10-Q

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 March 31, 2013

OR

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):

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller Reporting Company o
		(Do not check if a smaller reporting company)

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

The number of shares of the Registrant’s Common Stock, without par value, outstanding as of April 19, 2013 was 52,332,830.

ITC Holdings Corp.

Form 10-Q for the Quarterly Period Ended March 31, 2013

INDEX

	Page
Part I. Financial Information	4
Item 1. Financial Statements	4
Condensed Consolidated Statements of Financial Position (Unaudited)	4
Condensed Consolidated Statements of Operations (Unaudited)	5
Condensed Consolidated Statements of Comprehensive Income (Unaudited)	6
Condensed Consolidated Statements of Cash Flows (Unaudited)	7
Notes to Condensed Consolidated Financial Statements (Unaudited)	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 3. Quantitative and Qualitative Disclosures About Market Risk	31
Item 4. Controls and Procedures	32
Part II. Other Information	32
Item 1A. Risk Factors	32
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds	33
Item 6. Exhibits	34
Signatures	35
Exhibit Index

2

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;

• “Green Power Express” are references to Green Power Express LP, an indirect wholly-owned subsidiary of ITC Holdings;

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

• “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;

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

• “Entergy” are references to Entergy Corporation;

• “Entergy Transaction” are references to the transaction whereby the electric transmission business of Entergy will be separated and subsequently merged with a wholly-owned subsidiary of ITC Holdings;

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

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

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

• “ITC Holdings’ annual report on Form 10-K” are references to the annual report on Form 10-K filed on March 1, 2013;

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

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

• “MISO” are references to the Midwest Independent Transmission 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;

• “MW” are references to megawatts (one megawatt equaling 1,000,000 watts);

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

• “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.

3

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

	March 31,			December 31,
(in thousands, except share data)	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	67,582		$	26,187
Accounts receivable	78,412			72,192
Inventory	37,092			37,357
Deferred income taxes	21,094			23,014
Regulatory assets — revenue accruals, including accrued interest	6,310			7,489
Prepaid assets	18,367			29,235
Other	5,179			2,752
Total current assets	234,036			198,226
Property, plant and equipment (net of accumulated depreciation and amortization of $1,289,769 and $1,269,810, respectively)	4,317,746			4,134,579
Other assets
Goodwill	950,163			950,163
Intangible assets (net of accumulated amortization of $19,188 and $18,397, respectively)	47,701			48,492
Regulatory assets — revenue accruals, including accrued interest	14,594			2,719
Other regulatory assets	181,797			180,378
Deferred financing fees (net of accumulated amortization of $18,742 and $17,838, respectively)	18,721			19,293
Other	30,729			30,959
Total other assets	1,243,705			1,232,004
TOTAL ASSETS	$	5,795,487		$	5,564,809
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	109,646		$	123,022
Accrued payroll	10,174			20,740
Accrued interest	44,722			44,708
Accrued taxes	23,221			28,117
Regulatory liabilities — revenue deferrals, including accrued interest	47,736			53,763
Refundable deposits from generators for transmission network upgrades	30,083			40,745
Debt maturing within one year	901,962			651,929
Other	38,408			40,287
Total current liabilities	1,205,952			1,003,311
Accrued pension and postretirement liabilities	55,349			53,243
Deferred income taxes	484,577			460,072
Regulatory liabilities — revenue deferrals, including accrued interest	33,479			28,613
Regulatory liabilities — accrued asset removal costs	74,549			75,477
Refundable deposits from generators for transmission network upgrades	6,019			7,623
Other	23,088			26,317
Long-term debt	2,458,881			2,495,298
Commitments and contingent liabilities (Note 10)
STOCKHOLDERS’ EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,317,093 and 52,248,514 shares issued and outstanding at March 31, 2013 and December 31, 2012, respectively	995,509			989,334
Retained earnings	474,026			443,569
Accumulated other comprehensive loss	(15,942		)	(18,048		)
Total stockholders’ equity	1,453,593			1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	5,795,487		$	5,564,809

See notes to condensed consolidated financial statements (unaudited).

4

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three months ended
	March 31,
(in thousands, except per share data)	2013			2012
OPERATING REVENUES	$	217,304		$	196,713
OPERATING EXPENSES
Operation and maintenance	24,513			28,712
General and administrative	34,926			23,009
Depreciation and amortization	28,486			25,011
Taxes other than income taxes	16,670			14,280
Other operating (income) and expense — net	(172		)	(193		)
Total operating expenses	104,423			90,819
OPERATING INCOME	112,881			105,894
OTHER EXPENSES (INCOME)
Interest expense	39,063			37,910
Allowance for equity funds used during construction	(8,733		)	(5,624		)
Other income	(236		)	(306		)
Other expense	1,037			831
Total other expenses (income)	31,131			32,811
INCOME BEFORE INCOME TAXES	81,750			73,083
INCOME TAX PROVISION	31,560			27,032
NET INCOME	$	50,190		$	46,051
Basic earnings per common share	$	0.96		$	0.90
Diluted earnings per common share	$	0.95		$	0.88
Dividends declared per common share	$	0.3775		$	0.3525

See notes to condensed consolidated financial statements (unaudited).

5

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

	Three months ended
	March 31,
(in thousands)	2013		2012
NET INCOME	$	50,190	$	46,051
OTHER COMPREHENSIVE INCOME
Amortization of interest rate lock cash flow hedges (net of tax of $10 and $9, respectively)	14		15
Unrealized gain on interest rate swaps relating to interest rate cash flow hedges (net of tax of $1,365 and $1,803, respectively)	2,092		2,812
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAX	2,106		2,827
TOTAL COMPREHENSIVE INCOME	$	52,296	$	48,878

See notes to condensed consolidated financial statements (unaudited).

6

ITC HOLDINGS CORP. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three months ended
	March 31,
(in thousands)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	50,190		$	46,051
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	28,486			25,011
Recognition, refund and collection of revenue accruals and deferrals — including accrued interest	(11,857		)	(16,779		)
Deferred income tax expense	21,329			16,191
Allowance for equity funds used during construction	(8,733		)	(5,624		)
Other	3,992			2,974
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(4,341		)	1,232
Inventory	265			1,771
Prepaid and other current assets	10,857			(4,421		)
Accounts payable	(5,193		)	(4,840		)
Accrued payroll	(7,040		)	(6,726		)
Accrued interest	14			(19,448		)
Accrued taxes	(4,896		)	(6,505		)
Other current liabilities	(839		)	(3,641		)
Other non-current assets and liabilities, net	(266		)	4,429
Net cash provided by operating activities	71,968			29,675
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(214,111		)	(224,079		)
Other	(103		)	(50		)
Net cash used in investing activities	(214,214		)	(224,129		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	—			100,000
Borrowings under revolving credit agreements	369,500			342,250
Borrowings under term loan credit agreements	250,000			—
Repayments of revolving credit agreements	(406,000		)	(268,500		)
Issuance of common stock	2,632			1,050
Dividends on common and restricted stock	(19,733		)	(18,101		)
Refundable deposits from generators for transmission network upgrades	8,058			9,636
Repayment of refundable deposits from generators for transmission network upgrades	(20,325		)	(5,661		)
Other	(491		)	(1,512		)
Net cash provided by financing activities	183,641			159,162
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	41,395			(35,292		)
CASH AND CASH EQUIVALENTS — Beginning of period	26,187			58,344
CASH AND CASH EQUIVALENTS — End of period	$	67,582		$	23,052

See notes to condensed consolidated financial statements (unaudited).

7

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, 2012 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

	Three months ended
	March 31,
(in thousands)	2013		2012
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	38,144	$	56,262
Income taxes paid	1,100		9,324
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment (a)	$	79,933	$	78,252
Allowance for equity funds used during construction	8,733		5,624

____________________________

(a) Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of March 31, 2013 or 2012, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

2.    RECENT ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income

The guidance set forth by the Financial Accounting Standards Board (“FASB”) has been updated for the presentation of comprehensive income in financial statements. Under this guidance, we are required to (1) disclose the changes in accumulated other comprehensive income (“AOCI”) by component and (2) disclose the effects on the line items of net income of significant amounts reclassified out of AOCI. We adopted this guidance as of January 1, 2013. For the three months ended March 31, 2013, the requirements under (1) above are presented in the condensed consolidated statements of comprehensive income, however, there were no significant amounts reclassified out of AOCI that would require disclosure.

Balance Sheet Offsetting Requirements

The FASB has created new disclosure requirements regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires entities to disclose, at a minimum, the following information in tabular format, separately for assets and liabilities: (a) the gross amounts of those recognized assets and those recognized liabilities; (b) the amounts offset to determine the net amounts presented in the statement of financial position; (c) the net amounts presented in the statement of financial position; (d) the amounts subject to an enforceable master netting arrangement or similar agreement; and (e) the net amount after deducting the amounts in (d) from the amounts in (c). We adopted this guidance as of January 1, 2013. As of March 31, 2013, we did not have any material assets and liabilities that are subject to the new disclosure requirements.

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3.    REGULATORY MATTERS

ITC Great Plains

As of March 31, 2013, we have recorded a total of $14.1 million of regulatory assets for start-up and development expenses incurred by ITC Great Plains, which include certain costs incurred for the Kansas Electric Transmission Authority (“KETA”) Project and the Kansas V-Plan Project prior to construction. Based on ITC Great Plains’ FERC application under which authority to recognize these regulatory assets was sought and the related FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the FPA in order to recover these start-up, development and pre-construction expenses in future rates. If FERC authorization to recover these costs is received, ITC Great Plains will include the balance of the regulatory assets in its rate base and will amortize them over a 10-year period beginning at the later of the project in-service date or the FERC authorization date. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template beginning in the period in which amortization begins.

Order on Formula Rate Protocols

On May 17, 2012, the FERC issued an order pursuant to Section 206 of the FPA to determine whether the formula rate protocols under the MISO Tariff are sufficient to ensure just and reasonable rates. The MISO Regulated Operating Subsidiaries were named in the order. We do not expect the resolution of this proceeding and its ultimate impact on our MISO Regulated Operating Subsidiaries’ formula rates will be material to our results of operations, cash flows or financial condition.

Complaint of IP&L

On September 14, 2012, IP&L filed a complaint with the FERC against ITC Midwest’s reimbursement policy under Section 206 of the Federal Power Act. The complaint challenges ITC Midwest’s FERC approved reimbursement policy for network upgrades to qualifying generators. IP&L requests that the FERC (1) investigate the justness and reasonableness of ITC Midwest’s Attachment FF policy; (2) establish a refund effective date of September 14, 2012; and (3) establish hearing procedures. On October 4, 2012, ITC Midwest filed an answer to the complaint with the FERC outlining the reasons ITC Midwest’s Attachment FF provision remains just and reasonable and requesting dismissal of the complaint.

Cost-Based Formula Rates with True-Up Mechanism

The transmission rates at our Regulated Operating Subsidiaries are set annually, using the FERC-approved formula rates, and the rates 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 adjust their transmission rates 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 FERC-approved formula rates do not require further action or FERC filings for the calculated joint zone rates to go into effect, although the rates are subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use formula rates to calculate their respective annual revenue requirements unless the FERC determines the rates to be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable.

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 requirements. The over- or under-collection typically results from differences between the projected revenue requirement used to establish the billing rate 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. 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 customer bills within two years under the provisions of the formula rate templates.

