and disbursements), liabilities, judgments, penalties, fines, excise taxes, and amounts paid in settlement actually and incurred by him or her in connection with such action, suit, or proceeding. Indemnification may continue as to a person who has ceased to be a director, officer, employee or agent of the corporation and may inure to the benefit of such person’s heirs, executors and administrators. The corporation, by provisions in its bylaws or by agreement, may grant to any current or former director, officer, employee or agent of the corporation the right to, or regulate the manner of providing to any current or former director, officer, employee or agent of the corporation, indemnification to the fullest extent permitted by the MBCA. Any right to indemnification conferred as permitted by this Article V shall not be deemed exclusive of any other right which any person may have or hereafter acquire under any statute (including the MBCA), any other provision of these Articles, any provision of the bylaws, any agreement, any vote of shareholders or the Board of Directors or otherwise.

ARTICLE VII

Corporate Action Without Meeting of Shareholders

Any action required or permitted by the MBCA to be taken at an annual or special meeting of shareholders of the Corporation may be taken without a meeting, without

prior notice and without a vote, if a consent in writing, setting forth the action so taken, is signed by the holders of record of outstanding shares of stock of the Corporation having not less than the minimum number of votes that would be necessary to authorize or take action at a meeting at which all shares entitled to vote thereon were present and voted. The written consent shall bear the date of signature of each shareholder who signs the consent. No written consents shall be effective to take corporate action unless, within sixty (60) days after the record date for determining shareholders entitled to express consent to or dissent from a proposal with a meeting, written consents dated not more than ten (10) days before the record date and signed by a sufficient number of shareholders to take the action are delivered to the Corporation. Delivery shall be to the Corporation’s registered office, its principal place of business or an officer or agent of the Corporation having

custody of the minutes of the proceedings of its shareholders. Deliver made to a Corporation’s registered office shall be by hand or by certified or registered mail, return receipt requested.

Prompt notice of the taking of the corporate action without a meeting by less than unanimous written consent shall be given to shareholders who would have been entitled to notice of the shareholder meeting if the action had been taken at a meeting and who have not consented to the action in writing. An electronic transmission consenting to an action must comply with Section 407(3) of the MBCA.

ARTICLE VIII

Applicability of Chapter 7A

The corporation expressly elects not to be governed by Chapter 7A of the MBCA.

ARTICLE IX

Amendments

The corporation reserves the right to adopt, repeal, alter or amend any provision of these Articles in the manner now or hereafter prescribed by the MBCA and all rights, preferences and privileges conferred on shareholders, directors, officers, employees, agents and other persons in these Articles, if any, are granted subject to this reservation (subject to the last sentence of the first paragraph of Article V ).

ADOPTION OF AMENDED AND RESTATED ARTICLES

These Restated Articles of Incorporation were duly adopted on the 14th day of October, 2016 in accordance with the provisions of Sections 611(3), 641 and 642 of the MBCA.

Signed this 14 ^th day of October, 2016

By: /s/ Joseph L. Welch

Name: Joseph L. Welch

Title : Chairman, President & CEO

CERTIFICATE OF CORRECTION

CERTIFICATE OF MERGER OF ELEMENT ACQUISITION SUB INC.

AND

ITC HOLDINGS CORP.

AND

RESTATED ARTICLES OF INCORPORATION OF ITC HOLDINGS CORP.

Pursuant to the provisions of Section 450.1133 et seq. of the Michigan Business Corporation Act (the “ Act ”), the undersigned executes the following certificate (this “ Certificate of Correction ”):


1.	The name of the corporation submitting this Certificate of Correction is ITC Holdings Corp. (the “ Corporation ”), identification number 40595C.


2.	The Corporation is a corporation formed under the laws of the State of Michigan.


3.	That a Certificate of Merger of Element Acquisition Sub Inc. and ITC Holdings Corp. (the “ Merger Certificate ”) was filed by the Michigan Department of Licensing and Regulatory Affairs Corporations, Securities & Commercial Licensing Bureau (the “ Bureau ”) on October 14, 2016 (the “ Filing Date ”) and the Merger Certificate requires correction.


4.	That Restated Articles of Incorporation of the Corporation (the “ Restated Articles ”) were attached to the Merger Certificate and were filed with the Bureau in connection therewith on the Filing Date and the Restated Articles require correction.


5.	The inaccuracy or defect contained in the Merger Certificate is that Section 6 of the Merger Certificate erroneously set forth that the number of common shares of the Corporation outstanding on the Filing Date is 153,432,671.


6.	The inaccuracy or defect contained in the Restated Articles is that Article III of the Restated Articles erroneously set forth that the number of shares of common stock of the Corporation issued on the Filing Date is 226,607,715.


7.	Therefore, Section 6 of the Merger Certificate is hereby corrected to read as follows:

“The authorized capital stock of ITC consists of 300,000,000 common shares, with no par value and 10,000,000 preferred shares, with no par value of which 152,079,648 common shares and no preferred shares are outstanding. The common shares of ITC are the only outstanding class or series of shares of capital stock of ITC that is entitled to vote. No class or series of capital stock of ITC is entitled to vote as a class.”


8.	Therefore, Article III of the Restated Articles is hereby corrected to read as follows:

“The total number of shares which the Corporation shall have authority to issue: 235,000,000 shares of Common Stock, with no par value of which 224,203,112 shares of Common Stock shall be issued on the date hereof.”


9.	This Certificate of Correction is hereby executed in the same manner as the Act requires the document being corrected to be executed.

* * *

IN WITNESS WHEREOF, the Corporation has caused this Certificate of Correction to be duly executed by the undersigned as of the 27 ^th day of October, 2016.

ITC HOLDINGS CORP.

By: /s/ Christine Mason Soneral

Name: Christine Mason Soneral

Title: Senior Vice President and General Counsel

The preparer’s name and contact information is as follows: Kristen Rohr, (212) 819-7596, White & Case LLP, 1155 Avenue of the Americas, New York, New York 10036.

EXHIBIT 10.170

SA 1756 METC-CONSUMERS GIA VERSION 33.0.0

EFFECTIVE 10/01/2016

TENTH REVISED SERVICE AGREEMENT NO. 1756

PUBLIC VERSION

Project G479B

AMENDED AND RESTATED

GENERATOR INTERCONNECTION AGREEMENT

entered into by and between

Michigan Electric Transmission Company, LLC

and

Consumers Energy Company

and

Midcontinent Independent System Operator, Inc.

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

by and among

Michigan Electric Transmission Company, LLC

and

Consumers Energy Company

and the

Midcontinent Independent System Operator, Inc.

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

THIS Amended AND RESTATED GENERATOR INTERCONNECTION AGREEMENT(the "Agreement") is made and entered into as of October 24, 2016 by and among Michigan Electric Transmission Company, LLC , a limited liability company with offices at 27175 Energy Way Novi, Michigan (herein referred to as “METC” or "Transmission Owner”), Consumers Energy Company , a Michigan corporation with offices at One Energy Plaza, Jackson, Michigan (herein referred to as “Consumers” or “Interconnection Customer”), and the Midcontinent Independent System Operator, Inc. , formerly known as Midwest Independent Transmission System Operator, Inc. , a non-profit, non-stock corporation organized and existing under the laws of the State of Delaware (herein referred to as “MISO” or “Transmission Provider”). Transmission Provider, Consumers and Transmission Owner each may be referred to individually as a "Party," or collectively as the "Parties." This Agreement amends, restates and replaces the October 1, 2015 Amendment and Restatement of the Generator Interconnection Agreement between the Transmission Owner, Transmission Provider and Consumers, effective on the Effective Date provided for below in Section 2.1.

WITNESSETH:

WHEREAS, Consumers owns and operates several electric generating assets (herein referred to as a Unit when discussing one of them, or as Generation Resources when referring to all of them) as described in Article 1. The Unit names and generating capability ratings of the Generation Resources are set forth in Exhibit A to this Agreement. Each Unit in the list is currently in commercial operation; and

WHEREAS, Transmission Provider has functional control of the operation of the Transmission System, as defined in Article 1 of this Agreement, and is responsible for providing transmission and interconnection service on the transmission facilities under its functional control; and

WHEREAS, Transmission Owner owns or operates the Transmission System, whose operations are subject to the functional control of the Transmission Provider, to which the Consumers’ Units are interconnected, as set forth in this Agreement; and

WHEREAS, it is necessary for Consumers’ Units to remain interconnected with the Transmission System (as defined in Article 1), in order for said Units to continue to operate; and

WHEREAS, the revised and restated Agreement is not intended to affect METC’s and Consumer’s obligations to each other with regard to the following agreements:

WHEREAS, Consumers and Transmission Owner have entered into an Operating Agreement, dated as of April 1, 2001, as amended and restated, (herein referred to as the “Operating Agreement”) that defines the operating responsibilities of the Transmission Owner with respect to the Transmission System and the obligations, rights and responsibilities of Consumers to provide ancillary services and to operate its Generation Resources in a manner that will not unduly interfere with the provision of Transmission Services by the Transmission Owner; and

WHEREAS, Consumers, Transmission Owner and Transmission Provider have entered into a Purchase and Sale Agreement for Ancillary Services, dated as of April 1, 2001, as amended and restated, that sets forth the terms and conditions under which Consumers shall use its Generation Resources to provide ancillary services to the Transmission Owner and Transmission Provider; and

WHEREAS, the Parties are willing to maintain the interconnection of Consumers’ Generation Resources with the Transmission System under the terms and conditions contained herein.

NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, the Parties hereto agree as follows:

ARTICLE 1

DEFINITIONS


1.	Whenever used in this Agreement, appendices, and attachments hereto, the following terms shall have the following meanings:

“ Black Start Capability” shall mean a generating Unit that is capable of starting without an outside electrical supply. Said Units are specified in Exhibit A.

“ Black Start Plan” shall mean a plan utilizing Black Start Capability designed and implemented by the Transmission Provider or Transmission Owner in conjunction with its interconnected generation and distribution customers, Distribution System Control, other electric systems, its Security Coordinator and ECAR, to energize portions of the Transmission System which are de-energized as a result of a widespread system disturbance.

“ Black Start Service ” shall mean the provision of service needed to energize a defined portion of the Transmission Owner’s Transmission System, including the start up of the Generation Resources and/or other generators, in accordance with the Transmission Provider’s or Transmission Owner’s Black Start Plan when local power from the Transmission System is unavailable or insufficient.

" Commission " shall mean the Federal Energy Regulatory Commission, or any successor agency.

“ Connection Point ” shall be the point where Consumers’ Interconnection Assets connect to Transmission Owner’s Interconnection Assets, as described in Exhibit B of this Agreement.

“ Consumers’ Incremental Cost ” shall mean Consumers’ actual hourly replacement cost of energy on Consumers’ Generation Resources, whether that energy is (a) produced by generation owned by or under contract to Consumers or (b) purchased from a third party.

“ Consumers’ Interconnection Assets ” shall mean the assets identified as belonging to Consumers in Exhibit B of this Agreement and all other assets that are necessary or desirable to interconnect a Unit to the Transmission System reliably and safely, including all connection, switching, transmission, distribution, safety, and communication assets, protective assets, Telemetry and Monitoring Assets that Consumers owns or operates and maintains.

" Consumers’ System " shall mean the assets owned, controlled and operated by Consumers that are used to provide service to its customers.

“ ECAR ” stands for the East Central Area Reliability council or a successor group.

" Emergency " shall mean any system condition that requires automatic or immediate manual action to prevent or limit the loss of transmission assets or generation supply that could adversely affect the reliability

of Transmission System or Consumers’ System or the systems to which either Party is directly or indirectly connected.

“ Generation Resources ” shall mean the assets used for the production of electric energy, which are owned and operated by Consumers and directly or indirectly connected to the Transmission System pursuant to this Agreement.

" Good Utility Practice " shall mean any of the practices, methods and acts engaged in or approved by a significant proportion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others, but rather to be acceptable practices, methods or acts generally accepted in the region.

“ Governmental Authority ” shall mean any federal, state, local or municipal governmental body; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, policy, regulatory or taxing authority or power; or any court or governmental tribunal.

" Hazardous Substances " shall mean any chemicals, materials or substances defined as or included in the definition of "hazardous substances", "hazardous wastes", "hazardous materials", "hazardous constituents", "restricted hazardous materials", "extremely hazardous substances", "toxic substances", "contaminants", "pollutants", "toxic pollutants" or words of similar meaning and regulatory effect under any applicable Environmental Law, or any other chemical, material or substance, exposure to which is prohibited, limited or regulated by any applicable Environmental Law. For purposes of this Agreement, the term "Environmental Law" shall mean federal, state, and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders relating to pollution or protection of the environment, natural resources or human health and safety.

“ IEEE ” is an acronym, which stands for the Institute of Electrical and Electronic Engineers.

“ Interconnection Assets ” shall mean, collectively, Transmission Owner’s Interconnection Assets and Consumers’ Interconnection Assets, or the specific Interconnection Assets of either the Transmission Owner or Consumers, as the case may be.

“ Jointly Owned Assets ” shall mean those assets in which Consumers and Transmission Owner have undivided ownership interests. Due to the nature of substation designs, many of the supporting substation assets (e.g., station batteries, fencing, control houses, ground grid, yard stone, steel structures and some protective relay assets) cannot be separated by ownership and the Parties share in the ownership of such assets. The respective ownership of such assets by substation is shown in Exhibit B hereto.

“Metering Assets” shall mean the assets required to provide acceptably accurate metering of the interconnection power and energy output from the Unit and the standby power and energy usage of the Unit. Said Metering Assets typically includes but is not limited to, metering accuracy potential and current transformers, transducers, primary connections, secondary connections, secondary potential and current circuits and conduit, telephone lines and access to said Metering Assets, if necessary. The transducers used shall be capable of providing Megawatthour and Megavarhour data.

“MISO” shall mean the Midcontinent Independent System Operator, Inc., or its successor.

“MISO Tariff” shall mean the Open Access Transmission, Energy and Operating Reserve Markets Tariff on file with the Commission as it may be amended or superseded from time to time.

“ Monitoring Assets ” shall mean the assets required to determine (a) the sequence of events for the operation of protective assets during an electrical fault, (b) the location and characteristics of an electrical fault and (c) the quality of power provided at the Point of Receipt.

" NERC " is an acronym that stands for the North American Electric Reliability Council, including any successor thereto or any regional reliability council thereof. This reliability council oversees the development and publication of operating policies, engineering planning principles and guides and support information to provide guidance to the regional reliability councils and to promote electric system reliability.

“ Point of Receipt ” shall be the point at which capacity and energy is provided by Consumers, as described in Exhibit B of this Agreement.

“ Reactive Design Limitations ” shall mean the reactive power capability designed into the Unit, which were consistent with reactive power capability specifications in place when the Unit was constructed.

" Secondary Systems " shall mean control or power circuits that operate below 600 volts, AC or DC, including, but not limited to, any hardware, control or protective devices, cables, conductors, electric conduits and raceways, secondary assets panels, transducers, batteries, chargers, and voltage and current transformers.

" Switching and Tagging Rules " shall mean the written documents describing the switching and tagging procedures of Transmission Owner and Consumers, as they may be amended.

“ System Operator ” is a generic term used to describe the individuals responsible for the integrity or the operational control of the Transmission System and any successor thereto.

" System Protection Assets " shall mean the assets required to protect (a) the Transmission System, the systems of others connected to the Transmission System, and Transmission Owner’s customers from faults occurring at the Unit, and (b) the Unit from faults occurring on the Transmission System or on the systems of others to which the Transmission System is directly or indirectly connected.

“Telemetry Equipment” shall mean the assets, identified by Transmission Owner, that are required to provide the necessary, real-time telemetry of Unit operations and status, as required by Transmission Owner, for remote monitoring and control purposes. This typically includes but is not limited to, remote terminal units, distributed terminal units, telemetry signal inputs, fiber optic communication connections, transducers, pulse multipliers, isolation amplifiers, analog inputs, digital inputs, metering pulsed accumulator inputs, power supply, dedicated telephone data line to remote terminal units, telephone modem, telephone switching, interface terminal strips for landing signal inputs/outputs. Telemetry Equipment may be located at Consumers’ Unit and or at Transmission Owner’s assets.

“Transmission Owner” shall mean Michigan Electric Transmission Company, LLC or its successor.

“ Transmission Owner’s Interconnection Assets ” shall mean the assets identified as belonging to Transmission Owner in Exhibit B of this Agreement and all other assets that are necessary or desirable to interconnect the Generation Resources to the Transmission System reliably and safely, including all connection, switching, transmission, distribution, safety, and communication assets, protective assets, Metering, Telemetry and Monitoring Assets and all improvements, additions or extensions to the Transmission

System owned or operated and maintained by the Transmission Owner and that are attributable to or necessitated by the Generation Resources.

“Transmission Provider” shall mean MISO.

" Transmission System " shall mean the facilities owned by the Transmission Owner and controlled or operated by the Transmission Provider or Transmission Owner that are used to provide transmission service under the MISO Tariff.

“Transmission Service” shall include both Point-To-Point Transmission Service and Network Integration Transmission Service provided under the MISO Tariff.

" Unit " shall mean each of Consumers’ electric generating assets, or group of generating assets having common Interconnection Assets, covered by this Agreement and identified generally in the first "Whereas" clause and Exhibit A of this Agreement and more specifically identified in the "as built" drawings provided to Transmission Owner in accordance with Section 4.3 of this Agreement, together with the other property, assets, and assets owned and/or controlled by Consumers on the Consumers' side of the Connection Point.

ARTICLE 2

TERM OF AGREEMENT

2.1 Effective Date

This Agreement shall become effective on the date designated by the Commission in its order accepting this Agreement for filing (the “Effective Date”).

2.2 Term

This Agreement shall become effective as provided in Section 2.1 above and, unless terminated as provided below, shall continue in full force and effect until a mutually agreed termination date, but no later than the date on which all of the Generation Resources cease commercial operation.

2.3 Termination

In the event that Transmission Owner joins a Regional Transmission Organization (“RTO”) which requires use of its own FERC-approved interconnection and operating agreement, this Agreement shall terminate on the effective date of such new interconnection and operating agreement between Consumers and the RTO, except to the extent necessary to resolve billing and other outstanding matters related to service rendered under this Agreement as specified in Section 2.5.

2.4 Regulatory Filing

Transmission Provider shall file this Agreement with the Commission as a Service Agreement under the MISO Tariff, within the meaning of 18 C.F.R. Part 35. Consumers and Transmission Owner agree to cooperate with Transmission Provider with respect to such filing and to provide any information, including the rendering of testimony reasonably requested by Transmission Provider, needed to comply with applicable regulatory requirements.

2.5 Survival

The applicable provisions of this Agreement shall continue in effect after expiration, cancellation, or termination hereof to the extent necessary to provide for final billings, billing adjustments, and the determination and enforcement of liability and indemnification obligations arising from acts or events that occurred while this Agreement was in effect.

ARTICLE 3

INTERCONNECTION SERVICE

3.1 Scope of Service

In the event future changes in either (a) design or operation of any Unit, (b) Consumers’ requirements or (c) Transmission Provider’s or Transmission Owner’s requirements resulting from the Unit’s parallel operation with the Transmission System later necessitate additional Interconnection Assets or modifications to the then existing Interconnection Assets herein, the Parties shall undertake such additions and modifications as may be necessary. Before undertaking such future additions or modifications, the Parties shall consult, develop plans and coordinate schedules of activities, including the making of necessary amendments to this Agreement (including its Appendices) and/or entering into new agreements, so as to insure continuous and reliable operation of the Interconnection Assets. The cost of such additions or modifications to the Interconnection Assets shall be borne by Consumers unless otherwise agreed upon at the time. The ownership, operation and maintenance responsibilities for any such future additions or modifications shall be made consistent with the responsibilities allocated in this Agreement.

3.1.1 Except as otherwise provided under Sections 5.8 and 5.9 of this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to pay Consumers any wheeling or other charges for electric power and/or energy transferred through Consumers’ assets or for power or ancillary services provided by Consumers under this Agreement for the benefit of the Transmission System.

3.1.2 Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to make arrangements or pay under

applicable tariffs for transmission and ancillary services associated with the delivery of electricity and ancillary electrical products produced by the Unit.

3.1.3 Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to procure electricity and ancillary electrical products to satisfy Consumers’ station power needs or other related requirements.

3.1.4 Except as otherwise provided under this Agreement, neither Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to make arrangements under applicable tariffs for transmission, losses, and ancillary services associated with the use of the Transmission System for the delivery of electricity and ancillary electrical products to the Unit.

3.1.5 Transmission Provider makes no representations to Consumers regarding the availability of Transmission Service on the Transmission System, and Consumers agrees that the availability of Transmission Service on the Transmission System may not be inferred or implied from Transmission Provider’s or Transmission Owner’s execution of this Agreement. Consumers will obtain Transmission Service on the Transmission System under a separate agreement between the Parties and in accordance with the provisions of the MISO Tariff.

3.2 Third-Party Actions

Consumers acknowledges and agrees that, from time to time during the term of this Agreement, other persons may develop, construct and operate, or acquire and operate generating assets in the Transmission Provider’s service territory, and construction or acquisition and operation of any such assets, and reservations by any such persons of Transmission Service under the MISO Tariff may adversely affect the Unit and the availability of Transmission Service for the Unit’s electric output. Consumers acknowledges and agrees that Transmission Provider has no obligation under this Agreement to disclose to Consumers any information with respect to third-party developments or circumstances, including the identity or existence of any such person or other assets, beyond what Transmission Provider customarily provides to other similarly situated generators, except as may be required under Article 4 of this Agreement and elsewhere in this Agreement. Consumers and Transmission Provider make no guarantees to the other under this Agreement with respect to Transmission Service that is available under the MISO Tariff.

ARTICLE 4

INTERCONNECTION ASSETS

4.1 Reservation of Rights to Interconnection Assets

Except as provided in Section 5.2 hereof, each Party reserves to itself the ownership, operation and maintenance of its Interconnection Assets and all improvements, additions or extensions to its Interconnection Assets under this Agreement which are attributable to or necessitated by the interconnection of the Unit.