9

The current and non-current regulatory assets are recorded on the balance sheet in regulatory assets revenue accruals, including accrued interest. The current and non-current regulatory liabilities are recorded in regulatory liabilities revenue deferrals, including accrued interest. The changes in regulatory assets and liabilities (net) associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the three months endedMarch 31, 2013:

(in thousands)	Total
Balance as of December 31, 2012	$	(72,168	)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	11,766
Net revenue accrual for the three months ended March 31, 2013	687
Net accrued interest payable for the three months ended March 31, 2013	(596		)
Balance as of March 31, 2013	$	(60,311	)

Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals are recorded in our condensed consolidated statement of financial position as follows:

(in thousands)	Total
Current assets	$	6,310
Non-current assets	14,594
Current liabilities	(47,736		)
Non-current liabilities	(33,479		)
Balance as of March 31, 2013	$	(60,311	)

4.    INTANGIBLE ASSETS

We have recorded intangible assets as a result of the METC acquisition in 2006. The carrying value of these assets was $39.5 million (net of accumulated amortization of $18.9 million) as of March 31, 2013.

We have also recorded intangible assets for payments made by ITC Great Plains to certain transmission owners 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 $8.2 million (net of accumulated amortization of $0.3 million) as of March 31, 2013.

During the three months endedMarch 31, 2013 and 2012, we recognized $0.8 million of amortization expense of our intangible assets. For each of the next five years, we expect the annual amortization of our intangible assets that have been recorded as of March 31, 2013 to be $3.2 million per year.

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5.    DEBT

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. The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuances of fixed-rate debt related to (1) the expected refinancing of the $267.0 million ITC Holdings 5.25% Senior Notes, due July 15, 2013, prior to its maturity and (2) the expected financing required to repay the $200.0 million and $250.0 million borrowed under the existing ITC Holdings unsecured, unguaranteed term loan credit agreements, due August 23, 2013 and December 31, 2013, respectively, prior to their maturity:

Interest Rate Swaps	Notional Amount		Fixed Rate	Original Term	Effective Date
(amounts in millions)
September 2010 swap	$	50.0	3.60%	10 years	July 2013
March 2011 swaps	50.0		4.45%	10 years	July 2013
May 2011 swap	25.0		4.20%	10 years	July 2013
August 2011 swaps	50.0		3.80%	10 years	July 2013
November 2012 swap	25.0		2.60%	30 years	June 2013
December 2012 swap	25.0		2.58%	30 years	June 2013
February 2013 swap	25.0		2.98%	30 years	June 2013
February 2013 swap	25.0		2.93%	30 years	June 2013
Total	$	275.0

The 10 year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 10-year period beginning July 15, 2013 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 July 15, 2013. The 30 year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 30-year period beginning June 15, 2013 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 July 15, 2013 and June 15, 2013 for the 10- and 30-year swaps, respectively. 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 debt issuance attributable to changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation. In April 2013, we entered into additional interest rate swap contracts with terms that are comparable to the interest rate swaps described above, consisting of an additional $75.0 million notional amount of 10-year term interest rate swaps with a weighted average fixed rate of 3.37% and $125.0 million notional amount of 30-year term interest rate swaps with a weighted average fixed rate of 2.82%.

As of March 31, 2013, there has been no material ineffectiveness recorded in the condensed consolidated statement of operations. The interest rate swaps qualify for 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. These amounts will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. As of March 31, 2013, the fair value of the derivative instruments was an asset of $5.1 million recorded to other current assets and a liability of $30.5 million recorded to other current liabilities. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 9 for additional fair value information.

ITC Holdings

On August 23, 2012, ITC Holdings entered into a new unsecured, unguaranteed term loan credit agreement (“2012 Term Loan”), under which ITC Holdings had borrowed $200.0 million as of March 31, 2013 and as of December 31, 2012. On February 15, 2013, ITC Holdings entered into a new unsecured, unguaranteed term loan credit agreement with a borrowing capacity of $250.0 million (“2013 Term Loan”), under which ITC Holdings borrowed $250.0 million as of March 31, 2013. The proceeds from each term loan were used for general corporate purposes, including the repayment of borrowings under the ITC Holdings’ revolving credit agreement. The 2012 Term Loan and the 2013 Term Loan are scheduled to mature on August 23, 2013 and December 31, 2013, respectively. The weighted-average interest rate on the borrowings outstanding under the term loans was 1.2% at March 31, 2013.

11

ITC Midwest

On April 4, 2013, ITC Midwest issued $100.0 million aggregate principal amount of 4.09% First Mortgage Bonds, Series F, due 2043. The proceeds from the issuance were used to refinance existing indebtedness, partially fund capital expenditures and for general corporate purposes. All of ITC Midwest’s First Mortgage Bonds are issued under its First Mortgage and Deed of Trust, and therefore have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.

Revolving Credit Agreements

At March 31, 2013, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available, each of which bears interest at a variable rate based on the prime rate or LIBOR (subject to adjustment based on credit rating):

(amounts in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity		Weighted-Average Interest Rate on Outstanding Balance	Commitment Fee Rate (b)		Original Term	Date of Maturity
Revolving Credit Agreements:
ITC Holdings	$	200.0	$	—	$	200.0	n/a	0.25	%	5 years	May 2016
ITCTransmission	100.0		2.5		97.5		1.4%	0.125	%	5 years	May 2016
METC	100.0		31.3		68.7		1.3%	0.125	%	5 years	May 2016
ITC Midwest	175.0		146.2		28.8		1.2%	0.10	%	5 years	May 2017
ITC Great Plains	150.0		111.3		38.7		2.0%	0.30	%	4 years	February 2015
Total	$	725.0	$	291.3	$	433.7

____________________________

(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.

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. We are currently in compliance with all debt covenants.

6.     STOCKHOLDERS’ EQUITY

ITC Holdings Sales Agency Financing Agreement

On July 27, 2011, ITC Holdings entered into a Sales Agency Financing Agreement with Deutsche Bank Securities Inc. as sales agent (the “SAFA”). Under the terms of the SAFA, ITC Holdings may issue and sell shares of common stock, without par value, from time to time, up to an aggregate sales proceeds amount of $250.0 million. The SAFA terminates in July 2014, although the agreements relating to the Entergy Transaction generally prohibit us from issuing shares under the SAFA until approximately two years after the closing except under certain limited circumstances. The shares of common stock may be offered in one or more selling periods. Any shares of common stock sold under the SAFA will be offered at market prices prevailing at the time of sale. Moreover, ITC Holdings will specify to the sales agent (i) the aggregate selling price of the shares of common stock to be sold during each selling period, and (ii) the minimum price below which sales may not be made. ITC Holdings will pay a commission equal to a mutually agreed upon rate with its agent, not to exceed 2% of the sales price of all shares of common stock sold through its agent under the SAFA, plus expenses. The shares we would issue under the SAFA have been registered under ITC Holdings’ shelf registration statement on Form S-3 (File No. 333-187994) filed on April 18, 2013 with the SEC. No shares have been issued under the SAFA.

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7.    EARNINGS PER SHARE

We report both basic and diluted earnings per share. Our restricted stock and deferred stock units contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing earnings per share. A reconciliation of both calculations for the three months endedMarch 31, 2013 and 2012 is presented in the following table:

	Three months ended
	March 31,
(in thousands, except share, per share data and percentages)	2013			2012
Numerator:
Net income	$	50,190		$	46,051
Less: dividends declared — common shares and restricted shares	(19,733		)	(18,101		)
Undistributed earnings	30,457			27,950
Percentage allocated to common shares (a)	99.0		%	98.6		%
Undistributed earnings — common shares	30,152			27,559
Add: dividends declared — common shares	19,537			17,851
Numerator for basic and diluted earnings per common share	$	49,689		$	45,410
Denominator:
Denominator for basic earnings per common share — weighted-average common shares	51,756,765			50,636,200
Incremental shares for stock options and employee stock purchase plan	378,406			768,834
Denominator for diluted earnings per common share — adjusted weighted-average shares and assumed conversion	52,135,171			51,405,034
Per common share net income:
Basic	$	0.96		$	0.90
Diluted	$	0.95		$	0.88

____________________________

(a)	Weighted-average common shares outstanding	51,756,765		50,636,200
	Weighted-average restricted shares (participating securities)	519,996		709,091
	Total	52,276,761		51,345,291
	Percentage allocated to common shares	99.0	%	98.6	%

The incremental shares for stock options and the employee stock purchase plan (“stock options and ESPP shares”) are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including them would be anti-dilutive. The outstanding stock options and ESPP shares as of March 31, 2013 and 2012 and the anti-dilutive stock options and ESPP shares excluded from the diluted earnings per share calculations for the three months endedMarch 31, 2013 and 2012 were as follows:

	2013	2012
Outstanding stock options and ESPP shares	1,549,860	2,066,083
Anti-dilutive stock options and ESPP shares	356,730	214,993

8.    RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Retirement Plan Benefits

We have a qualified 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 the employees’ 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. While we are obligated to fund the retirement plan by contributing the minimum amount required by the Employee Retirement Income Security Act of 1974, as amended, it is our practice to contribute the maximum allowable amount as defined by section 404 of the Internal Revenue Code. We expect to contribute up to $6.9 million to the defined benefit retirement plan in 2013.

We also have two supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. The plans provide for benefits that supplement those provided by our other retirement plans. We expect to contribute up to $0.6 million to these supplemental nonqualified, noncontributory, retirement benefit plans in 2013.

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Net pension cost includes the following components:

	Three months ended
	March 31,
(in thousands)	2013			2012
Service cost	$	1,315		$	1,040
Interest cost	763			647
Expected return on plan assets	(717		)	(570		)
Amortization of prior service cost	(10		)	(10		)
Amortization of unrecognized loss	679			868
Net pension cost	$	2,030		$	1,975

Other Postretirement Benefits

We provide certain postretirement health care, dental, and life insurance benefits for employees who may become eligible for these benefits. We expect to contribute up to $3.8 million to the postretirement benefit plan in 2013.

Net postretirement cost includes the following components:

	Three months ended
	March 31,
(in thousands)	2013			2012
Service cost	$	1,443		$	1,358
Interest cost	390			388
Expected return on plan assets	(353		)	(254		)
Amortization of prior service cost	—			31
Amortization of unrecognized loss	55			134
Net postretirement cost	$	1,535		$	1,657

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 $1.7 million and $1.3 million for the three months endedMarch 31, 2013 and 2012, respectively.

9.    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.

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at March 31, 2013, 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	$	35,935	$	30,243		$	—
Mutual funds — fixed income securities	21,113		—			—
Mutual funds — equity securities	1,766		—			—
Interest rate swap derivatives	—		5,142			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(30,468		)	—
Total	$	58,814	$	4,917		$	—

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Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2012, 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	$	13,127	$	10,037		$	—
Mutual funds — fixed income securities	21,332		—			—
Mutual funds — equity securities	1,612		—			—
Interest rate swap derivatives	—		2,725			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(31,507		)	—
Total	$	36,071	$	(18,745	)	$	—

As of March 31, 2013 and December 31, 2012, we held certain assets and liabilities that are required to be measured at fair value on a recurring basis.

The assets 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 that are classified as trading securities. Our Level 1 investments included in cash equivalents consist of money market mutual funds and common and collective trusts that are administered similar to money market funds recorded at cost plus accrued interest to approximate fair value. Our mutual funds consist primarily of publicly traded mutual funds for which market prices are readily available. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost. The cash and cash equivalents that are classified as a Level 2 investment consist of deposits held with financial institutions that are then invested by the financial institution in money market mutual funds and common and collective trusts that are administered similar to money market funds. The underlying money market funds and common and collective trusts are recorded at cost plus accrued interest.

The assets and liabilities related to derivatives consist of interest rate swaps discussed in Note 5. The fair value of our interest rate swap derivatives as of March 31, 2013 and December 31, 2012 is determined based on a discounted cash flow 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 three months endedMarch 31, 2013. 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 endedDecember 31, 2012 included in our Form 10-K for such period and to Note 4 of this Form 10-Q.