4.2 Modifications

Either Party may undertake modifications to its assets. In the event a Party plans to undertake a modification that may be expected to impact the other Party's assets, that Party shall provide the other Party with sufficient information regarding such modification, including, without limitation, the notice required in accordance with Article 11 of this Agreement so that the other Party can evaluate the potential impact of such modification prior to commencement of the work. The Party desiring to perform such work shall provide the relevant drawings, plans, and specifications to the other Party at least ninety (90) days in advance of

commencement of the work or such shorter period upon which the Parties may agree, which agreement will not unreasonably be withheld or delayed.

4.3 As-Built Drawings

Upon execution of this Agreement, Consumers shall provide to Transmission Provider and Transmission Owner current interconnection drawings and system diagrams for each of its Units, unless the Parties agree that such drawings are not necessary. Subject to the requirements of Article 17 of this Agreement, not later than ninety (90) days after completion of any addition to or modification of the assets of any of said Units that may reasonably be expected to affect the Transmission System, Consumers shall issue revised "as built" drawings to Transmission Provider and Transmission Owner.

ARTICLE 5

OPERATIONS

5.1 General

The Parties agree that they shall comply with the Operating Agreement, then-existing (or amended) applicable manuals, standards, and guidelines of Transmission Provider, NERC, ECAR, or any successor agency assuming or charged with similar responsibilities related to the operation and reliability of the North American electric interconnected transmission grid. To the extent that this Agreement does not specifically address or provide the mechanisms necessary to comply with such Operating Agreement, Transmission Provider, NERC or ECAR manuals, standards, or guidelines, the Parties hereby agree that each Party shall provide to the other Parties all such information as may reasonably be required to comply with such Operating Agreement, manuals, standards, or guidelines and shall operate, or cause to be operated, their respective assets in accordance with such Operating Agreement, manuals, standards, or guidelines.


1.	Transmission Provider and Transmission Owner Obligations

Transmission Provider and Transmission Owner shall operate and control the Transmission System and other Transmission Owner assets in a safe and reliable manner (a) in accordance with Transmission Provider’s and Transmission Owner’s applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) the Operating Agreement and (c) in accordance with the provisions of this Agreement. From time to time, Consumers will control and operate four (4) 345 kV synchronizing circuit breakers (Nos. 28H9, 28R8, 32F7 and 32H9 in the Hampton Substation) to connect or disconnect the Karn 3 or Karn 4 Units, as the case may be, from the Transmission System. The Parties may agree from time to time that Consumers, under the direction of the Transmission Provider or Transmission Owner, will operate certain other Interconnection Assets of the Transmission Owner.

5.3 Consumers’ Obligations

Consumers shall operate and control its Generation Resources in a safe and reliable manner in accordance with (a) Consumers’ applicable operational and/or reliability criteria, protocols, and directives (which shall include those of NERC and ECAR), (b) the Operating Agreement and (c) the provisions of this Agreement.

5.4 Jointly Owned Assets

Operation of Jointly Owned Assets at the electric substations where Interconnection Facilities are located will be under the direction and control of the Party with more than fifty percent (50%) of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said Party shall

operate the Jointly Owned Assets in a manner consistent with Good Utility Practice and the provisions of Sections 5.2 and 5.3 above, as appropriate. Each Party’s respective share of responsibility for the costs of operation of Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum’s. The respective ownership of substation facilities is shown in the Wiring Diagrams for each of the electrical substations at which Consumers’ Generation Resources are connected to the Transmission System (see Exhibit B), reflecting ownership changes through July 24, 2008. The Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties. For current ownership (reflecting ownership changes since July 24, 2008), see the WDs in the DMS. For purposes of this Agreement, major equipment is defined as (a) main power transformers, (b) 23 kV, 46 kV, 138 kV and 345 kV circuit breakers, (c) power system regulators and reclosers and (d) 46 kV and 138 kV capacitor banks (any three-phase installation of such equipment shall count as one unit of equipment). Exhibit B shall be updated with an addendum at least annually by the Transmission Owner, and approved in writing by all Parties at least annually, to show all changes in equipment and the effects of such changes on the determination of Jointly Owned Asset percentages. For purposes of this Section 5.4, such submission and approval of changes shall be in writing consistent with Section 21.1. In the case where each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume the responsibility for direction and control of the operation activities as such location. In those substations where each Party hereto owns assets, each Party shall be responsible for its appropriate share, as set forth in Exhibit B hereto, of station power energy usage and expense.

5.5 Access Rights

The Parties shall provide each other such access rights as may be necessary for either Party's performance of its respective operational obligations under this Agreement; provided that, notwithstanding anything stated herein, a Party performing operational work within the boundaries of the other Party's assets must abide by the rules applicable to that site.

5.6 Switching and Tagging Rules

The Parties shall abide by their respective Switching and Tagging Rules for obtaining clearances for work or for switching operations on assets. The Parties will adopt mutually agreeable Switching and Tagging Rules prior to the effective date of this Agreement.


1.	Black Start Participation

In accordance with Good Utility Practice, Consumers agrees to participate in Transmission Owner’s Black Start Plan, as well as any verification testing. Nothing in this Agreement obligates a particular Unit to provide Black Start Service.


2.	Reactive Power

The supply and absorption of reactive power is dealt with in the Purchase and Sale Agreement for Ancillary Services among the Parties hereto.


3.	System Security

During an Emergency on the Transmission System or on an adjacent transmission system, the System Operator has the authority to direct Consumers to increase or decrease real power production (measured in MW) and/or reactive power production (measured in MVAR), within the design and operational limitations

of any of Consumers’ Generation Resources in service at the time, in order to maintain security on the Transmission System. In the event of such a declaration of an Emergency, determinations: (a) that the Transmission System security is in jeopardy, and/or (b) that there is a need to increase or decrease reactive power production, even if real power production is adversely affected, will be made solely by the System Operator or his designated representative. Each Unit operator will honor System Operator's orders and directives concerning said Unit’s real power and/or reactive power output within design and operational limitations of the Unit's equipment in service at the time, such that the security of the Transmission System is maintained. Transmission Provider and Transmission Owner shall restore the Transmission System conditions to normal to alleviate any such Emergency, in accordance with Good Utility Practice. Consumers will be compensated by Transmission Provider or Transmission Owner for increasing or decreasing the real power output of any of its Units as directed by the System Operator to support the Transmission System during an Emergency by the payment of (a) Consumers’ Incremental Cost associated with such increase or decrease in real power output or (b) at such other rate filed by a Party and approved by the Commission including any existing tariff or rate schedule which has been filed by the Transmission Provider, Transmission Owner or Consumers. Similarly, if the Transmission Provider or Transmission Owner requests any of Consumers’ Units to provide or absorb reactive power that would be outside of the Unit’s Reactive Design Limitations, requiring the Unit’s real power output to be reduced to obtain the desired reactive power, the Transmission Provider or Transmission Owner shall compensate Consumers at the real power rate discussed in the preceding sentence, to the extent that the Unit had to reduce real power output to operate within its Reactive Design Limitations, unless otherwise provided in another agreement or tariff on file with the Commission.

5.10 Consumers’ Voltage Regulation

Consumers shall have sufficient voltage regulation at each Unit to maintain an acceptable voltage level for the equipment at the Unit during periods of time that the Unit’s generation is off line.

5.11 Protection and System Quality

Consumers shall, at its expense, install, maintain, and operate System Protection Assets, including such protective and regulating devices as are identified by order, rule or regulation of any duly constituted regulatory authority having jurisdiction, or as are otherwise necessary to protect personnel and assets and to minimize deleterious effects to Transmission Provider’s or Transmission Owner’s electric service operation arising from the Unit. Transmission Owner shall install any such protective or regulating devices that may be required on Transmission Owner’s assets in connection with the operation of the Unit at Consumers’ expense.

5.11.1 Requirements for Protection. In compliance with applicable NERC, ECAR and Transmission Provider’s and Transmission Owner’s requirements, Consumers shall provide, own, and maintain relays, circuit breakers and all other devices necessary to promptly remove any fault contribution of the Unit to any short circuit occurring on the Transmission System not otherwise isolated by Transmission Owner’s assets. Such protective assets shall include, without limitation, a disconnecting device or switch with visible blade disconnect and load interrupting capability to be located between the Unit and the Transmission System at an accessible, protected, and satisfactory site selected upon mutual agreement of the Parties. The present integrated system provides for fault clearing at the generation substations. Unit protection may not be able to detect all short circuits, but the Parties agree that no other arrangements shall be required. Consumers shall be responsible for protection of the Unit and Consumers’ other associated assets from such conditions as negative sequence currents, over- or under-frequency, sudden load rejection, over- or under-voltage, and generator loss-of-field. Consumers shall be solely responsible for provisions to disconnect the Unit and

Consumers’ other associated assets when any of the disturbances described above occur on the Transmission System.

5.11.2 System Power Quality. Consumers’ facilities and equipment shall not cause excessive voltage flicker nor introduce excessive distortion to the sinusoidal voltage or current waves. Power output from and input to the Unit shall be in accordance with the power quality standards contained in IEEE Standards 141 - Recommended Practice for Electrical Power Distribution for Industrial Plants (voltage flicker) and 519 - Recommended Practices and Requirements for Harmonic Control in Electric Power Systems (harmonics). Consumers’ facilities and equipment have been designed and constructed in accordance with then-existing standards so as not to cause excessive voltage excursions nor cause the voltage to drop below or rise above the range maintained by Transmission Provider or Transmission Owner in the absence of Consumers’ facilities and equipment at the time the Unit first went into service.

5.11.3 Inspection. Subject to the confidentiality provisions set forth in Article 17, Transmission Provider and Transmission Owner shall have the right, but shall have no obligation or responsibility to (a) observe Consumers’ tests and/or inspection of any of Consumers’ protective assets directly connected to the Transmission System or interfacing with Transmission Owner’s protective assets, (b) review the settings of any of Consumers’ protective assets; and (c) review Consumers’ maintenance records relative to Consumers’ protective assets. Transmission Provider and Transmission Owner may exercise the foregoing rights from time to time as deemed necessary by Transmission Provider or Transmission Owner upon reasonable notice to Consumers. However, the exercise or non-exercise by Transmission Provider or Transmission Owner of any of the foregoing rights of observation, review or inspection shall be construed neither as an endorsement or confirmation of any aspect, feature, element, or condition of the Unit or Consumers’ protective assets or the operation thereof, nor as a warranty as to the fitness, safety, desirability, or reliability of same.

5.12 Outages, Interruptions, and Disconnection

5.12.1 Outage Authority and Coordination. In accordance with Good Utility Practice, each Party may, in close cooperation with the other and upon providing notice per Section 20.2, remove from service its assets that may impact the other Party's assets as necessary to perform maintenance or testing or to install or replace assets. Absent the existence or imminence of an Emergency, the Party scheduling a removal of a facility from service will schedule such removal on a date mutually acceptable to both Parties. Further, the Transmission Provider and Transmission Owner shall use their best efforts to coordinate the scheduling of maintenance on Transmission Owner’s Interconnection Assets to coincide with Consumers scheduled maintenance on its Units that may be impacted by maintenance on Transmission Owner’s Interconnection Assets.

5.12.2 Outage Restoration.

5.12.2.1 Unplanned Outage. In the event of an unplanned outage of a Party's facility that adversely affects the other Party's assets, the Party that owns or controls the facility out of service will use commercially reasonable efforts to promptly restore that facility to service.

5.12.2.2 Planned Outage. In the event of a planned outage of a Party's facility that adversely affects the other Party's assets, the Party that owns or controls the facility out of service will use commercially reasonable efforts to promptly restore that facility to service and in accordance with its schedule for the work that necessitated the planned outage.

5.12.3 Interruption. If at any time, in Transmission Provider’s or Transmission Owner’s reasonable judgment, the continued operation of the Unit would cause an Emergency, Transmission Provider or

Transmission Owner may curtail, interrupt, or reduce energy delivered from the Unit to the Transmission System until the condition which would cause the Emergency is corrected. Transmission Provider or Transmission Owner shall give Consumers as much notice as is reasonably practicable of Transmission Provider’s or Transmission Owner’s intention to curtail, interrupt, or reduce energy delivery from the Unit in response to a condition that would cause an Emergency and, where practicable, allow suitable time for the Parties to remove or remedy such condition before any such curtailment, interruption, or reduction commences. In the event of any curtailment, interruption, or reduction, Transmission Provider or Transmission Owner shall promptly confer with Consumers regarding the conditions that gave rise to the curtailment, interruption, or reduction, and Transmission Provider or Transmission Owner shall give Consumers Transmission Provider’s or Transmission Owner’s recommendation, if any, concerning the timely correction of such conditions. Transmission Provider or Transmission Owner shall promptly cease the curtailment, interruption, or reduction of energy delivery when the condition that would cause the Emergency ceases to exist.

5.12.4 Disconnection.

5.12.4.1 Disconnection after Agreement Terminates. Upon termination of the Agreement, Transmission Provider or Transmission Owner may disconnect Consumers’ Generation Resources from the Transmission System in accordance with a plan for disconnection upon which the Parties agree.

5.12.4.2 Disconnection in Event of Emergency. Subject to the provisions of Subsection 5.12.4.3 of this Agreement, Transmission Provider, Transmission Owner or Consumers shall have the right to disconnect the Unit without notice if, in Transmission Provider’s, Transmission Owner’s or Consumers’ sole opinion, an Emergency exists and immediate disconnection is necessary to protect persons or property from damage or interference caused by Consumers’ interconnection or lack of proper or properly operating protective devices. For purposes of this Subsection 5.12.4.2, protective devices may be deemed by Transmission Provider or Transmission Owner to be not properly operating if Transmission Provider’s or Transmission Owner’s review under Article 6 of this Agreement has disclosed irregular or otherwise insufficient maintenance on such devices or that maintenance records do not exist or are otherwise insufficient to demonstrate that adequate maintenance has been and is being performed.

5.12.4.3 Disconnection after Under-frequency Load Shed Event. NERC Planning Criteria require the interconnected transmission system frequency be maintained between 59.95 Hz and 60.05 Hz. In case of an under-frequency system disturbance, the Transmission System is designed to automatically activate a five-tier load shed program. The five load sheds occur at 59.5, 59.3, 59.1, 58.9 and 58.7 Hz, respectively. For those Units that are determined by Transmission Provider to be large enough to impact the Transmission Provider’s system security, each such Unit shall be capable of under-frequency operation as specified in Appendix 1 “Isolation of Generating Units” contained in ECAR Document No. 3 - Emergency Operations, or a higher under-frequency set point if already in place upon execution of this Agreement. Upon notice from Consumers and if the Transmission Provider or Transmission Owner agrees, Consumers may implement a higher under-frequency relay set point if necessary to protect its assets for a particular Unit or Units.

5.12.5 Continuity of Service. Notwithstanding any other provision of this Agreement, Transmission Provider shall not be obligated to accept, and Transmission Provider may require Consumers to curtail, interrupt or reduce deliveries of energy if such delivery of energy impairs Transmission Provider’s or Transmission Owner’s ability to construct, install, repair, replace or remove any of its equipment or any part

to its system or if Transmission Provider or Transmission Owner determines that curtailment, interruption or reduction is necessary because of Emergencies, forced outages, operating conditions on its system, or any reason otherwise permitted by applicable rules or regulations promulgated by a regulatory agency having jurisdiction over such matters. The Parties shall coordinate, and if necessary negotiate in good faith, the timing of such curtailments, interruptions, reductions or deliveries with respect to maintenance, investigation or inspection of Transmission Owner’s assets or system. Consumers reserves all rights under the Federal Power Act and applicable other federal and state laws and regulations to commence a complaint proceeding or other action with the Commission or other Governmental Authority with appropriate jurisdiction over the Parties to enforce the provisions of this Subsection 5.12.5.

5.12.6 Curtailment Notice. Except in case of Emergency, in order not to interfere unreasonably with the other Party's operations, the curtailing, interrupting or reducing Party shall give the other Party reasonable prior notice of any curtailment, interruption or reduction, the reason for its occurrence, and its probable duration.

5.13 Operating Expenses

Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses (including but not limited to telephone circuit charges, property taxes, insurance and assets testing) incurred by Transmission Owner in operating Transmission Owner’s Interconnection Assets, to the extent that Transmission Owner is not otherwise recovering such costs and expenses under an existing tariff or rate schedule which has been filed by Transmission Provider or Transmission Owner and accepted by FERC. Such costs and expenses shall be determined by Transmission Owner in accordance with the standard practices and policies followed by Transmission Provider or Transmission Owner for the performance of work for others in effect at the time such operation work is performed. Payment by Consumers shall be made in accordance with the provisions of Article 12 hereof.

ARTICLE 6

MAINTENANCE

6.1 Transmission Owner’s Obligations

Transmission Owner shall maintain its assets, to the extent they might reasonably be expected to have an impact on the operation of the Unit (a) in a safe and reliable manner in accordance with applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c) in accordance with the provisions of this Agreement.

6.2 Consumers’ Obligations

Consumers shall maintain its assets, to the extent they might reasonably be expected to have an impact on the operation of the Transmission System (a) in a safe and reliable manner in accordance with applicable operational and/or reliability criteria, protocols, and directives (which include those of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c) in accordance with the provisions of this Agreement.

6.3 Jointly Owned Assets

Maintenance of Jointly Owned Assets at the electric substations where Interconnection Facilities are located will be under the direction and control of the Party with more than fifty percent (50%) of the major

equipment at each such location, unless otherwise agreed by the Parties hereto. Said Party shall maintain the Jointly Owned Assets in a manner consistent with Good Utility Practice and the provisions of Sections 6.1 and 6.2 above, as appropriate. Each Party’s respective share of responsibility for the costs of maintenance of Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum. For purposes of this Agreement, major equipment is defined as set forth in Section 5.4 hereto. Exhibit B shall be updated with an addendum at least annually by the Transmission Owner, and approved in writing by Consumers, to show all changes in equipment and the effects of such changes on the determination of Jointly Owned Asset percentages. In the case where each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume the responsibility for direction and control of the maintenance activities at such location.

6.4 Access Rights

The Parties shall provide each other such access rights as may be necessary for either Party's performance of their respective maintenance and/or construction obligations under this Agreement; provided that, notwithstanding anything stated herein, a Party performing

maintenance and/or construction work within the boundaries of the other Party's assets must abide by the rules applicable to that site.

6.5 Maintenance Expenses

Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses (including but not limited to inspection, repair and replacement) incurred by Transmission Owner in maintaining Transmission Owner’s Interconnection Assets, to the extent that Transmission Owner is not otherwise recovering such costs and expenses under an existing tariff or rate schedule which has been filed by Transmission Provider or Transmission Owner and accepted by FERC. Such costs and expenses shall be determined by Transmission Owner in accordance with the standard practices and policies followed by Transmission Provider or Transmission Owner for the performance of work for others in effect at the time such operation work is performed. Payment by Consumers shall be made in accordance with the provisions of Article 12 of this Agreement.

6.6 Coordination

The Parties agree to confer regularly to coordinate the planning and scheduling of preventative and corrective maintenance. Each Party shall conduct preventive and corrective maintenance activities as planned and scheduled in accordance with this Section 6.5 and the Operating Agreement.

6.7 Inspections and Testing

Each Party shall perform routine inspection and testing of its assets in accordance with Good Utility Practice as may be necessary to ensure the continued interconnection of each Unit with the Transmission System in a safe and reliable manner.

6.8 Right to Observe Testing

Each Party shall, at its own expense, have the right to observe the testing of any of the other Party's assets whose performance may reasonably be expected to affect the reliability of the observing Party's assets. Each Party shall notify the other Party in advance of its performance of tests of its assets, and the other Party may have a representative attend and be present during such testing.

6.9 Secondary Systems

Each Party agrees to cooperate with the other in the inspection, maintenance, and testing of those Secondary Systems directly affecting the operation of a Party's assets which may reasonably be expected to impact the other Party. Each Party will provide advance notice to the other Party before undertaking any work in these areas, especially in electrical circuits involving circuit breaker trip and close contacts, current transformers, or potential transformers.

6.10 Observation of Deficiencies

If a Party observes any deficiencies or defects on, or becomes aware of a lack of scheduled maintenance and testing with respect to, the other Party's assets that might reasonably be expected to adversely affect the observing Party's assets, the observing Party shall either (a) provide notice to the other Party that is prompt under the circumstance or (b) deem such observation an Emergency to life or property and immediately disconnect the Unit pursuant to Subsection 5.12.4.2 of this Agreement, and the other Party shall make any corrections required in accordance with Good Utility Practice.

ARTICLE 7

EMERGENCIES

7.1 Obligations

Each Party agrees to comply with NERC and ECAR Emergency procedures and Transmission Provider, Transmission Owner and Consumers Emergency procedures, as applicable, with respect to Emergencies.

7.2 Notice

Transmission Provider or Transmission Owner shall provide Consumers with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect Consumers’ operation of any or all of its Generation Resources, to the extent Transmission Provider or Transmission Owner is aware of the Emergency. Consumers shall provide Transmission Provider and Transmission Owner with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect the Transmission System, to the extent Consumers is aware of the Emergency. In lieu of oral notification described in the preceding two sentences, the Parties may agree in advance to use other electronic notification means. To the extent the Party becoming aware of an Emergency is aware of the facts of the

Emergency, such notification shall describe the Emergency, the extent of the damage or deficiency, its anticipated duration, and the corrective action taken and/or to be taken. Any such notification given pursuant to this Section 7.2 shall be followed as soon as practicable with written notice.

7.3 Immediate Action

In case of an Emergency, the Party becoming aware of the Emergency may, in accordance with Good Utility Practice, take such action as is reasonable and necessary to prevent, avoid, or mitigate injury, danger, and loss, including disconnection pursuant to Subsection 5.12.4.2 of this Agreement.

7.4 Transmission Provider’s and Transmission Owner’s Authority

Transmission Provider or Transmission Owner may, consistent with Good Utility Practice, take whatever actions with regard to the Transmission System as it may deem necessary during an Emergency in order to (a) preserve public health and safety, (b) preserve the reliability of the Transmission System, (c) limit or prevent damage and (d) expedite restoration of service. Transmission Provider or Transmission Owner shall use reasonable efforts to minimize the effect of such actions on the Unit.