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, was $3,034.8 million and $3,072.9 million at March 31, 2013 and December 31, 2012, respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $2,619.5 million and $2,619.4 million at March 31, 2013 and December 31, 2012, respectively.

Revolving and Term Loan Credit Agreements

At March 31, 2013 and December 31, 2012, we had a consolidated total of $741.3 million and $527.8 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.

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10.    COMMITMENTS AND CONTINGENT LIABILITIES

Environmental Matters

Our Regulated Operating Subsidiaries’ operations 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 hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate 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 at properties currently owned or operated by our Regulated Operating Subsidiaries. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of 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 Regulated Operating Subsidiaries’ 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 Regulated Operating Subsidiaries’ assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties our Regulated Operating Subsidiaries 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 PCBs. Our Regulated Operating Subsidiaries’ facilities and equipment are often situated close to or on property owned by others so that, if they are the source of contamination, other’s property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that our Regulated Operating Subsidiaries do not own, and, at some of our Regulated Operating Subsidiaries’ transmission stations, transmission assets (owned or operated by our Regulated Operating Subsidiaries) and distribution assets (owned or operated by our Regulated Operating Subsidiaries’ transmission customer) are commingled.

Some properties in which our Regulated Operating Subsidiaries have an ownership interest or at which they operate are, and others are suspected of being, affected by environmental contamination. Our Regulated Operating Subsidiaries are not aware of any pending or threatened claims against them with respect to environmental contamination, or of any investigation or remediation of contamination at any properties, that entail costs likely to materially affect them. Some facilities and properties are located near environmentally sensitive areas such as wetlands.

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 our Regulated Operating Subsidiaries do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, if such a relationship is established or accepted, the liabilities and costs imposed on our business could be significant. We are not aware of any pending or threatened claims against our Regulated Operating Subsidiaries 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, 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. The resolution of pending proceedings is not expected to have a material effect on our operations or consolidated financial statements in the period in which they are resolved.

Michigan Sales and Use Tax Audit

The Michigan Department of Treasury conducted a sales and use tax audit of ITCTransmission for the audit period April 1, 2005 through June 30, 2008 and has denied ITCTransmission’s use of the industrial processing exemption from use tax it has taken beginning January 1, 2007. ITCTransmission has certain administrative and judicial appeal rights.

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ITCTransmission believes that its utilization of the industrial processing exemption is appropriate and intends to defend itself against the denial of such exemption. However, it is reasonably possible that the assessment of additional use tax could be sustained after all administrative appeals and litigation have been exhausted.

The amount of use tax liability associated with the exemptions taken by ITCTransmission through March 31, 2013 is estimated to be approximately $15.6 million, which includes approximately $3.7 million assessed for the audit period April 1, 2005 through June 30, 2008, including interest. In the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission 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. METC has also taken the industrial processing exemption, estimated to be approximately $11.0 million for periods still subject to audit since 2006. These higher use tax expenses would be passed on to ITCTransmission’s and METC’s customers as the amounts are included as components of net revenue requirements and resulting rates.

FERC Audit of ITC Midwest

Certain staff of the FERC (“FERC audit staff”) have conducted an audit of ITC Midwest’s compliance with certain of the FERC’s regulations and the conditions established in the 2007 FERC order approving the acquisition of the transmission assets of Interstate Power and Light Company by ITC Midwest. In 2011, the FERC issued an order that identified certain findings and recommendations of FERC audit staff relating to specific aspects of the accounting treatment for the acquisition that requires adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. In 2012, ITC Midwest filed a refund report with the FERC which included adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. On January 30, 2013, the FERC accepted ITC Midwest’s refund report which included the amount expected to be refunded in 2014.

ITCTransmission and METC have applied an accounting treatment for their respective acquisitions similar to ITC Midwest, and on February 1, 2013, voluntarily filed compliance plans with FERC to address the findings raised with respect to the ITC Midwest audit, which includes the amount expected to be refunded in 2014.

As a result of the FERC order, ITC Midwest, ITCTransmission and METC have recorded an aggregate estimated liability for the refund and related interest of $12.8 million as of March 31, 2013 in the condensed consolidated statements of financial position. The refund amounts are limited to 2010 and earlier periods. The ITCTransmission and METC compliance plans and refund reports remain subject to FERC acceptance, however, we do not believe the ultimate resolution of this matter will differ materially from the estimates recorded during 2012.

ITC Midwest Project Commitment

In the Minnesota regulatory proceeding to approve ITC Midwest’s December 2007 acquisition of the transmission assets of IP&L, ITC Midwest agreed to build a certain project in Iowa, the 345 kV Salem-Hazelton line, and made a commitment to use commercially reasonable best efforts to complete the project prior to December 31, 2011. In the event ITC Midwest is found to have failed to meet this commitment, the allowed 12.38% rate of return on the actual equity portion of its capital structure would be reduced to 10.39% until such time as ITC Midwest completes the project, and ITC Midwest would refund with interest any amounts collected since the close date of the transaction that exceeded what would have been collected if the 10.39% return on equity had been used. Certain regulatory approvals were needed from the Iowa Utilities Board (“IUB”) before construction of the project could commence, but due to the IUB’s case schedule, these approvals were not received until the second quarter of 2011. As a result of the delay in the receipt of the necessary regulatory approvals, the project was not completed by December 31, 2011. The Minnesota Public Utilities Commission is monitoring the status of the project, and ITC Midwest is providing it with periodic status updates about the project and other information about transmission system conditions, as requested in a May 15, 2012 Order. We believe we used commercially reasonable best efforts to meet the December 31, 2011 deadline and will continue to pursue completion of the project using our commercially reasonable best efforts. Therefore, we believe the likelihood of any material effect from this matter is remote.

11.    ENTERGY TRANSACTION

As of December 4, 2011, Entergy and ITC Holdings executed definitive agreements (as subsequently amended, the “transaction agreements”) under which Entergy will divest and then merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings (“Entergy Transaction”). Entergy’s electric transmission business consists of approximately 15,400 miles of interconnected transmission lines at voltages of 69 kV and above and associated substations across its utility service territory in the Mid-South.

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The terms of the transaction agreements call for Entergy to divest its electric transmission business to a newly-formed entity, Mid South TransCo LLC (“Mid South TransCo”), and Mid South TransCo’s subsidiaries, and distribute the equity interests in Mid South TransCo to Entergy’s shareholders in the form of a tax-free spin-off. Mid South TransCo will then merge with a newly-created merger subsidiary of ITC Holdings in an all-stock, Reverse Morris Trust transaction, and will survive the merger as a wholly-owned subsidiary of ITC Holdings. Prior to the merger, we expect to effectuate a recapitalization, which may take the form of a one-time special dividend to ITC Holdings’ pre-merger shareholders, a repurchase of ITC Holdings common stock from its shareholders, or a combination of a special dividend and share repurchase. The merger will result in shareholders of Entergy receiving approximately 50.1% of the shares of pro forma ITC Holdings in exchange for their shares of Mid South TransCo, with existing shareholders of ITC Holdings owning the remaining approximately 49.9% of the combined company. In addition, Entergy will receive gross cash proceeds of $1.775 billion from indebtedness that will be incurred by Mid South TransCo and its subsidiaries prior to the merger and assumed under the acquisition. On April 16, 2013, ITC Holdings received the necessary shareholder approvals to consummate the merger. Completion of the transaction is expected in 2013 subject to the satisfaction of certain closing conditions, including the receipt of necessary approvals of Entergy’s retail regulators and the FERC.

For the three months endedMarch 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $8.7 million and $2.4 million, respectively, and certain internal labor and related costs of approximately $2.3 million and $1.5 million, respectively, related to the Entergy Transaction recorded primarily within general and administrative expenses. The external and internal costs related to the Entergy Transaction are not included as components of revenue requirement at our Regulated Operating Subsidiaries as they were incurred at ITC Holdings.

Per the transaction agreements, prior to completion of the Entergy Transaction, there are certain restrictions on our ability to pay dividends other than those paid in the ordinary course of business with record dates and payment dates consistent with our past practice and, if elected, a one-time special dividend to ITC Holdings’ pre-merger shareholders in accordance with the transaction agreements. Management does not expect the restrictions to have an impact on our ability to pay dividends at the current level in the foreseeable future.

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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. The following tables show our financial information by reportable segment:

	Three months ended
OPERATING REVENUES:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	217,379		$	196,733
ITC Holdings and other	152			152
Intercompany eliminations	(227		)	(172		)
Total Operating Revenues	$	217,304		$	196,713

	Three months ended
INCOME BEFORE INCOME TAXES:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	119,260		$	100,924
ITC Holdings and other	(37,510		)	(27,841		)
Total Income Before Income Taxes	$	81,750		$	73,083

	Three months ended
NET INCOME:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	73,756		$	62,475
ITC Holdings and other	50,190			46,051
Intercompany eliminations	(73,756		)	(62,475		)
Total Net Income	$	50,190		$	46,051

TOTAL ASSETS:	March 31,			December 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	5,536,371		$	5,440,401
ITC Holdings and other	3,500,265			3,252,047
Reconciliations / Intercompany Eliminations (a)	(3,241,149		)	(3,127,639		)
Total Assets	$	5,795,487		$	5,564,809

____________________________

(a) Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our Regulated Operating Subsidiaries 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 and the outlook for our business and the electric transmission industry 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” and similar phrases. These forward-looking statements are based upon assumptions our management believes are reasonable. Such forward-looking statements are subject to 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 fiscal year endedDecember 31, 2012, and the following:

• Certain elements of our Regulated Operating Subsidiaries’ cost recovery through rates can be 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. We have also made certain commitments to federal and state regulators with respect to, among other things, our rates in connection with acquisitions that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

• Our Regulated Operating Subsidiaries’ actual capital expenditures may be lower than planned, which would decrease expected rate base and therefore our expected revenues and earnings. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot assure you that we will be able to initiate or complete any of these investments.

• 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 federal 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 Regulated Operating Subsidiaries’ assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, our Regulated Operating Subsidiaries 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.

• Our Regulated Operating Subsidiaries contract with third parties to provide services for certain aspects of their businesses. If any of these agreements are terminated, our Regulated Operating Subsidiaries 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 Regulated Operating Subsidiaries’ operations or the imposition of civil or criminal penalties.

• Our Regulated Operating Subsidiaries are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.

• Our Regulated Operating Subsidiaries 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.

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• Acts of war, terrorist attacks and threats, including cyber attacks or threats, or the escalation of military activity in response to such attacks or otherwise may negatively affect our business, financial condition, results of operations and cash flows.

• 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 pay dividends and fulfill our other cash obligations.

• We are highly leveraged and our dependence on debt may limit our ability to fulfill our debt obligations and/or to obtain additional financing.

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

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

• Provisions in our Articles of Incorporation and bylaws, Michigan corporate law and our debt agreements may impede efforts by our shareholders to change the direction or management of our company.

• Provisions in our Articles of Incorporation restrict market participants from voting or owning 5% or more of the outstanding shares of our capital stock.

• We may be unable to satisfy the conditions or obtain the approvals required to complete the Entergy Transaction or such approvals may contain material restrictions or conditions.

• If completed, the Entergy Transaction may not be successful or achieve its anticipated benefits.

• The merger agreement contains provisions that may discourage other companies from trying to acquire us.

• Failure to complete the Entergy Transaction could adversely affect the market price of ITC Holdings common stock as well as our business, financial condition, results of operations and cash flows.