7.5 Consumers’ Authority

Consumers may, consistent with Good Utility Practice, take whatever actions with regard to the Unit as it may deem necessary during an Emergency in order to (a) preserve public health and safety, (b) preserve the reliability of the Unit, (c) limit or prevent damage and (d) expedite restoration of service. Consumers shall use reasonable efforts to minimize the effect of such actions on the Transmission System.

7.6 Audit Rights

Each Party shall keep and maintain records of actions taken during an Emergency that may reasonably be expected to impact the other Party's assets and make such records available for third-party independent audit upon the request and expense of the party affected by such action. Any such request for an audit will be no later than twelve (12) months following the action taken.

ARTICLE 8

SAFETY

8.1 General

The Parties agree that all work performed by a Party that may reasonably be expected to affect another Party shall be performed in accordance with Good Utility Practice and all applicable laws, regulations, and other requirements pertaining to the safety of persons or property. A Party performing work within the boundaries of another Party’s assets must abide by the safety rules applicable to the site.

8.2 Environmental Releases

Each Party shall notify the other Parties, first orally and then in writing, of the release of any Hazardous Substances or any type of remedial activities, such as asbestos or lead abatement, which may reasonably be expected to affect another Party, as soon as possible but not later than twenty-four (24) hours after the Party becomes aware of the occurrence, and shall promptly furnish to the other Parties copies of any reports filed with any governmental agencies addressing such events.

ARTICLE 9

METERING

9.1 General

Transmission Owner shall provide, install, own and maintain Metering Assets necessary to meet its obligations under this Agreement. Notwithstanding the foregoing sentence, Consumers, if mutually agreed by the Parties, may provide and install some, or all, of said Metering Assets, as per Transmission Owner’s specifications. The Parties agree that, as to all Connection Points in existence as of the effective date of this Agreement, no new Metering Assets or arrangements shall be required. If necessary, Metering Assets shall be either located or adjusted, at Transmission Provider’s or Transmission Owner’s option, in such manner to account for (a) any transformation or interconnection losses between the location of the meter and the Point of Receipt and (b) any station auxiliary power load of the generating unit. Metering quantities, in analog and/or digital form, shall be provided to Consumers upon request. The Parties also agree that Consumers shall continue to maintain records of the Megawatthour and Megavarhour values collected from existing meters on the generating units and provide the information recorded to Transmission Provider or Transmission Owner upon request.

9.2 Costs of Administering Metering Assets

All costs associated with the administration of Metering Assets and the provision of metering data to Consumers shall be borne by Consumers. The costs of administration and of providing metering data shall be separately itemized on Transmission Owner’s invoices to Consumers pursuant to Article 12 of this Agreement. All costs associated with changes to Metering Assets requested by Consumers, shall be borne by Consumers and shall be invoiced pursuant to Article 12 of this Agreement.

9.3 Testing of Metering Assets

Transmission Owner shall, at Consumers’ expense, inspect and test all Metering Assets not less than once every year, unless an extension of the testing cycle is agreed upon by the Parties. If requested to do so by Consumers and at Consumers’ expense, Transmission Owner shall inspect or test Metering Assets more frequently. Transmission Owner shall give reasonable notice of the time when any inspection or test shall take place and Consumers may have representatives present at the test or inspection. If Metering Assets is found to be inaccurate or defective, it shall be adjusted, repaired or replaced at Consumers’ expense, in order to provide accurate metering. If Metering Assets fails to register, or if the measurement made by Metering Assets during a test varies by more than two percent (2%) from the measurement made by the standard Metering Assets used in the test, adjustment shall be made correcting all measurements made by the inaccurate Metering Assets for (a) the actual period during which inaccurate measurements were made, if the period can be determined, or (b) a period equal to one-half of the elapsed time since the last test of the Metering Assets.

9.4 Metering Data

9.4.1 When the Metering Assets location is not at the Point of Receipt, Metering Assets readings shall be adjusted to account for appropriate transformer and line losses, and when applicable, the station auxiliary power load of the Unit.

9.4.2 At Consumers’ expense, all metered data shall be telemetered to one or more locations designated by Transmission Provider and one or more locations designated by Consumers.

9.5 Communications

9.5.1 At Consumers’ expense, Consumers shall maintain satisfactory operating communications with System Operator or representative, as designated by Transmission Provider or Transmission Owner. Consumers has provided standard voice and facsimile communications in the control room of each of its Units through use of the public telephone system. Consumers has also provided a 4-wire, full duplex data circuit (or circuits) operating at a minimum of 9600 baud, or at other baud rates as reasonably specified by Transmission Provider or Transmission Owner. The data circuit(s) extend from each Consumers’ Unit to a location, or locations, specified by Transmission Provider or Transmission Owner. Any required maintenance of such communications assets shall be performed at Consumers’ expense, and may be performed by Consumers or by Transmission Owner. Operational communications shall be activated and maintained under, but not be limited to, the following events: system paralleling or separation, scheduled and unscheduled shutdowns, equipment clearances, and hourly and daily load data exchanges. To the extent required by applicable rules and regulations, Consumers shall (a) request permission from the System Operator prior to opening or closing circuit breakers that affect the Transmission System, (b) carry out switching orders from the System Operator in a timely manner and (c) keep the System Operator advised of the Unit’s operational capabilities as required for reliable operation of the Transmission System.

9.5.2 For all Units 1 MW or larger, a Remote Terminal Unit ("RTU"), or equivalent data collection and transfer equipment acceptable to Consumers and Transmission Owner, has been installed to gather accumulated and instantaneous data to be telemetered to a location, or locations, designated by Transmission Owner through use of dedicated point-to-point data circuits as indicated in Subsection 9.5.1 of this Agreement. Instantaneous bi-directional analog real power and reactive power flow information, circuit breaker status information, instantaneous analog voltage information, metering information, and disturbance monitoring information, as determined by Transmission Provider or Transmission Owner, must be telemetered directly to the location, or locations, specified by Transmission Provider or Transmission Owner.

ARTICLE 10

FORCE MAJEURE

10.1 An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or assets, any curtailment, order, regulation or restriction imposed by governmental military or lawfully established civilian authorities, or any other cause beyond a Party's reasonable control. A Force Majeure event does not include an act of negligence or intentional wrongdoing.

10.2 If either Party is rendered unable, wholly or in part, by Force Majeure, to carry out its obligations under this Agreement, then, during the continuance of such inability, the obligation of such Party shall be suspended except that Consumers’ obligation under Section 5.11 of this Agreement to provide protection while operating in parallel with the Transmission System shall not be suspended. The Party relying on Force Majeure shall give written notice of Force Majeure to the other Party as soon as practicable after

such event occurs. Upon the conclusion of Force Majeure, the Party heretofore relying on Force Majeure shall, with all reasonable dispatch, take all necessary steps to resume the obligation previously suspended.

10.3 Any Party’s obligation to make payments already owing shall not be suspended by Force Majeure.

ARTICLE 11

INFORMATION REPORTING

Each Party shall, in accordance with Good Utility Practice, promptly provide to the other Parties all relevant information, documents, or data regarding the Party's assets which may reasonably be expected to pertain to the reliability of the other Parties’ assets and/or which has been reasonably requested by the other Parties.

ARTICLE 12

PAYMENTS AND BILLING PROCEDURES

12.1 Invoices

Any invoices for reimbursable services provided to another Party under this Agreement during the preceding month shall be prepared within a reasonable time after the first day of each month. Each invoice shall delineate the month in which services were provided, shall fully describe the services rendered and shall be itemized to reflect the services performed or provided. The invoice shall be paid so that the other Party will receive the funds by the 20 ^th day following the date of such invoice, or the first business day thereafter if the payment date falls on other than a business day. All payments shall be made in immediately available funds payable to another Party, or by wire transfer to a bank named by the Party being paid, provided that payments expressly required by this Agreement to be mailed shall be mailed in accordance with Section 12.2.

12.2 Payments

Any payments to be made by Consumers under this Agreement shall be made to Transmission Owner at the following address:

Michigan Electric Transmission Company, LLC

P.O. Box 673971

Detroit, MI 48267-3971

Attn: Accounting Department

If paying by wire transfer, please see the wiring instructions on the invoice.

Any payments to be made by Transmission Owner under this Agreement shall be made to Consumers at the following address:

Consumers Energy Company

One Energy Plaza

Jackson, Michigan 49201

Attn: Treasurer

The Parties shall provide the names of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing of names and addresses up to date.

12.3 Interest Charges

Interest on any unpaid amounts shall be calculated in accordance with the methodology specified for interest on refunds in the Commission’s regulations at 18 CFR. §35.19 (a)(2)(iii). Interest on delinquent amounts shall be calculated from the due date of the invoice to the date of payment. When payments are made by mail, invoices shall be considered as having been paid on the date of receipt by Transmission Owner or Consumers, as the case may be.

12.4 Disputes

In the event of a billing dispute between Transmission Owner and Consumers, the Parties shall continue to provide services and pay all invoiced amounts not in dispute. While the dispute is being resolved, the Parties shall continue to provide services and pay all invoiced amounts not in dispute. Following resolution of the dispute, the prevailing Party shall be entitled to receive the disputed amount, as finally determined to be payable, along with interest accrued through the date on which payment is made at the interest rate pursuant to Section 13.3. Payment shall be due within ten (10) days of resolution.

ARTICLE 13

ASSIGNMENT

13.1 This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the respective parties hereto. This Agreement shall not be transferred or otherwise alienated by any Party without the other Parties' prior written consent, which consent shall not be unreasonably withheld, provided that any assignee shall expressly assume assignor's obligations hereunder and, unless expressly agreed to by the other Parties, no assignment shall relieve the assignor of its obligations hereunder in the event its assignee fails to perform. Any attempted assignment, transfer or other alienation without such consent shall be void and not merely voidable.

13.2 Notwithstanding the above, the Transmission Provider or Transmission Owner shall be permitted to assign or otherwise transfer this Agreement, or its rights, duties and obligations hereunder, in whole or in part, by operation of law or otherwise, without the prior written consent of Consumers, to any successor to or transferee of the direct or indirect ownership or operation of all or part of the transmission system to which the Generation Resources are connected. Upon the assumption by any such permitted assignee of the assigning Transmission Provider’s or Transmission Owner’s rights, duties and obligations hereunder, the assigning Transmission Provider or Transmission Owner shall be released and discharged therefrom to the extent provided in the assignment agreement.

13.3 Notwithstanding the above, Consumers may assign this Agreement to a bank pursuant to the terms of an Assignment and Security Agreement without the prior written consent of Transmission Provider or Transmission Owner provided that such assignment shall not be effective as to Transmission Provider or Transmission Owner until it receives a fully executed copy thereof.

ARTICLE 14

INDEMNITY AND INSURANCE

14.1 Indemnity

The Parties shall at all times assume all liability for, and shall indemnify and save the other Parties harmless from any and all damages, losses, claims, demands, suits, recoveries, costs, legal fees, expenses for injury to or death of any person or persons whomsoever, or for any loss, destruction of or damage to any property of third persons, firms, corporations or other entities that occurs on its own system and that arises out of or results from, either directly or indirectly, its own assets or assets controlled by it, unless caused by the sole negligence, or intentional wrongdoing, of another Party.