• Investors holding shares of ITC Holdings common stock immediately prior to the completion of the Entergy Transaction will, in the aggregate, have a significantly reduced ownership and voting interest in us after the Entergy Transaction and will exercise less influence over management.

• After the completion of the merger, sales of ITC Holdings common stock may negatively affect its market price.

• We are required to abide by potentially significant restrictions which could limit our ability to undertake certain corporate actions (such as the issuance of ITC Holdings common stock or the undertaking of a merger or consolidation) that otherwise could be advantageous.

Because our forward-looking statements are based on estimates and assumptions that are subject to significant business, economic and competitive uncertainties, many of which are beyond our control or are subject to change, actual results could be materially different and any or all of our forward-looking statements may turn out to be wrong. 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, 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, to reduce transmission constraints and to 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 also intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.

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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 3 to the condensed consolidated financial statements under “— Cost-Based Formula Rates 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 Detroit Edison, Consumers Energy and IP&L, and to other entities such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers and 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 three months endedMarch 31, 2013 or may affect future results include:

• Our capital investment of $212.0 million at our Regulated Operating Subsidiaries for the three months endedMarch 31, 2013, resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;

• Debt issuances and borrowings under our revolving and term loan credit agreements in 2013 and 2012 to fund capital investment at our Regulated Operating Subsidiaries, resulting in higher interest expense;

• Debt maturing within one year of $902.0 million and the resulting additional financing required; and

• The proposed transaction with Entergy in which Entergy will divest and merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings (“Entergy Transaction”) as discussed below under “Capital Project Updates and Other Recent Developments.” For the three months endedMarch 31, 2013, we expensed external legal, advisory and financial services fees of $8.7 million and certain internal labor costs of approximately $2.3 million, related to the Entergy Transaction recorded within general and administrative expenses. Certain amounts of the external costs are not expected to be deductible for income tax purposes. The external and internal costs related to the Entergy Transaction are not included as components of revenue requirement as they were incurred at ITC Holdings. The transaction fees are expected to continue to be significant until the transaction is consummated. Completion of the transaction is anticipated to occur in 2013.

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

Thumb Loop Project

The Thumb Loop Project is located in ITCTransmission’s region and consists of a 140-mile, double-circuit 345 kV transmission line and related substations that will serve 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. Construction activities commenced for the Thumb Loop Project in 2012. Through March 31, 2013, ITCTransmission has invested $213.1 million in the Thumb Loop Project. We estimate ITCTransmission will invest a total of approximately $510 million to complete construction of the project.

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ITC Great Plains

Kansas V-Plan Project

The Kansas V-Plan Project is a 200-mile long transmission line that will run between Spearville and Wichita, Kansas. ITC Great Plains is responsible for constructing an approximately 120-mile portion of the project from Spearville to Medicine Lodge, Kansas. ITC Great Plains commenced construction during 2012, and through March 31, 2013, ITC Great Plains has invested $70.3 million in the Kansas V-Plan Project. We estimate that ITC Great Plains will invest a total of approximately $300 million to complete construction of its portion of the project.

Regulatory Assets

As of March 31, 2013, we have recorded a total of $14.1 million of regulatory assets for start-up and development expenses incurred by ITC Great Plains, which include certain costs incurred for the Kansas Electric Transmission Authority (“KETA”) Project and the Kansas V-Plan Project prior to construction. Based on ITC Great Plains’ FERC application under which authority to recognize these regulatory assets was sought and the related FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the FPA in order to recover these start-up, development and pre-construction expenses in future rates.

Development Bonuses

During the first quarter of 2013, we recognized general and administrative expenses of $1.4 million for bonuses for the successful completion of certain milestones relating to projects at ITC Great Plains. It is reasonably possible that future development-related bonuses may be authorized and awarded for these or other development projects.

North Central Region Development

In 2009, we announced the Green Power Express project, which consisted of transmission line segments that would facilitate the movement of power from the Dakotas, Minnesota and Iowa to Midwest load centers that demand energy. After the announcement of the Green Power Express project, MISO undertook its Regional Generation Outlet Study (“RGOS”) to promote investments in new regional transmission infrastructure and implemented its Multi-Value Project (“MVP”) cost allocation methodology. MISO’s RGOS and MVP processes provide a channel for the Green Power Express project, or its underlying segments, to move forward through the planning approval process as MVPs. In December 2011, MISO approved the first portfolio of MVPs identified through the RGOS which includes portions of four MVPs that we intend to build, own and operate. The four MVPs are located in south central Minnesota, portions of Iowa, southwest Wisconsin, and northeast Missouri.

We continue to explore other opportunities to advance segments of our Green Power Express project, or similar RGOS projects, through the MISO MVP process.

Entergy Transaction

As of December 4, 2011, Entergy and ITC Holdings executed definitive agreements (as subsequently amended, the “transaction agreements”) under which Entergy will divest and then merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings. Entergy’s electric transmission business consists of approximately 15,400 miles of interconnected transmission lines at voltages of 69 kV and above and associated substations across its utility service territory in the mid-south.

The Entergy Transaction would expand our network across the entire middle of the continental United States from the Great Lakes to the Gulf Coast. It will approximately double our asset base, add sizable new markets to our operating and development portfolio, and diversify and enhance growth prospects through an expanded footprint.

The terms of the transaction agreements call for Entergy to divest its electric transmission business to a newly-formed entity, Mid South TransCo LLC (“Mid South TransCo”), and Mid South TransCo’s subsidiaries, and distribute the equity interests in Mid South TransCo to Entergy’s shareholders in the form of a tax-free spin-off. Mid South TransCo will then merge with a newly-created merger subsidiary of ITC Holdings in an all-stock, Reverse Morris Trust transaction, and will survive the merger as a wholly owned subsidiary of ITC Holdings. Prior to the merger, we expect to effectuate a recapitalization which will not exceed $700 million and which may take the form of a one-time special dividend to ITC Holdings’ pre-merger shareholders, a repurchase of ITC Holdings common stock from its shareholders, or a combination of a special dividend and share repurchase. The merger will result in shareholders of Entergy receiving approximately 50.1% of the shares of pro forma

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ITC Holdings in exchange for their shares of Mid South TransCo, with existing shareholders of ITC Holdings owning the remaining approximately 49.9% of the combined company. In addition, Entergy will receive gross cash proceeds of $1.775 billion from indebtedness that will be incurred by Mid South TransCo and its subsidiaries prior to the merger. This indebtedness will be assumed by us upon completion of the transaction.

On April 16, 2013, ITC Holdings received the necessary shareholder approvals to consummate the merger. Completion of the Entergy Transaction is expected in 2013 subject to the satisfaction of certain closing conditions, including receipt of the necessary approvals of Entergy’s retail regulators and the FERC. There can be no assurance the Entergy Transaction will be consummated. See “Item 1A Risk Factors — We may be unable to satisfy the conditions or obtain the approvals required to complete the Entergy Transaction or such approvals may contain material restrictions or conditions” of our Form 10-K for the fiscal year endedDecember 31, 2012.

Per the transaction agreements, prior to completion of the Entergy Transaction, there are certain restrictions on our ability to pay dividends other than those paid in the ordinary course of business with record dates and payment dates consistent with our past practice and, if elected, a one-time special dividend to ITC Holdings’ pre-merger shareholders in accordance with the transaction agreements. Management does not expect the restrictions to have an impact on our ability to pay dividends at the current level in the foreseeable future.

Cost-Based Formula Rates 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 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 rather than a lagging basis. The formula rate templates 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 — 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 accrual/deferral 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 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. For example, to the extent that amounts billed are less than the revenue requirement for a reporting period, a revenue accrual is recorded for the difference. To the extent that amounts billed are more than the revenue requirement for a reporting period, a revenue deferral is recorded for the difference. 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 affected by many variables, but is generally impacted by weather and economic conditions and is seasonally shaped with higher load in the summer months when cooling demand is higher.

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The following table sets forth the monthly peak loads during the last three calendar years.

Monthly Peak Load (in MW) (a)

	2013			2012			2011
	ITCTransmission	METC	ITC Midwest	ITCTransmission	METC	ITC Midwest	ITCTransmission	METC	ITC Midwest
January	7,593	6,178	2,790	7,264	6,145	2,789	7,326	6,045	2,777
February	7,141	5,848	2,677	6,919	5,754	2,592	7,261	6,058	2,854
March	6,817	5,551	2,542	6,941	5,708	2,443	6,946	5,715	2,520
April				6,403	5,259	2,296	6,483	5,416	2,458
May				8,947	6,459	2,700	10,119	7,239	2,773
June				11,652	8,738	3,388	11,488	8,231	3,403
July				12,180	9,354	3,636	12,321	9,389	3,621
August				11,081	8,508	3,445	11,158	8,538	3,614
September				9,094	7,346	3,411	11,288	7,966	3,466
October				6,626	5,429	2,487	6,642	5,479	2,559
November				7,024	5,953	2,680	7,101	6,061	2,556
December				7,226	5,891	2,682	7,206	6,071	2,734
Total	21,551	17,577	8,009	101,357	80,544	34,549	105,339	82,208	35,335

____________________________

(a) Our MISO Regulated Operating Subsidiaries are each part of a joint rate zone. The load data presented is for all transmission owners in the respective joint rate zone and is used for billing network revenues. Each of our MISO Regulated Operating Subsidiaries makes up the most significant portion of the rates or revenue requirement billed to network load within their respective joint rate zone.

Capital Investment and Operating Results Trends

We expect a general trend of increases in revenues and earnings for our Regulated Operating Subsidiaries over the long term. The primary factor that is expected to continue to increase our actual revenue requirements in future years is our anticipated capital investment in excess of depreciation as a result of 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, as well as the Entergy Transaction. In addition, our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that will 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 strive for high reliability of their systems and to improve system accessibility for all generation resources. Effective June 2007, the FERC approved mandatory adoption of certain reliability standards and approved enforcement actions for violators, including fines of up to $1.0 million per day. The NERC was assigned the responsibility of developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by the NERC, as well as the standards of applicable regional entities under the NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe 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.

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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 transmission plays in meeting the needs of the wholesale market, including accommodating the siting of new generation or to increase 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 expected and actual capital investment for each of the Regulated Operating Subsidiaries and our development initiatives:

			Actual Capital		Forecasted Capital
	Long-term Capital		Investment for the		Investment for the
(in millions)	Investment Program		three months ended		year ending
Source of Investment	2012-2016 (a)		March 31, 2013 (b)		December 31, 2013 (a)
ITCTransmission	$	739	$	53.4	$200 — 230
METC	581		32.3		160 — 180
ITC Midwest	1,128		92.2		270 — 300
ITC Great Plains (c)	343		34.1		130 — 150
Development (d)	1,390		—		—
Total	$	4,181	$	212.0	$760 — 860

____________________________

(a) The current long-term capital investment program does not include anticipated expenditures related to the Entergy Transaction or in the subsidiaries of Mid South TransCo post-closing. The investments in property, plant and equipment would be expected to increase significantly upon closing of that transaction.

(b) Capital investment amounts differ from cash expenditures for property, plant and equipment included in our condensed consolidated statements of cash flows due in part to differences in construction costs incurred compared to cash paid during that period, as well as payments for major equipment inventory that are included in cash expenditures but not included in capital investment until transferred to construction work in progress, among other factors.

(c) ITC Great Plains’ investment program includes the Kansas V-Plan Project that is under construction.

(d) The long-term capital investment program includes expenditures to construct various development projects such as our portions of the four MISO MVPs.

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 financing for such expenditures, if necessary, 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 and variances between estimated and actual costs of construction contracts awarded. 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, the generator’s potential failure to meet the various criteria of Attachment FF of the MISO tariff for the project to qualify as a refundable network upgrade, and other factors beyond our control.

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RESULTS OF OPERATIONS

Results of Operations and Variances

	Three months ended									Percentage
	March 31,						Increase			increase
(in thousands)	2013			2012			(decrease)			(decrease)
OPERATING REVENUES	$	217,304		$	196,713		$	20,591		10.5	%
OPERATING EXPENSES
Operation and maintenance	24,513			28,712			(4,199		)	(14.6	)%
General and administrative	34,926			23,009			11,917			51.8	%
Depreciation and amortization	28,486			25,011			3,475			13.9	%
Taxes other than income taxes	16,670			14,280			2,390			16.7	%
Other operating (income) and expenses — net	(172		)	(193		)	21			(10.9	)%
Total operating expenses	104,423			90,819			13,604			15.0	%
OPERATING INCOME	112,881			105,894			6,987			6.6	%
OTHER EXPENSES (INCOME)
Interest expense	39,063			37,910			1,153			3.0	%
Allowance for equity funds used during construction	(8,733		)	(5,624		)	(3,109		)	55.3	%
Other income	(236		)	(306		)	70			(22.9	)%
Other expense	1,037			831			206			24.8	%
Total other expenses (income)	31,131			32,811			(1,680		)	(5.1	)%
INCOME BEFORE INCOME TAXES	81,750			73,083			8,667			11.9	%
INCOME TAX PROVISION	31,560			27,032			4,528			16.8	%
NET INCOME	$	50,190		$	46,051		$	4,139		9.0	%

Operating Revenues

Three months endedMarch 31, 2013 compared to three months endedMarch 31, 2012

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

												Percentage
	2013				2012				Increase			increase
(in thousands)	Amount		Percentage		Amount		Percentage		(decrease)			(decrease)
Network revenues	$	171,285	78.8	%	$	163,156	82.9	%	$	8,129		5.0	%
Regional cost sharing revenues	37,469		17.2	%	25,476		13.0	%	11,993			47.1	%
Point-to-point	4,369		2.0	%	4,125		2.1	%	244			5.9	%
Scheduling, control and dispatch	2,988		1.4	%	3,375		1.7	%	(387		)	(11.5	)%
Other	1,193		0.6	%	581		0.3	%	612			105.3	%
Total	$	217,304	100.0	%	$	196,713	100.0	%	$	20,591		10.5	%

Network revenues increased due primarily to higher revenue requirements at our Regulated Operating Subsidiaries during the three months endedMarch 31, 2013 as compared to the same period in 2012. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service and higher recoverable expenses due to higher operating expenses.

Regional cost sharing revenues increased due primarily to additional capital projects that have been identified by MISO as eligible for regional cost sharing and these projects being placed in-service. We expect to continue to receive regional cost sharing revenues and the amounts could increase in the near future, including revenues associated with projects that have been or are expected to be approved for regional cost sharing.

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Operating revenues for the three months endedMarch 31, 2013 include the network revenue, regional cost sharing and scheduling, control and dispatch revenue accruals (deferrals) as calculated below:

														Total
								ITC			ITC Great			net revenue
Line	Item	ITCTransmission			METC			Midwest			Plains			accrual
	(in thousands)
1	Estimated net revenue requirement (a)	$	59,082		$	50,865		$	59,932		$	1,406
2	Network revenues billed (b)	51,914			46,473			63,910			1,434
3	Network revenue accruals (deferrals) (line 1 — line 2)	7,168			4,392			(3,978		)	(28		)
4	Regional cost sharing revenue accruals (deferrals) (c)	(3,695		)	(1,038		)	401			(2,011		)
5	Scheduling, control and dispatch revenue deferrals (d)	(198		)	(214		)	(112		)	—
6	Total net revenue accruals (deferrals) (line 3 + line 4 + line 5)	$	3,275		$	3,140		$	(3,689	)	$	(2,039	)	$	687

____________________________

(a) The calculation of net revenue requirement for our Regulated Operating Subsidiaries is described in our Form 10-K for the year endedDecember 31, 2012 under “Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cost-Based Formula Rates with True-Up Mechanism — Revenue Requirement Calculation.” The amount is estimated for each reporting period until such time as FERC Form No. 1’s are completed for our Regulated Operating Subsidiaries.

(b) Network revenues billed at our MISO Regulated Operating Subsidiaries are calculated based on the joint zone monthly network peak load multiplied by their effective monthly network rates for 2013 of $2.147 per kW/month, $2.5263 per kW/month and $7.805 per kW/month applicable to ITCTransmission, METC and ITC Midwest, respectively, adjusted for the actual number of days in the month less amounts recovered or refunded associated with our MISO Regulated Operating Subsidiaries 2011 true-up adjustments. The rates for 2013 include amounts for the collection and refund of the 2011 revenue accruals and deferrals and related accrued interest and the revenues billed in 2013 associated with the 2011 revenue accruals and deferrals are not included in these amounts.

(c) Regional cost sharing revenues are subject to a separate true-up mechanism whereby our Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery. The related revenue accruals or deferrals associated with regional cost sharing revenues are included in the regional cost sharing revenue amounts.

(d) Beginning in 2013, a significant portion of our MISO Regulated Operating Subsidiaries’ scheduling, control and dispatch revenues are subject to a separate true-up mechanism whereby our MISO Regulated Operating Subsidiaries accrue or defer revenues for any over- or under-recovery. The related revenue accruals or deferrals associated with the MISO Regulated Operating Subsidiaries’ scheduling, control and dispatch revenues are included in the scheduling, control and dispatch revenue amounts.

Operating Expenses

Operation and maintenance expenses

Three months endedMarch 31, 2013 compared to three months endedMarch 31, 2012

Operation and maintenance expenses decreased by $3.3 million due to increased cost efficiencies associated primarily with substation and transmission line maintenance and $1.0 million for lower vegetation management requirements.

General and administrative expenses

Three months endedMarch 31, 2013 compared to three months endedMarch 31, 2012

General and administrative expenses increased due to external legal, advisory and consulting services for the Entergy Transaction of $5.9 million, higher compensation-related expenses of $3.7 million primarily due to personnel increases and increases in bonuses earned in 2013 such as those described above under “Capital Project Updates and Other Recent Developments — Development Bonus” and an increase in other professional services such as legal, advisory and financial services fees of $1.4 million.

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Depreciation and amortization expenses

Three months endedMarch 31, 2013 compared to three months endedMarch 31, 2012

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

Taxes other than income taxes

Three months endedMarch 31, 2013 compared to three months endedMarch 31, 2012

Taxes other than income taxes increased due to higher property tax expenses due primarily to our Regulated Operating Subsidiaries’ 2012 capital additions, which are included in the assessments for 2013 personal property taxes.

Other Expenses (Income)

Three months endedMarch 31, 2013 compared to three months endedMarch 31, 2012

Interest expense increased due primarily to additional interest expense associated with higher borrowing levels under our revolving credit agreements and term loan credit agreement.

Allowance for Equity Funds Used During Construction (“AFUDC equity”) increased due primarily to higher capital expenditures during the period.

Income Tax Provision

Three months endedMarch 31, 2013 compared to three months endedMarch 31, 2012

Our effective tax rates for the three months endedMarch 31, 2013 and 2012 were 38.6% and 37.0%, respectively. Our effective tax rate exceeded our 35% statutory federal income tax rate due primarily to state income taxes, 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 $2.9 million (net of federal deductibility) during the three months endedMarch 31, 2013, compared to a state income tax provision of $2.4 million (net of federal deductibility) for the three months endedMarch 31, 2012.

LIQUIDITY AND CAPITAL RESOURCES

We expect to fund our future capital requirements with cash from operations, our existing cash and cash equivalents and amounts available under our revolving credit agreements (described in Note 5 to the condensed consolidated financial statements). In addition, we may from time to time secure debt and equity 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. We expect that our capital requirements will arise principally from our need to:

• Fund capital expenditures at our Regulated Operating Subsidiaries and, following the close of the Entergy Transaction, capital expenditures at the subsidiaries of Mid South TransCo. 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 which 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. We expect our interest payments to increase each year as a result of additional debt we expect to incur to fund our capital expenditures.

• Fund dividends or any recapitalization associated with the Entergy transaction to holders of our common stock.

• Fund contributions to our retirement plans, as described in Note 8 to the condensed consolidated financial statements. We expect to contribute up to $11.3 million to these plans in 2013. The impact of the growth in the number of participants in our retirement benefit plans and changes in the requirements of the Pension Protection Act may require contributions to our retirement plans to be higher than we have experienced in the past.

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In addition to the expected capital requirements above, any adverse determinations relating to the contingencies described in Note 10 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 to fund capital investments. We expect to continue to utilize our revolving and term loan credit agreements and our cash and cash equivalents as needed to meet our short-term cash requirements. As described in Note 5 to the condensed consolidated financial statements, in 2013, we entered into a term loan credit agreement for $250.0 million at ITC Holdings. As of March 31, 2013, we had consolidated indebtedness under our revolving and term loan credit agreements of $741.3 million, with unused capacity under the agreements of $433.7 million.

As of March 31, 2013, we have approximately $902.0 million of debt maturing within one year at ITC Holdings and ITCTransmission. The maturing debt is expected to be refinanced with long-term debt. In addition, for our long-term capital requirements and the funding of the anticipated $700 million recapitalization in connection with the Entergy Transaction, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed in the event we experience difficulties in accessing capital. We expect to be able to obtain such additional financing for both our short and long-term requirements 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.

On April 4, 2013, ITC Midwest issued $100 million aggregate principal amount of its 4.09% First Mortgage Bonds, Series F, due 2043 under its First Mortgage and Deed of Trust, as supplemented by the Seventh Supplemental Indenture thereto. See Note 5 to the condensed consolidated financial statements.

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 an indication of future stock performance or 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
ITCTransmission	First Mortgage Bonds	A	A1
METC	Senior Secured Notes	A	A1
ITC Midwest	First Mortgage Bonds	A	A1
ITC Great Plains	Unsecured Credit Facility	BBB+	Baa1

____________________________

(a) On December 19, 2012, Standard and Poor’s Financial Services completed their annual review and made no changes to the existing ratings. All of the ratings have a stable outlook.

(b) Moody’s Investor Service, Inc. updated their credit opinions on April 15, 2013 and made no changes to the credit ratings. All of the ratings have a stable outlook.

Covenants

Our debt instruments include senior notes, secured notes, first mortgage bonds and revolving credit agreements containing numerous financial and operating covenants that place significant restrictions, which are described in Note 5 to the condensed consolidated financial statements and in our Form 10-K for the fiscal year endedDecember 31, 2012. As of March 31, 2013, we were in compliance with all debt covenants and 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 $72.0 million and $29.7 million for the three months endedMarch 31, 2013 and 2012, respectively. The increase in cash provided by operating activities was due primarily to the timing of interest payments which resulted ina decrease in interest payments (net of interest capitalized) of $18.1 million, an increase in cash received from operating revenues of $15.8 million and the timing of tax payments which resulted in lower income taxes paid of $8.2 million during the three months endedMarch 31, 2013 compared to the same period in 2012.

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Cash Flows From Investing Activities

Net cash used in investing activities was $214.2 million and $224.1 million for the three months endedMarch 31, 2013 and 2012, respectively. The decrease in cash used in investing activities was due primarily to the timing of payments for investments in property, plant and equipment.

Cash Flows From Financing Activities

Net cash provided by financing activities was $183.6 million and $159.2 million for the three months endedMarch 31, 2013 and 2012, respectively. The increase in cash provided by financing activities was due primarily to the proceeds from a net increase of $139.8 million in amounts outstanding under our revolving and term loan credit agreements. This increase was partially offset by higher net payments of $16.2 million associated with refundable deposits for transmission network upgrades and no issuance of long-term debt during the three months endedMarch 31, 2013 as compared to proceeds of $100.0 million from the closing of ITC Midwest’s 3.50% First Mortgage Bonds, Series E during the same period in 2012.