14.2 Insurance

14.2.1 The Parties agree to maintain, at their own cost and expense, the following insurance coverages for the life of this Agreement in the manner and amounts, at a minimum, as set forth below:


(a)	Workers’ Compensation Insurance in accordance with all applicable State, Federal, and Maritime Law.


(b)	Employer’s Liability insurance in the amount of $1,000,000 per accident.


(c)	Commercial General Liability or Excess Liability Insurance in the amount of $25,000,000 per occurrence.


(d)	Automobile Liability Insurance for all owned, non-owned, and hired vehicles in the amount of $5,000,000 each accident.

14.2.2 A Party may, at its option, [A] be an approved self-insurer for the insurances required in 1.(a) and (d); and [B] maintain such deductibles and/or retentions under the insurance required in 1.(b) and (c) as is maintained by other similarly situated companies engaged in a similar business. The Parties agree that all amounts of self-insurance, retentions and/or deductibles are the responsibility of, and shall be borne by, the Party whom makes such an election.

14.2.3 Within fifteen (15) days of the Effective Date and thereafter when requested, in writing, but not more than once every 12 months, during the term of this Agreement (including any extensions) each Party shall provide to the other Parties properly executed and current certificates of insurance or evidence of approved self-insurance status with respect to all insurance required to be maintained by such Party under this Agreement. Certificates of insurance shall provide the following information:


(a)	Name of insurance company, policy number and expiration date.


(b)	The coverage maintained and the limits on each, including the amount of deductibles or retentions, which shall be for the account of the Party maintaining such policy.


(c)	The insurance company shall endeavor to provide thirty (30) days prior written notice of cancellation to the certificate holder.

ARTICLE 15

LIMITATION ON LIABILITY

NO PARTY SHALL IN ANY EVENT BE LIABLE TO THE OTHER PARTIES FOR ANY SPECIAL, INCIDENTAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES SUCH AS, BUT NOT LIMITED TO, LOST PROFITS, REVENUE OR GOOD WILL, INTEREST, LOSS BY REASON OF SHUTDOWN OR NON-OPERATION OF EQUIPMENT OR MACHINERY, INCREASED EXPENSE OF OPERATION OF EQUIPMENT OR MACHINERY, COST OF PURCHASED OR REPLACEMENT POWER OR SERVICES OR CLAIMS BY CUSTOMERS, WHETHER SUCH LOSS IS BASED ON CONTRACT, WARRANTY, NEGLIGENCE, STRICT LIABILITY OR OTHERWISE.

ARTICLE 16

BREACH, CURE AND DEFAULT

16.1 General

A breach of this Agreement ("Breach") shall occur upon the failure by a Party to perform or observe any material term or condition of this Agreement. Default of this Agreement ("Default") shall occur upon the failure of a Party in Breach of this Agreement to cure such Breach in accordance with the provisions of Section 16.4 of this Agreement.

16.2 Events of Breach

A Breach of this Agreement shall include:

16.2.1 The failure to pay any amount when due;

16.2.2 The failure to comply with any material term or condition of this Agreement, including but not limited to any material Breach of a representation, warranty or covenant made in this Agreement;

16.2.3 If a Party: (a) becomes insolvent; (b) files a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; (c) makes a general assignment for the benefit of its creditors or (d) consents to the appointment of a receiver, trustee or liquidator;

16.2.4 Assignment of this Agreement in a manner inconsistent with the terms of this Agreement;

16.2.5 Failure of a Party to provide such access rights, or a Party's attempt to revoke or terminate such access rights, as provided under this Agreement; or

16.2.6 Failure of a Party to provide information or data to the other Parties as required under this Agreement, provided the Party entitled to the information or data under this Agreement requires such information or data to satisfy its obligations under this Agreement.

16.3 Continued Operation

In the event of a Breach or Default by a Party, the Parties shall continue to operate and maintain, as applicable, such DC power systems, protection and Metering Assets, Telemetering Assets, SCADA equipment, transformers, Secondary Systems, communications assets, building assets, software, documentation, structural components, and other assets and appurtenances that are reasonably necessary for

Transmission Provider or Transmission Owner to operate and maintain the Transmission System and for Consumers to operate and maintain the Unit, in a safe and reliable manner.

16.4 Cure and Default

Upon the occurrence of an event of Breach, the Party or Parties not in Breach (hereinafter the "Non-Breaching Party"), when it becomes aware of the Breach, shall give written notice of the Breach to the Breaching Party and to any other person the Parties to this Agreement identify in writing to the other Parties in advance. Such notice shall set forth, in reasonable detail, the nature of the Breach, and where known and applicable, the steps necessary to cure such Breach. Upon receiving written notice of the Breach hereunder, the Breaching Party shall have thirty (30) days to cure such Breach. If the Breach is such that it cannot be cured within thirty (30) days, the Breaching Party will commence in good faith all steps as are reasonable and appropriate to cure the Breach within such thirty (30) day time period and thereafter diligently pursue such action to completion. In the event the Breaching Party fails to cure the Breach, or to commence reasonable and appropriate steps to cure the Breach, within thirty (30) days of becoming aware of the Breach; the Breaching Party will be in Default of the Agreement.

16.5 Right to Compel Performance

Notwithstanding the foregoing, upon the occurrence of an event of Default, the non-Defaulting Party or Parties shall be entitled to: (a) commence an action to require the Defaulting Party to remedy such Default and specifically perform its duties and obligations hereunder in accordance with the terms and conditions hereof and (b) exercise such other rights and remedies as it may have in equity or at law.

ARTICLE 17

CONFIDENTIALITY

17.1 All information regarding a Party (the “Disclosing Party”) that is furnished directly or indirectly to another Party (the “Recipient”) pursuant to this Agreement and marked “Confidential” shall be deemed “Confidential Information”. Notwithstanding the foregoing, Confidential Information does not include information that (i) is rightfully received by Recipient from a third party having an obligation of confidence to the Disclosing Party, (ii) is or becomes in the public domain through no action on Recipient’s part in violation of this Agreement, (iii) is already known by Recipient as of the date hereof, or (iv) is developed by Recipient independent of any Confidential Information of the Disclosing Party. Information that is specific as to certain data shall not be deemed to be in the public domain merely because such information is embraced by more general disclosure in the public domain.

17.1.1 Recipient shall keep all Confidential Information strictly confidential and not disclose any Confidential Information to any third party for a period of two (2) years from the date the Confidential Information was received by Recipient, except as otherwise provided herein.

17.1.2 Recipient may disclose the Confidential Information to its affiliates and its affiliates’ respective directors, officers, employees, consultants, advisors, and agents who need to know the Confidential Information for the purpose of assisting Recipient with respect to its obligations under this Agreement. Recipient shall inform all such parties, in advance, of the confidential nature of the Confidential Information. Recipient shall cause such parties to comply with the requirements of this Agreement and shall be responsible for the actions, uses, and disclosures of all such parties.

17.1.3 If Recipient becomes legally compelled or required to disclose any of the Confidential Information (including, without limitation, pursuant to the policies, methods, and procedures of the FERC,

including the OASIS Standards of Conduct, or other Regulatory Authority), Recipient will provide the Disclosing Party with prompt written notice thereof so that the Disclosing Party may seek a protective order or other appropriate remedy. Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required, and Recipient will cooperate, at the Disclosing Party’s expense, with the Disclosing Party’s counsel to enable the Disclosing Party to obtain a protective order or other reliable assurance that confidential treatment will be accorded the Confidential Information. It is further agreed that, if, in the absence of a protective order, Recipient is nonetheless required to disclose any Confidential Information, Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required.

ARTICLE 18

AUDIT RIGHTS

Subject to the requirements of confidentiality under Article 17 of this Agreement, each Party shall have the right, during normal business hours, and upon prior reasonable notice to another Party, to audit one another's accounts and records pertaining to the Party's performance and/or satisfaction of obligations arising under this Agreement. Said audit shall be performed at the offices where such accounts and records are maintained and shall be limited to those portions of such accounts and records that relate to obligations under this Agreement.

ARTICLE 19

DISPUTES

The Dispute Resolution Procedures set forth in the MISO Tariff shall apply to all disputes arising under this Agreement.

ARTICLE 20

NOTICES

20.1 Any notice, demand or request required or permitted to be given by a Party to another and any instrument required or permitted to be tendered or delivered by a Party to another may be so given, tendered or delivered, as the case may be, by depositing the same in any United States Post Office with postage prepaid, for transmission by certified or registered mail, addressed to the Party, or personally delivered to the Party, at the address set out below:

To Transmission Owner:

Michigan Electric Transmission Company, LLC

27175 Energy Way

Novi, MI 48377

Attn: Legal Department - Contracts

To Consumers:

Consumers Energy Company

1945 W. Parnall Road

Jackson, Michigan 49201

Attn: Director of Staff - Energy Resources Business Services

To Transmission Provider:

Midcontinent Independent System Operator, Inc.

Attn: Manager, Interconnection Planning

701 City Center Drive

Carmel, IN 46032

20.2 The Parties shall use standard telephone circuits as the primary communication link for generation dispatch communications, including with respect to dispatching energy in the event of an Emergency and declaring unit capability. The Parties shall provide the names and telephone numbers of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing of names and telephone numbers up to date.

ARTICLE 21

MISCELLANEOUS

21.1 Amendments

This Agreement may be amended by and only by a written instrument duly executed by the Parties hereto. No change or modification as to any of the provisions hereof shall be binding on any Party unless approved in writing and approved by the duly authorized officers of the Parties. Notwithstanding the foregoing, nothing contained herein shall be construed as affecting in any way the right of Transmission Provider, Transmission Owner or Consumers to unilaterally make application to the Commission for a change in rates, terms or conditions of service under Sections 205 and 206 of the Federal Power Act and pursuant to the Commission's Rules and Regulations promulgated thereunder. Transmission Provider reserves the right to file rate schedules with the Commission concerning any services Transmission Provider deems necessary for reliable and orderly bulk power system management, including but not limited to any standby or related services that may arise from a failure by Consumers to meet its schedule of deliveries across the assets covered by this Agreement.

21.2 Binding Effect

This Agreement and the rights and obligations hereof, shall be binding upon and shall inure to the benefit of the successors and assigns of the Parties hereto.

21.3 Counterparts

This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument.

21.4 Entire Agreement

This Agreement constitutes the entire agreement among the Parties hereto with reference to the subject matter hereof and its execution superseded all previous agreements, discussions, communications and correspondence with respect to said subject matter. The terms and conditions of this Agreement and every Exhibit referred to herein shall be amended, as mutually agreed to by the Parties, to comply with changes or alterations made necessary by a valid applicable order of any governmental regulatory authority, or any court, having jurisdiction hereof.

21.5 Governing Law

The validity, interpretation and performance of this Agreement and each of its provisions shall be governed by the applicable laws of the State of Michigan, exclusive of its conflict of laws principles.

21.6 Headings Not To Affect Meaning

The descriptive headings of the various Articles and Sections of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict any of the terms and provisions hereof.

21.7 Waivers

Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matters arising in connection with this Agreement, shall not be deemed a waiver or continuing waiver with respect to any subsequent default or other matter.