CONTRACTUAL OBLIGATIONS

Our contractual obligations are described in our Form 10-K for the year endedDecember 31, 2012. There have been no material changes to that information since December 31, 2012, other than amounts borrowed under our revolving and term loan credit agreements and the issuance on April 4, 2013 of $100.0 million of 4.09% First Mortgage Bonds, Series F, due January 2043 by ITC Midwest as described in Note 5 to the condensed consolidated financial statements which were not included in the contractual obligations table as of December 31, 2012.

CRITICAL ACCOUNTING POLICIES

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” in our Form 10-K for the fiscal year endedDecember 31, 2012 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 three months endedMarch 31, 2013.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 2 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 and term loan credit agreements, was $3,034.8 million at March 31, 2013. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $2,619.5 million at March 31, 2013. 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, at March 31, 2013. An increase in interest rates of 10% (from 7.0% to 7.7%, for example) at March 31, 2013 would decrease the fair value of debt by $66.0 million, and a decrease in interest rates of 10% at March 31, 2013 would increase the fair value of debt by $70.7 million at that date.

31

Revolving and Term Loan Credit Agreements

At March 31, 2013, we had a consolidated total of $741.3 million outstanding under our revolving and term loan 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 March 31, 2013 would increase or decrease the total interest expense by $1.0 million, respectively, for an annual period on a constant borrowing level of $741.3 million.

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. The interest rate swaps manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to (1) the expected refinancing of the $267.0 million ITC Holdings 5.25% Senior Notes, due July 15, 2013, prior to its maturity and (2) the expected financing required to repay the $200.0 million and $250.0 million borrowed under the existing ITC Holdings unsecured, unguaranteed term loan credit agreements, due August 23, 2013 and December 31, 2013, respectively, prior to their maturity.

Other

As described in our Form 10-K for the fiscal year endedDecember 31, 2012, we are subject to commodity price risk from market price fluctuations, and to credit risk primarily with Detroit Edison, Consumers Energy and IP&L, our primary customers. There have been no material changes in these risks during the three months endedMarch 31, 2013.

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 the 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 endedMarch 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1A. RISK FACTORS

For information regarding risk factors affecting us, see “Item 1A Risk Factors” of our Form 10-K for the fiscal year endedDecember 31, 2012. There have been no material changes to the risk factors set forth therein.

32

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 March 31, 2013:

Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Program (b)	Maximum Number or Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (b)
January 2013	1,956	$	78.57	—	—
February 2013	812	81.21		—	—
March 2013	420	86.42		—	—
Total	3,188	$	80.28	—	—

____________________________

(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) We do not have a publicly announced share repurchase plan.

33

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
2.5	Amendment No. 2 to the Merger Agreement, dated as of January 28, 2013, among Entergy Corporation, Mid South TransCo LLC, ITC Holdings Corp. and ITC Midsouth LLC (formerly known as Ibis Transaction Subsidiary LLC) (filed with Registrant’s Form 8-K on January 31, 2013)
4.32	Seventh Supplemental Indenture, dated as of March 18, 2013, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K filed on April 8, 2013)
10.113	Employment Agreement between ITC Holdings Corp. and Cameron M. Bready, dated as of December 21, 2012 (filed with Registrant’s Form 8-K on January 23, 2013)
10.114	Term Loan Credit Agreement, dated February 15, 2013, among Registrant, various financial institutions from time to time parties hereto, Wells Fargo Bank, National Association, as administrative agent for the Lenders, Bank of America, N.A., as documentation agent, Deutsche Bank Securities, Inc. and Morgan Stanley Senior Funding, Inc., as co-syndication agents and Wells Fargo Securities, LLC, Deutsche Bank Securities, Inc., Merrill Lynch, Pierce, Fenner & Smith Inc. and Morgan Stanley Senior Funding, Inc. as joint lead arrangers and joint bookrunners (filed with Registrant’s Form 8-K on February 19, 2013)
10.116	First Amendment, dated April 9, 2013, to Revolving Credit Agreement, dated as of February 16, 2011, among ITC Great Plains, LLC, as the Borrower, Various Financial Institutions and Other Persons from Time to Time Parties Thereto, as the Lenders, Credit Suisse AG, and Cayman Islands Branch, as Administrative Agent (filed with Registrant’s Form 8-K filed on April 12, 2013)
10.117	Amendment and Restatement of the April 1, 2001 Distribution-Transmission Interconnection Agreement by and between Michigan Electric Transmission Company, LLC as Transmission Provider and Consumers Energy Company as Local Distribution Company, effective March 1, 2013
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

34

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: April 24, 2013

ITC HOLDINGS CORP.
By:	/s/ Joseph L. Welch
	Joseph L. Welch
	President and Chief Executive Officer (duly authorized officer)
By:	/s/ Cameron M. Bready
	Cameron M. Bready
	Executive Vice President and Chief Financial Officer (principal financial officer and principal accounting officer)

35

EX-10.117

EXHIBIT 10.117

SA 1926 DTIA Consumers-METC Version: 3.0.0 Effective 3/1/2013

Fourth Revised Service Agreement No.1926

Amendment and Restatement of the

April 1, 2001

DISTRIBUTION-TRANSMISSION

INTERCONNECTION AGREEMENT

by and between

Michigan Electric Transmission Company, LLC

as Transmission Provider

and

Consumers Energy Company

as Local Distribution Company

TABLE OF CONTENTS

ARTICLE 1.Definitions

ARTICLE 2.Operational Requirements

ARTICLE 3:Operation and Maintenance

ARTICLE 4.Supervisory Control and Data Acquisition, SCADA

ARTICLE 5.Revenue Metering

ARTICLE 6.Protective Relaying and Control

ARTICLE 7.Planning and Obligation to Serve

ARTICLE 8.Transmission Service Level

ARTICLE 9.New Construction and Modification

ARTICLE 10.Access to Facilities

ARTICLE 11.Notifications and Reporting

ARTICLE 12.Safety

ARTICLE 13.Environmental Compliance and Procedures

ARTICLE 14.Billings and Payment

ARTICLE 15.Applicable Regulations and Interpretation

ARTICLE 16.Force Majeure

ARTICLE 17.Indemnification

ARTICLE 18.Insurance

ARTICLE 19.Several Obligations

ARTICLE 20.Confidentiality

ARTICLE 21.Breach, Default and Remedies

ARTICLE 22.Term

ARTICLE 23.Assignment/Change in Corporate Identity

ARTICLE 24.Subcontractors

ARTICLE 25.Dispute Resolution

ARTICLE 26.Miscellaneous Provisions

EXHIBIT 1. Interconnection Points (Substations) Addendum 7, Final

11/28/12

EXHIBIT 2.Contact Information for Local Distribution Company's

Representatives and Transmission Provider's Representatives

EXHIBIT 3.Special Manufacturing Contracts Influenced by Transmission

System

EXHIBIT 4.Metering Specifications

EXHIBIT 5. Respective Ownership of Substation Facilities Since August 7, 2007 - Addendum 5, Final 11/28/12

EXHIBIT 6. Jointly Owned Assets - Ownership by Percent of Major Equipment Addendum 7, Final 11/28/12

Amendment and Restatement of the

DISTRIBUTION TRANSMISSION INTERCONNECTION AGREEMENT

This Amendment and Restatement of the April 1, 2001 Distribution Transmission Interconnection Agreement (“Agreement”) is entered into April 29, 2002, by and between the Michigan Electric Transmission Company, LLC, a Michigan corporation (“Transmission Provider”), having a place of business at 27175 Energy Way, Novi, Michigan 48377, and Consumers Energy Company (“Local Distribution Company”), a Michigan company, doing business in Michigan and having a place of business at One Energy Plaza, Jackson, Michigan, 49201.Transmission Provider and Local Distribution Company are individually referred to herein as a "Party” and collectively as “Parties.” This Agreement amends, restates and completely replaces the April 1, 2001 Distribution Transmission Interconnection Agreement between the Parties, effective on the date indicated above.

WHEREAS, Transmission Provider requires access to parts of Local Distribution Company's assets, and Local Distribution Company requires access to parts of Transmission Provider's assets; and

WHEREAS, the Parties have agreed to execute this mutually acceptable Agreement in order to provide interconnection of the Local Distribution Company with the Transmission Provider and to define the continuing rights, responsibilities, and obligations of the Parties with respect to the use of certain of their own and the other Party's property, assets, and facilities.

NOW, THEREFORE, in consideration of their respective commitments set forth herein, and intending to be legally bound hereby, the Parties covenant and agree as follows:

ARTICLE 1. Definitions

Wherever used in this Agreement with initial capitalization, the following terms shall have the meanings specified or referred to in this Article 1.

1.1 Administrative Committee means the committee established pursuant to Article 6 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.

1.2 Agreement means this Interconnection Agreement between Local Distribution Company and Transmission Provider, including all attachments hereto, as the same may be amended, supplemented, or modified in accordance with its terms

1.3 Black Start Capability shall mean a generating unit that is capable of starting without an outside electrical supply.

1.4 Black Start Plan shall mean a plan utilizing Black Start Capability designed and implemented by the Transmission Provider 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.

1.5 Commission shall mean the Michigan Public Service Commission (MPSC), or its successor.

1.6 Confidential Information shall have the meaning set forth in Section 20.1 hereof.

1.7 Control Area shall mean an electric system, bounded by interconnection metering and telemetry. Generation within the Control Area is directed to operate in a manner prescribed by guidelines established by ECAR and NERC and in accordance with Good Utility Practice to (a) maintain scheduled interchange with other Control Areas, (b) maintain the operating frequency and (c) provide sufficient generating capacity to maintain operating reserves.

1.8 Distribution System shall mean the equipment and facilities and the Interconnection Equipment owned by the Local Distribution Company and used to deliver power and energy to end users including transformers, switches, and feeders rated at Nominal Voltage of 138 kilovolts (kV) or less.

1.9 Distribution System Control shall mean the entity that has the ability and the obligation to operate the Distribution System Control Area to ensure that the aggregate electrical demand and energy requirements of the load is met at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.

1.10 Distribution System Control Area shall mean a Control Area whose load and generation, and other bulk power supply points are integrated by the Transmission System.

1.11 Distribution System Control Center shall mean the electric Distribution System Control Center(s) that is/are responsible for monitoring and controlling the Distribution System in real time.

1.12 Distribution Transformer shall mean an electrical transformer which, generally, has its secondary low-side windings rated at Nominal Voltage of less than 138 kV.

1.13 Due Diligence shall mean the exercise of good faith efforts to perform a required act on a timely basis and in accordance with Good Utility Practice using the necessary technical and personnel resources.

1.14 ECAR is an acronym, which stands for the East Central Area Reliability coordination agreement. This is the Agreement under which Transmission Providers, who are signatories of the agreement, establish regional coordination practices and guides to govern the electric coordinated operation and reliability of the East Central Region of North America.

1.15 Effective Date shall mean the closing date as defined in the Membership Interests Purchase Agreement between the Parties.

1.16 Eligible Customer shall have the same meaning as that term is defined under the Transmission Provider's OATT on file with the FERC.

1.17 Emergency means a condition or situation that in the reasonable good faith determination of the affected Party in accordance with Good Utility Practice contributes to an existing or imminent physical threat of danger to life or a significant threat to health, property or the environment.

1.18 Extended Outage shall mean an Unplanned Outage, in which facilities are automatically removed from service (typically by relay-action operating circuit breakers), with a duration of more than two (2) minutes.

1.19 FERC shall mean the Federal Energy Regulatory Commission or its successor federal agency.

1.20 Force Majeure shall have the meaning set forth under Article 16 hereof.

1.21 Forced Outage shall mean an Unplanned Outage, in which facilities are removed from service by operator intervention and not automatically such as by relay-action operating circuit breakers.

1.22 Good Utility Practice shall mean any of the practices, methods and acts engaged in or approved by a significant portion 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 includes all acceptable practices, methods, or acts generally accepted in the region.

1.23 Governmental Authority shall mean any foreign, federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, arbitrating body, or other governmental authority; provided such entity possesses valid jurisdictional authority to regulate the Parties and the terms and conditions of this Agreement.

1.24 ISO means Independent System Operator.

1.25 Interconnection Equipment shall mean all the equipment that is necessary for the interconnection of the Distribution System to the Transmission System which is located at the substations listed in Exhibit 1 hereto as it may be revised from time to time.

1.26 Interconnection Point(s) shall mean the point(s) at which the Distribution System is connected to the Transmission System, as set forth in Exhibit 1 hereto as it may be revised from time to time.

1.27 Interconnection Service shall mean the services provided by the Transmission Provider for the interconnection of the Distribution System with the Transmission System. Interconnection Service does not include the right to transmission service on the Transmission System, which service shall be obtained in accordance with the provisions of the Transmission Provider's OATT.

1.28 Interconnection Standards shall be those standards provided by the Transmission Provider to the Local Distribution Company to establish and maintain interconnection operation in compliance with standards of NERC, ECAR, applicable state or federal regulations or by mutual agreement of the Parties.

1.29 Interest Rate shall mean an annual percentage rate of interest equal to the lesser of (a) the prime rate published by the Wall Street Journal (which represents the base rate on corporate loans posted by at least 75% of the nation's banks) on the date due, plus 2%, or (b) the highest rate permitted by law.

1.30 Jointly Owned Assets shall mean those assets in which the Transmission Provider and Local Distribution Company have undivided ownership interests. Due to the nature of substation designs, many of the supporting substation assets (e.g., station batteries, fence, control houses, ground

grid, yard stone, steel structures, and some protective relay equipment) 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 6.

1.31 Knowledge shall mean actual knowledge of the corporate officers or managers of the specified Person charged with responsibility for the particular function as of the Effective Date of this Agreement, or, with respect to any certificate delivered pursuant to the Agreement, the date of delivery of the certificate.

1.32 Least-Cost shall mean the lowest Transmission System and Distribution System facility costs, over the life of the facility, to accommodate an improvement need while adequately providing for reliability, operating, and maintenance requirements.

1.33 Local Distribution Company shall mean Consumers Energy Company and its successors and assigns.

1.34 Local Distribution Company Provided Services shall mean those services provided by the Local Distribution Company for the Transmission Provider by mutual agreement or contract.

1.35 Local Distribution Company's Representative shall be that person(s) identified as the point of contact for day-to-day operations of the Distribution System, identified in Section 2.3.

1.36 Momentary Outage shall mean a Distribution or Transmission System (in whole or in part) interruption in service with a duration of two (2) minutes or less.

1.37 Momentary Outage Event shall mean one or more Momentary Outages within any 60-minute period that are attributable to the same root cause.

1.38 NERC shall mean the North American Electric Reliability Council or its successor.

1.39 Network Security shall mean the ability of the Transmission System to withstand sudden disturbances such as unforeseen conditions, electric short circuits or unanticipated loss of system elements consistent with reliability principles used to design, plan, operate, and assess the actual or projected reliability of an electric system that are established by any Governmental Authority, NERC or ECAR and which are implemented by Transmission Provider or required of Transmission Provider in compliance with Security Coordinator directives.

1.40 Network Security Condition shall mean a condition or situation in which, in the reasonable good faith determination of Transmission Provider, Network Security is not satisfied or is threatened.

1.41 Nominal Voltage shall mean an accepted standard voltage level offered by the Transmission Provider, at various points on the Transmission System, including but not limited to 120 kV, 138 kV and 345 kV.

1.42 Normal System Condition shall mean any operating conditions of the Transmission System other than an Emergency or Network Security Condition.

1.43 Open Access Transmission Tariff or OATT shall mean the Open Access Transmission Tariff of the Transmission Provider on file with the FERC.

1.44 Operating Committee means the committee established pursuant to Section 6.4.3 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.

1.45 Party or Parties shall have the meaning set forth in the introductory paragraph of this Agreement.

1.46 Person shall mean any individual, partnership, limited liability company, joint venture, corporation, trust, unincorporated organization, or governmental entity or any department or agency thereof.

1.47 Planned Outage shall mean action by (i) Local Distribution Company or Transmission Provider to take its equipment, facilities or systems out of service, partially or completely, to perform work on specific components that is scheduled in advance and has a predetermined start date and duration pursuant to the procedures set forth in Sections 3.9.1, 3.9.2, and 3.9.4. Planned Outage shall not include the construction of new facilities or system elements, the modification of existing facilities or system elements addressed in Article 9, which includes, but is not limited to, activities associated with the construction of third party facilities or with the modifications required to accommodate third party facilities.

1.48 Planning Committee means the committee established pursuant to Section 6.4.3 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.

1.49 Protective Relay is a device which detects abnormal power system conditions and, in response, initiates automatic control action

1.50 Protective Relay System is a group of Protective Relays and associated sensing devices and communications equipment that detects system abnormalities and performs automatic control action to mitigate or reduce adverse effects of such abnormalities.

1.51 Qualified Personnel shall mean individuals trained for their positions in accordance with Good Utility Practice.

1.52 RTO means Regional Transmission Organization.

1.53 Regulated Substance means any contaminant, hazardous waste, hazardous substance, hazardous constituent, or toxic substance, as defined in the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), 42 USC 9601 et seq, Resource Conservation and Recovery Act (RCRA), 42 USC 6901 et seq, Toxic Substances Control Act (TSCA), 15 USC 2601 et seq, The Michigan Natural Resources and Environmental Protection Act (MCLA 324.101 et seq); or any other similar statutes now or hereafter in effect.

1.54 Release shall mean, spill, leak, discharge, dispose of, pump, pour, emit, empty, inject, leach, dump, or allow to escape into or through the environment.

1.55 Revenue Quality Metering System shall mean a system which includes current and voltage instrument transformers, secondary wiring, test switches, meter transducer(s), meter and loss compensation as set forth in Article 5.

1.56 RTU - Remote Terminal Units shall mean a device connected by a communication system to one or more master computers with appropriate software placed at various locations to collect data and perform remote control. It may also perform intelligent autonomous control of electrical systems and report the results back to the master computer(s).

1.57 Security Coordinator shall mean a NERC-approved entity that provides the security assessment and emergency operations coordination for one or more Control Areas or transmission providers and which has operational authority under NERC standards over the Transmission Provider.

1.58 Steady-State Voltage shall mean the value of a voltage after all transients have decayed to a negligible value. The root-mean-square value in the steady-state does not vary with time.

1.59 Supervisory Control and Data Acquisition (SCADA) shall mean a system that provides data acquisition, supervisory control and alarm display and control from remote field locations to control centers.

1.60 Transmission Provider shall mean the Michigan Electric Transmission Company, LLC and its successors and assigns.

1.61 Transmission Provider's Representative(s) shall be that person(s) identified as the point for contact for day-to-day operations of the Transmission System, identified in Section 2.3.

1.62 Transmission System shall mean all the facilities of the Transmission Provider that perform a "Transmission" function, as defined in Section 1.1 of the Easement Agreement between the Parties, dated April 29, 2002, as modified by Section 3.4 of this Agreement.

1.63 Transmission System Operations Center(s) shall mean the electric Transmission System control center(s) that is/are responsible for monitoring and controlling the Transmission System in real time.

1.64 Unplanned Outage shall mean action by Local Distribution Company or Transmission Provider to take its equipment, facilities or systems out of service, partially or completely, due to an unanticipated failure, when such removal from service was not scheduled in accordance with Sections 3.9.1, 3.9.2, and 3.9.4. Such removal from service may be automatic such as by relay-action operating circuit breakers or by operator intervention. Momentary interruptions are excluded from the definition of Unplanned Outages. Unplanned Outages include Forced Outages as well as Extended Outages.

ARTICLE 2. Operational Requirements

2.1 Subject to the terms and conditions of this Agreement, Transmission Provider shall provide Local Distribution Company Interconnection Service for each Interconnection Point identified in Exhibit 1, from the Effective Date for the term of this Agreement.

2.2 The Interconnection Points between the Transmission System and Distribution System are listed in Exhibit 1. It shall be the Transmission Provider's responsibility to annually prepare an addendum to this exhibit that shows all new or modified interconnections. The original Exhibit 1 and all addendums shall be retained for future reference.

2.3 Local Distribution Company's Representatives and Transmission Provider's Representatives are listed in Exhibit 2, as may be modified from time to time by either Party, giving written notice of changes regarding its

Representative(s) to the other Party.

2.4 Interconnection Standards

2.4.1 The Interconnection Point(s) shall be established and maintained in accordance with Good Utility Practice and the applicable NERC, Federal, State, OATT and ECAR standards and policies for Transmission Provider service to Local Distribution Company.

2.4.2 Reactive Power. Transmission Provider and Local Distribution Company recognize and agree that they have a mutual responsibility for maintaining voltage at the Interconnection Points. Transmission Provider is responsible for maintaining Transmission System voltage as listed in Sections 8.1, 8.2 and 8.3 and reasonably compensating for reactive power losses resulting from transmission service. The Local Distribution Company is responsible for controlling Distribution System voltage and compensating for Distribution System reactive power losses and reactive power consumed by retail customers. The Local Distribution Company may use a combination of static and dynamic reactive resources at various locations around the Transmission Provider's system. The Local Distribution Company's and the Transmission Provider's SCADA systems shall be used to determine the net exchange of reactive power on a total interconnections basis. For those distribution substations where there are no SCADA facilities in place the reactive flows shall be determined from SCADA data on the connecting lines in conjunction with computer load flow simulations. At load levels below 90% of peak the system should be designed such that the average power factor for the sum of all Interconnection Points is between 90% lagging and 90% leading (“peak” as used here shall refer to a current year's maximum MW load for the Local Distribution Company). For load levels above 90% of peak the power factor should be at 98% (lagging or leading), or better. If the power factor falls below this minimum the Planning Committee shall review available options and determine the best method of addressing any resulting system problems.

2.5(a) The Local Distribution Company shall comply with Transmission Provider's reasonable operating requirements or switching procedures. The Local Distribution Company shall verbally notify the Transmission Provider if the Local Distribution Company is unable to comply with this Section at any time during the term of the Agreement.

(b) The Transmission Provider shall comply with Local Distribution Company's reasonable operating requirements or switching procedures. The Transmission Provider shall verbally notify the Local Distribution Company if the Transmission Provider is unable to comply with this Section at any time during the term of the Agreement.

2.6 Local Distribution Company shall comply with the requests, orders, directives and requirements of Transmission Provider in its role of implementing the directives of the Security Coordinator. Any such requests, orders, directives or requirements of Transmission Provider must be (a) issued in accordance with Good Utility Practice, (b) not unduly discriminatory, (c) otherwise in accordance with applicable tariffs or applicable federal, state or local laws, (d) in conformance with NERC operating procedures, and (e) reasonably necessary to maintain the integrity of the Transmission System.

2.7 Load Shedding

2.7.1 Local Distribution Company shall comply, as part of a Control Area program, with installation of automatic underfrequency load shedding equipment and maintain compliance with the standards set forth in NERC and ECAR operating standards and policies at Transmission Provider's expense.