1.	Termination of Predecessor Interconnection Agreement

On the Effective Date, the June 18, 2013 Amendment and Restatement of the Generator Interconnection Agreement between Transmission Provider, Transmission Owner and Consumers shall terminate and be replaced by this Agreement with regard to the Units covered by this Agreement, except insofar as necessary to resolve billing and related matters arising from service rendered and other events occurring before the Effective Date.

IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed by their duly authorized officers.

MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC, a Michigan limited liability company

By: ITC Holdings Corp., its manager

By: /s/ Simon S. Whitelocke

Title: Vice President, ITC Holdings Corp. & President ITC Michigan

CONSUMERS ENERGY COMPANY

By: /s/ David B. Kehoe

Title: Executive Director of Staff - Energy Resources Business Services

MIDCONTINENT INDEPENDENT SYSTEM OPERATOR, INC.

By: /s/ Jennifer Curran

Title: Vice President, System Planning & Seams Coordination

EXHIBIT A - CONSUMERS GENERATION RESOURCES



Generating Unit	Nameplate Rated MVA (1)	Summer Net Demonstrated MW Capability	Winter Net Demonstrated MW Capability	Kilovolts	RPM	Cooling	AGC Capable	AGC Ramp MW/Min	Black Start Capable	Synch Breaker	Comments
Campbell 1	312.0	260.0	260.0	16.0	3,600	Hydrogen	Yes	3	No	199
Campbell 2	492.0	355.0	360.0	20.0	3,600	Water/Hydrogen	Yes	3	No	299
Campbell A	21.9	13.0	17.0	13.8	3,600	Air	No	—	No	C16	Returned to Service in February of 2015.


Gaylord 1	18.8	14.0	17.0	13.8	3,600	Air	No	—	No	116	Returned to Service February 2016.
Gaylord 2	18.8	14.0	17.0	13.8	3,600	Air	No	—	No	216	Returned to Service February 2016.
Gaylord 3	18.8	14.0	17.0	13.8	3,600	Air	No	—	No	316	Returned to Service February 2016.
Karn 1	336.0	255.0	255.0	16.0	3,600	Hydrogen	Yes	3	No	199
Karn 2	320.0	260.0	260.0	16.0	3,600	Hydrogen	Yes	3	No	299
Karn 3	814.7	638.0	638.0	26.0	3,600	Water/Hydrogen	Yes	6	No	28R8/28H9	AGC Ramp Rate: 6 is avg. 9 Mw/min 60 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Karn 4	835.0	638.0	638.0	26.0	3,600	Water/Hydrogen	Yes	6	No	32F7/32H9	AGC Ramp Rate: 6 is avg. 9 Mw/min 70 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Straits 1	25.0	5.0	10.0	13.8	3,600	Air	No	—	No	S16	Returned to Service February 2016.
Thetford 2	39.5	29.0	37.0	13.8	3,600	Air	No	—	No	216	Blackstart capable.
Thetford 3	39.5	30.0	37.0	13.8	3,600	Air	No	—	Yes	316	Blackstart Resource until May 2015.
Thetford 4	39.5	30.0	37.0	13.8	3,600	Air	No	—	Yes	416	Blackstart Resource until May 2015.
Alcona Hydro 1	4.4	4.0	4.0	5.0	90	Air	NA	NA	No	116/166
Alcona Hydro 2	4.4	4.0	4.0	5.0	90	Air	NA	NA	No	216/166
Calkins Bridge Hydro 1	0.6	0.4	0.4	4.8	180	Air	NA	NA	No	116/166	Also known as Allegan Hydro
Calkins Bridge Hydro 2	1.1	0.9	0.9	4.8	120	Air	NA	NA	No	216/166	Also known as Allegan Hydro
Calkins Bridge Hydro 3	1.5	1.2	1.2	4.8	113	Air	NA	NA	No	316/166	Also known as Allegan Hydro
Cooke Hydro 1	3.3	1.5	1.5	2.5	180	Air	NA	NA	No	116/166
Cooke Hydro 2	3.3	3.0	3.0	2.5	180	Air	NA	NA	No	216/166
Cooke Hydro 3	3.3	3.0	3.0	2.5	180	Air	NA	NA	No	316/166
Croton Hydro 1	3.8	2.9	2.9	7.2	225	Air	NA	NA	No	116/246
Croton Hydro 2	3.8	2.9	2.9	7.2	225	Air	NA	NA	No	216/246
Croton Hydro 3	1.4	1.3	1.3	7.2	150	Air	NA	NA	No	316/246
Croton Hydro 4	1.6	1.3	1.3	7.2	150	Air	NA	NA	No	416/246
Five Channels 1	3.3	3.2	3.2	2.5	150	Air	NA	NA	No	116/166
Five Channels 2	3.3	3.2	3.2	2.5	150	Air	NA	NA	No	216/166

EXHIBIT A - CONSUMERS GENERATION RESOURCES



Generating Unit	Nameplate Rated MVA (1)	Summer Net Demonstrated MW Capability	Winter Net Demonstrated MW Capability	Kilovolts	RPM	Cooling	AGC Capable	AGC Ramp MW/Min	Black Start Capable	Synch Breaker	Comments
Foote Hydro 1	3.3	3.3	3.3	5.0	90	Air	NA	NA	No	116/366
Foote Hydro 2	3.3	3.3	3.3	5.0	90	Air	NA	NA	No	216/366
Foote Hydro 3	3.3	3.3	3.3	5.0	90	Air	NA	NA	No	316/366
Hodenpyl Hydro 1	8.9	9.2	9.2	7.5	120	Air	NA	NA	No	116/266
Hodenpyl Hydro 2	8.9	9.2	9.2	7.5	120	Air	NA	NA	No	216/266
Loud Hydro 1	2.2	2.2	2.2	2.5	120	Air	NA	NA	No	116/266
Loud Hydro 2	2.2	2.2	2.2	2.5	120	Air	NA	NA	No	216/266
Mio Hydro 1	2.7	2.2	2.2	2.5	80	Air	NA	NA	No	116/166
Mio Hydro 2	2.7	2.2	2.2	2.5	80	Air	NA	NA	No	216/166
Rogers Hydro 1	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	116/166
Rogers Hydro 2	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	216/166
Rogers Hydro 3	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	316/166
Rogers Hydro 4	1.9	1.5	1.5	7.5	150	Air	NA	NA	No	416/166
Tippy Hydro 1	7.1	7.0	7.0	7.5	109	Air	NA	NA	No	116/266/126
Tippy Hydro 2	7.1	7.0	7.0	7.5	109	Air	NA	NA	No	216/266/126
Tippy Hydro 3	7.1	7.0	7.0	7.5	109	Air	NA	NA	No	316/266/126
Webber Hydro 1	3.3	2.3	2.3	7.2	164	Air	NA	NA	No	116/166
Webber Hydro 2	1.3	1.0	1.0	2.5	200	Air	NA	NA	No	216
Notes: (1) Rated MVA represents generator machine capability limits. Turbine or main transformer limits may be more restrictive.

EXHIBIT B - INTERCONNECTION ASSETS

General

The Parties agree that certain assets located at each of the electrical Substations at which Consumers’ Generation Resources are connected to the Transmission System are an integral part of the assets required by the Parties to provide services under their respective charters and that the physical partition would be impossible, impractical and wholly inconsistent with the purposes for which this Agreement is made. Said assets are deemed to be Jointly Owned Assets. In general, said assets include, but in some of the electrical Substations shall not be limited to, the following:


Foundations	All foundations not identified as belonging to a specific piece of assets in the Plant Accounting Records.


Structures	All steel support structures.


Station wiring	All buswork, control cables, batteries, battery chargers and ground grids.


Fencing	All chain-link fencing surrounding or used within the specific electrical Substation.


Control house	Any building located within the Substation used to house relaying, controls or telemetry equipment beneficial to and used by both Parties.


Stone	All stone used in the Substation yards, driveways and drains.

At each of the substations listed in this Exhibit B, an allocated percentage of the Jointly Owned Assets is determined for each Party hereto, in accordance with the provisions of this Agreement

For each of the electrical Substations at which Consumers’ Generation Resources are connected to the Transmission System, the specific assets allocated to and owned by Consumers are identified below as Consumers’ Interconnection Assets. In certain 345 kV Substations, specific breakers and associated assets that have been designated for operation by Consumers are also specifically identified as Transmission Owner’s Interconnection Assets.

Some of the electrical Substations containing Interconnection Assets also contain Distribution System assets owned by Consumers. Unless said Distribution System assets are directly involved in the connection of Consumers’ Generation Resources to the Transmission System, they are not described in the description of assets that follow.

The balance of the assets in each electrical Substation are allocated to and owned by the Transmission Owner and considered a part of the Transmission System.

Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties and approved in writing by the Local Distribution Company to show changes in ownership. For current ownership (reflecting ownership changes since July 24, 2008), see the WDs in the DMS.

Exhibit B - Table 1

Jointly Owned Asset Ownership by Percent of Major Equipment

Addendum 6 - Final 09/16/16

Substations

Jointly Owned Assets

Percentage Split by Major Equipment Count

(Substations with 100% ownership by Major Equipment Count Not Included)



Substation Name	Distribution	Transmission	Generation Owned by Local Distribution Company	Third-Party Assets	Last Revision Date
Campbell 138 kV ¹	0.00	64.28	35.24	0.48	08/16/12
Gaylord	44.44	44.44	11.12		01/01/10
Karn Plant	0.00	63.64	36.36		01/01/10
Morrow	63.33	30.00	6.67		08/16/12
Thetford	0.00	92.00	8.00		04/29/02

--________________________

¹ At 120 kV and above, third-party related assets will be included as part of the Transmission assets for purposes of making this calculation. Also, the third party may share in the financial responsibility associated with O&M activities.

Changes, relative to previous revisions (addendums), are shown in bold type .

Major equipment is defined in Section 5.4 of the GIA. Generator Connections located at Substations in the Transmission System

Campbell 1&2 Plant

The Campbell 1&2 Plant consists of three generating Units, known as Unit 1 (consisting of generators 1A and 1B), Unit 2 and Unit A. (The Campbell 3 Plant is located at the same site, but has separate interconnection facilities and is covered by a separate generator interconnection agreement.)

The Connection Point for Units 1, 2 and A are in the Campbell 138 kV Substation (see Wiring Diagram #93, Sheet 31 attached).

The Points of Receipt for all the Units in the Campbell 1&2 Plant are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers’ owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93, Sheet 31):

Transformer Bank No. A (located outside of substation; not included in JOA calc)


Circuit Breakers	Nos. 199, 299, 799, 899 *, 999 and 16A (16A is rated < 23kV and not considered major equipment per GIA definition).


Switches	Nos. 99A, 195, 196, 295, 296, 709, 793, 795, 796, 809 * , 893 * , 895 , 896 , 909, 993, 995 and 996


Circuit Connections	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork


Relay & Controls	All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

* Jointly Owned asset with Michigan Public Power Agency (4.8%) and Wolverine Power Supply Cooperative (1.8%)

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93, Sheet 31):

Transformer Bank No. 5

Circuit Breakers Nos. 148, 188, 288, 388, 488, 500, 566, 588 and 599


Switches	Nos. 108, 144, 145, 146, 184, 185, 186, 208, 284, 285, 286, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 509, 545, 546, 564, 584, 585, 586, 1020 and 1121


Circuit Connections	All wire, cable or bus work electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer bus work


Relay and Controls	All relays and controls associated with the Circuit Breakers identified above


Foundations	All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Campbell 138 kV Substation - See Exhibit B - Table 1

CEII MATERIAL

Gaylord Generating Plant Complex

The Gaylord Generating Plant Complex consists of five combustion turbine generating Units, known as Units 1 through 5, respectively.

The Connection Points for Units 1 through 5 are in the Gaylord Generating Substation (see Wiring Diagram #495, Sheet 31 attached).

The Points of Receipt for all the Units in the Gaylord Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495, Sheet 31):

Transformer Banks Nos. 1, 2* and 3* (*located outside of substation; not included in JOA calc)


Circuit Breakers	Nos. A16, 116, 146, 166, 199, 216, 316, 416* and 1288 (*located outside of substation; not included in JOA calc)


Switches	Nos. 3,142, 144, 145, 162, 164, 165, 191, 193, 195, 299, 399, 1282 and 1284


Circuit Connections	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above


Relay & Controls	All relays and controls associated with the Circuit Breakers identified above


Foundations	All foundations supporting the Transformers and Circuit Breakers identified above


Auxiliary Power	All station power assets shown in the attached Wiring Diagram #495, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495, Sheet 31):


Capacitor Bank	No. 3


Circuit Breakers	Nos. 356, 377 and 477


Switches	Nos. 352, 371, 373, 382, 384, 471 and 473


Circuit Connections	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above


Relay & Controls	All relays and controls associated with the Circuit Breakers identified above


Foundations	All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Gaylord Generating Substation - See Exhibit B - Table 1

CEII MATERIAL

Karn Generating Plant Complex

The Karn Generating Plant Complex consists of four generating Units, known as Units 1 (consisting of generators 1A and 1B), Unit 2 (consisting of generators 2A and 2B, Unit 3 and Unit 4.

The Connection Point for Units 1 and 2 are in the DE Karn Plant 138 kV Substation (see Wiring Diagram #695, Sheet 31 attached). The Connection Point for Units 3 and 4 are in the Hampton 345 kV Substation (see Wiring Diagram #1327, Sheet 31 attached).

The Points of Receipt for all the Units in the DE Karn Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695, Sheet 31):


Transformer Banks	Nos. 1 and 2 (located outside the substation; not included in JOA calc)

Circuit Breakers Nos. 199, 299, 799 and 899


Switches	Nos. 136A, 136B, 195, 196, 236A, 236B, 295, 296, 793, 795, 796, 893, 895, and 896


Circuit Connections	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork


Relay & Controls	All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above


Auxiliary Power	All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #695, Sheet 31

Transmission Owner’s Interconnection Assets

Transmission Owner owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695, Sheet 31):

Circuit Breakers Nos. 148, 188, 388, 488, 500, 588 and 988


Switches	Nos. 108, 144, 145, 146, 184, 185, 186, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 584, 585, 586, 709, 809, 908, 984, 985, 986, 2030 and 2131


Circuit Connections	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to adjacent buswork


Relay & Controls	All relays and controls associated with the Circuit Breakers identified above

Foundations All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Karn Plant Substation - See Exhibit B - Table 1

CEII MATERIAL

Morrow Generating Plant Complex

The Morrow Generating Plant Complex consists of two combustion turbine generating Units, known as Units A and B.

The Connection Points for both Units A and B are in the Morrow Substation (see Wiring Diagram #190, Sheet 31, attached).

The Points of Receipt for the Units in the Morrow Generating Plant Complex are deemed to be the Connection Points.

Consumers’ Interconnection Assets

Consumers’ owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet 31):


Transformer Banks	No. 1, 2, 4 and 5


Circuit Breakers	Nos. 100, 156, 166, 199, 256, 266, 299, 566, 499, 16A,16B, 599, 1077, 1188, 1388, 1488, 1588, 1688 and 1788


Switches	Nos. 102, 104, 109, 162, 164, 165, 191, 193, 195, 196, 209, 252, 262, 264, 265, 291, 293, 295, 296, 300, 509, 562, 564, 565, 591, 593, 595, 596, 1071, 1073, 1075, 1182, 1184, 1185, 1323, 1382, 1384, 1385, 1482, 1484, 1485, 1582, 1584, 1585, 1682, 1684, 1685, 1782, 1784, 1785 and 2333

Capacitors Nos. 1 and 2


Circuit Connections	All wire, cable or buswork electrically connecting the Transformers, Circuit Breakers and Switches identified above


Relay & Controls	All relays and controls associated with the Circuit Breakers identified above


Foundations	All foundations supporting the Transformers and Circuit Breakers identified above


Auxiliary Power	All 480 Volt station power assets shown in the attached Wiring Diagram #190, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet 31):

Circuit Breakers Nos. 177, 288, 377, 388, 500, 588, 677, 888 and 988


Switches	Nos. 107, 171, 173, 175, 176, 208, 282, 284, 285, 286, 307, 308, 371, 373, 375, 376, 382, 384, 385, 386, 501, 502, 503, 504, 505, 506, 508, 582, 584, 585, 586, 607, 671, 673, 675, 676, 882, 884, 885, 886, 982, 984, 985 and 986


Circuit Connections	All wire, cable or buswork electrically connecting the Circuit Breakers and Switches identified above


Relay and Controls	All relays and controls associated with the Circuit Breakers identified above


Foundations	All foundations supporting the Circuit Breakers identified above

Third Party Owned Assets

None

Jointly Owned Assets - Percentage Split by Major Equipment Count

Morrow Substation - See Exhibit B - Table 1

CEII MATERIAL

Thetford Generating Plant Complex

The Thetford Generating Plant Complex consists of nine combustion turbine generating Units, known as Units 1 through 9, respectively.

The Connection Points for Units 1 through 9 are in the Thetford Substation (see Wiring Diagram #1000, Sheet 31 attached).

The Points of Receipt for all the Thetford Units are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Thetford Substation (Wiring Diagram #1000, Sheet 31):


Transformer Banks	Nos. 5, 6-1, 6-2 and 7

Circuit Breakers Nos. 13B7, 13W8, 116, 216, 316, 416, 516, 616, 716, 816 and 916

Switches Nos. 13B1, 13B3, 13M5, 13W2, 13W4, 591, 691-1, 691-2 and 791


Circuit Connections	All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above


Relay & Controls	All relays and controls associated with the Circuit Breakers identified above


Foundations	All foundations supporting the Transformers and Circuit Breakers identified above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Thetford Substation (Wiring Diagram #1000, Sheet #31):


Transformer Banks	Nos. 3 and 4


Circuit Breakers	Nos. 6B7, 6M9, 6W8, 7B7, 7M9, 7W8, 9B7, 9M9, 9W8, 11B7, 11M9, 11W8, 27F7, 27H9, 27R8, 31F7, 31H9, 31R8, 33F7, 33H9 and 33R8


Switches	Nos. 6B1, 6B3, 6M5, 6M6, 6W2, 6W4, 7B1, 7B3, 7M5, 7M6, 7W2, 7W4, 9B1, 9B3, 9M5, 9M6, 9W2, 9W4, 11B1, 11B3, 11M5, 11M6, 11W2, 399, 499, 11W4, 27F1, 27F3, 27H5, 27H6, 27R2, 27R4, 31F1, 31F3, 31H5, 31H6, 31R2, 31R4, 33F1, 33F3, 33H5, 33H6, 33R2, 33R4 and 35R2


Circuit Connections	All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above


Relay and Controls	All relays and controls associated with the Circuit Breakers identified above


Foundations	All foundations supporting the Transformers and Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Thetford Substation - See Exhibit B - Table 1

CEII MATERIAL

EXHIBIT C

Generator Connections located in Consumers’ Distribution System

The following Units are connected indirectly to the Transmission System and do not have specific connection data listed herein.

Alcona Hydro Generating Plant, Units 1 and 2

Calkins Bridge “Allegan” Hydro Generating Plant, Units 1, 2 and 3

Cooke Hydro Generating Plant, Units 1. 2 and 3

Croton Hydro Generating Plant, Units 1, 2, 3 and 4

Five Channels Generating Plant, Units 1 and 2

Foote Hydro Generating Plant, Units 1, 2 and 3

Hodenpyl Hydro Generating Plant, Units 1 and 2

Loud Hydro Generating Plant, Units 1 and 2

Mio Hydro Generating Plant, Units 1 and 2

Rogers Hydro Generating Plant, Units 1, 2, 3 and 4

Straits Combustion Turbine Generating Unit 1

Tippy Hydro Generating Plant, Units 1, 2 and 3

Webber Hydro Generating Plant, Units 1 and 2

Consumers Energy Generator Connections Covered under Other Interconnection Agreements

The following Units are covered under their own GIAs and do not have specific connection data listed herein.

Campbell Generating Plant, Unit 3

Hardy Hydro Generating Plant, Units 1, 2 and 3

Zeeland Power Plant, Unit 1

Zeeland Power Plant, Unit 2

Jackson Generation

Ludington Units 1, 2, 3, 4, 5 and 6

Lake Winds Energy Park

Cross Winds Energy Park

EXHIBIT 31.1

CERTIFICATION PURSUANT TO SECTION 13a-14 OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Linda H. Blair, certify that:


1.	I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2016 of ITC Holdings Corp.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant ’ s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant ’ s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant ’ s internal control over financial reporting that occurred during the registrant ’ s most recent fiscal quarter (the registrant ’ s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant ’ s internal control over financial reporting; and


5.	The registrant ’ s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant ’ s auditors and the audit committee of the registrant ’ s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant ’ s ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant ’ s internal control over financial reporting.

Dated: November 4, 2016

/s/ Linda H. Blair

Linda H. Blair

President and Chief Executive Officer

EXHIBIT 31.2

CERTIFICATION PURSUANT TO SECTION 13a-14 OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Gretchen L. Holloway, certify that:


1.	I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2016 of ITC Holdings Corp.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant ’ s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c.	Evaluated the effectiveness of the registrant ’ s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d.	Disclosed in this report any change in the registrant ’ s internal control over financial reporting that occurred during the registrant ’ s most recent fiscal quarter (the registrant ’ s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant ’ s internal control over financial reporting; and


5.	The registrant ’ s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant ’ s auditors and the audit committee of the registrant ’ s board of directors (or persons performing the equivalent functions):


a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant ’ s ability to record, process, summarize and report financial information; and


b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant ’ s internal control over financial reporting.

Dated: November 4, 2016

/s/ Gretchen L. Holloway

Gretchen L. Holloway

Vice President, Chief Financial Officer and Treasurer

EXHIBIT 32

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of ITC Holdings Corp. (the “Registrant”) on Form 10-Q for the quarterly period ended September 30, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Linda H. Blair, President and Chief Executive Officer of the Registrant, and Gretchen L. Holloway, Vice President, Chief Financial Officer and Treasurer of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Dated: November 4, 2016

/s/ Linda H. Blair

Linda H. Blair

President and Chief Executive Officer

/s/ Gretchen L. Holloway

Gretchen L. Holloway
Vice President, Chief Financial Officer and Treasurer