2.7.2 The Transmission Provider may direct the Local Distribution Company to shed load to maintain the reliability and integrity of the Transmission System, in accordance with the OATT. The Transmission Provider and the Local Distribution Company will comply with MPSC directives and will endeavor to minimize the impact on the Local Distribution Company customers.

2.8Not a Reservation for Transmission Service

2.8.1 Local Distribution Company, or an Eligible Customer under the OATT, shall be responsible for making arrangements under the OATT for transmission and any ancillary services associated with the delivery of capacity and/or energy purchased or produced by the Local Distribution Company, which services shall not be provided under this Agreement.

2.8.2 Local Distribution Company and Transmission Provider make no guarantees to the other under this Agreement with respect to transmission service that is available under the Transmission Provider's OATT or any other tariff under which transmission service may be available in the region. Nothing in this Agreement shall constitute an express or implied representation or warranty with respect to the current or future availability of transmission service. Should the Parties enter into an arrangement under the OATT or another tariff, any terms in this Interconnection Agreement that may be in conflict with that tariff shall be subordinate to the terms of that tariff.

ARTICLE 3. Operation and Maintenance

3.1 The Operating Committee shall develop specific methods and procedures with respect to Local Distribution Company's and Transmission Provider's systems covering at least, but not limited to, the following areas: safety, voltage control, outage planning and implementation, service restoration, emergency operations procedures, frequency controls, environmental matters, and maintenance planning and execution.

3.2 Exhibit 5 reflects ownership changes since August 7, 2007. Exhibit 5 Wiring Diagrams (WDs) will be updated continuously in each Party's Drawing Management System (DMS) which is shared between the Parties and approved by both Parties at least annually when Exhibit 6 is updated to show changes in ownership. For purpose of this Section 3.2, such submission and approval of changes shall be in writing consistent with Section 11.1. For current ownership (reflecting ownership changes since August 7, 2007), see the WDs in the DMS. The original Exhibit 5 WDs and all updates will be retained for future reference.

3.3 All operation and maintenance activities will be the financial responsibility of the owning Party. All operation and maintenance activities on Jointly Owned Assets will be under the direction and control of the Party that owns the greater percentage of the major equipment at that location. In the case where both Parties own an equal share the Local Distribution Company shall have such direction and control. The Parties' respective share of responsibility for the costs of all operation and maintenance activities on Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by the Party in that substation as set forth in Exhibit 6 and its subsequent addendums. All generation-related assets owned by the Local Distribution Company in a substation will be included as a part of the Local Distribution Company's assets in making this calculation. Responsibilities related to third-party owned generation-related assets will be split according to the nominal operating voltage at the point of connection of the generation circuit. At 120kV and above the third-party generation-related assets will be included as a part of the Transmission Provider's assets for purposes of making this calculation. Below 120 kV the third-party generation-related assets will be included as a part of the Local Distribution Company's assets for purposes of making this calculation. Major equipment shall be defined as main power transformers, 23 kV, 46 kV, 138 kV, and 345 kV circuit breakers, power system regulators and reclosers, and 46 kV and 138 kV capacitor banks. (Any three-phase installation of such equipment shall count as a

single unit). Exhibit 6 will be updated with an addendum at least annually by the Transmission Provider and approved in writing by the Local Distribution Company to show all changes in equipment ownership in the joint substations. The original Exhibit 6 and all addendums will be retained for future reference. In those substations where each Party owns assets each Party shall be financially responsible for its appropriate share of station power energy usage.

3.4 The Parties agree that the principles upon which the initial identification was made of facilities as being either Transmission or Distribution (See the definitions of "Transmission" and "Distribution" in Section 1.1 of the Amended and Restated Easement Agreement dated April 29, 2002 between the Parties) shall continue to be applied for the future unless modification is agreed to by both Parties. Should future system modifications result in the reclassification of assets, the Parties agree to convey ownership of those assets to the appropriate Party. However, no such reclassification shall affect how the other Sections of this Agreement are applied until there is a change in ownership of the facilities involved and until any related changes are made to this Agreement and its exhibits. Upon such a change in ownership, the Planning Committee shall revise Exhibits 6 and/or 7 when needed to reflect the change in ownership. The conveyed facilities shall be priced at 1.18 times the seller's net plant value but in any case shall not be less than zero dollars (i.e. no payment from seller to purchaser will occur as a result of net plant value being less than zero). As used herein, “net plant value” shall mean the asset's original cost depreciated according to the seller's accepted accounting method. In addition, should either Party plan to abandon or otherwise take out of service any facilities which could be of use as part of the other Party's system, it shall offer to convey to the other Party such facilities before they are taken out of service under the same pricing formula outlined above. All types of conveyances discussed in this paragraph shall be subject to the following conditions:

(a) The Planning Committee shall within 12 months of the Effective Date of this Agreement develop appropriate timeframes and procedures for accomplishing such conveyances.

(b) At least 12 months (or as close as feasible to 12 months) before implementing system modifications which would result in such a conveyance, the Party planning to do such modifications shall notify the other Party of such plans. The other Party, if it wishes, shall then have 2 months within which to propose an alternative modification which is consistent with Good Utility Practice, which would reduce or eliminate the need for conveyances, and which would cost the Party seeking to do the modifications no more than the originally proposed modification. If such an alternative is provided in a timely manner, the

Party proposing to do the modification shall consider the alternative and shall not unreasonably refuse to pursue the alternative instead of the original proposal.

(c) Possible impediments to timely conveying the property in question (e.g. difficulty in getting release from the conveyor's indenture) shall be referred to the Administrative Committee. The Administrative Committee is authorized to modify the requirements of this Section with regard to such a specific proposed modification however it deems appropriate in light of the possible impediment and other circumstances.

3.5 Each Party shall operate any equipment that might reasonably be expected to have impact on the operations of the other Party in a safe and efficient manner and in accordance with all applicable federal, state, and local laws, NERC operating practices, and Good Utility Practice, and otherwise in accordance with the terms of this Agreement. Each Party shall comply with the reasonable requests, orders, directives and requirements of the other Party, which are authorized under this

Agreement.

3.6(a) Without limiting the generality of Section 3.5, Local Distribution Company shall own, operate and maintain its Distribution System in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services of the Transmission System. The Local Distribution Company shall be responsible for the costs to repair or replace the Distribution System and Local Distribution Company's Interconnection Equipment.

3.6(b) Without limiting the generality of Section 3.5, Transmission Provider shall own, operate and maintain its Transmission System in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services of Local Distribution Company's Distribution System. The Transmission Provider shall be responsible for the costs to repair or replace the Transmission System and Transmission Provider's Interconnection Equipment.

3.6(c) Without limiting the generality of Section 3.5, Local Distribution Company or Transmission Provider, as appropriate pursuant to Section 3.3 hereof, shall operate and maintain Jointly Owned Assets in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services to either Party.

3.7(a) Except during an Emergency, Local Distribution Company shall not, without prior Transmission Provider authorization, operate any Transmission Provider circuit, including transformer, line or bus elements.

Local Distribution Company shall retain the right to operate Transmission Provider equipment during an Emergency for imminent personnel safety threat, to prevent damage to equipment or to maintain the integrity of the Distribution System. When practical, prior to operation of such equipment, Local Distribution Company shall provide notice to the Transmission Provider. The Local Distribution Company shall not operate any Transmission System circuit if upon notice the Transmission Provider expressly refuses to grant permission to the Local Distribution Company. Within five (5) working days of such Emergency, Local Distribution Company shall provide written explanation of such Emergency to Transmission Provider.

3.7(b) Except during an Emergency, Transmission Provider shall not, without prior Local Distribution Company authorization, operate any Local Distribution Company circuit, including transformer, line or bus elements. Transmission Provider shall retain the right to operate Local Distribution Company equipment, during an Emergency for imminent personnel safety threat, to prevent damage to equipment or to maintain the integrity of the Transmission System. When practical, prior to operation of such equipment, Transmission Provider shall provide notice to Local Distribution Company. Transmission Provider shall not operate any Distribution System circuit if upon notice the Local Distribution Company expressly refuses to grant permission to the Transmission Provider. Within five (5) working days of such Emergency, Transmission Provider shall provide written explanation of such Emergency to Local Distribution Company.

3.7(c) In an Emergency, joint facilities shall be operated by the Party able to first respond with Qualified Personnel.

3.8 Local Distribution Company and Transmission Provider shall design, install, test, calibrate, set, and maintain their respective Protective Relay equipment in accordance with Good Utility Practice, applicable federal, state or local laws and this Agreement, as set forth in Article 6 hereof. In the case of jointly owned relaying equipment, the Party having direction and control pursuant to Section 3.3 hereof shall design, install, calibrate, set, and maintain Protective Relay equipment in

accordance with Good Utility Practice. Without limiting the generality of Section 3.5(c) above, costs for such work will be split between the Companies on a predetermined ownership percentage basis as set forth in the then-current version of Exhibit 6.

3.9(a) If Transmission Provider reasonably determines that (i) any of Local Distribution Company's Interconnection Equipment fails to perform in a manner in accordance with Good Utility Practice or this Agreement, or (ii) Local Distribution Company has failed to perform proper testing or

maintenance of its Interconnection Equipment in accordance with Good Utility Practice or this Agreement, Transmission Provider shall give Local Distribution Company written notice to take corrective action. Such written notice shall be provided by Transmission Provider to Local Distribution Company's Representative as soon as practicable upon such determination. If Local Distribution Company fails to initiate corrective action promptly, and in no event later than seven (7) days after the delivery of such notification, and if in Transmission Provider's reasonable judgment leaving Local Distribution Company's Distribution System connected with Transmission System would create an Emergency or Network Security Condition, Transmission Provider may, with as much prior verbal notification to Local Distribution Company and Distribution System Control as practicable, open only the Interconnection Point(s) needing corrective action connecting the Local Distribution Company and Transmission Provider until appropriate corrective actions have been completed by Local Distribution Company, as verified by Transmission Provider. Prior to taking such action, Transmission Provider shall give appropriate consideration to the needs of the Local Distribution Company's end-use customers. Transmission Provider's judgment with regard to an interruption of service under this paragraph shall be made in accordance with Good Utility Practice and subject to Section 3.1 hereto. In the case of such interruption, Transmission Provider shall immediately confer with Local Distribution Company regarding the conditions causing such interruption and its recommendation concerning timely correction thereof. Both Parties shall act promptly to correct the condition leading to such interruption and to restore the connection.

3.9(b) If Local Distribution Company reasonably determines that (i) any of Transmission Provider's Interconnection Equipment fails to perform in a manner in accordance with Good Utility Practice or this Agreement, or (ii) Transmission Provider has failed to perform proper testing or maintenance of its Interconnection Equipment in accordance with Good Utility Practice or this Agreement, Local Distribution Company shall give Transmission Provider written notice to take corrective action. Such written notice shall be provided by Local Distribution Company to Transmission Provider's Representative as soon as practicable upon such determination. If Transmission Provider fails to initiate corrective action promptly, and in no event later than seven (7) days after the delivery of such notification, and if in Local Distribution Company's reasonable judgment leaving Transmission System connected with Local Distribution Company's Distribution System would create an Emergency, Local Distribution Company may, with as much prior verbal notification to Transmission Provider and Distribution System Control as practicable, open only the Interconnection Point(s) needing corrective action connecting the Transmission Provider and Local Distribution Company until appropriate corrective actions have been completed by Transmission Provider, as

verified by Local Distribution Company. Local Distribution Company's judgment with regard to an interruption of service under this paragraph shall be made in accordance with Good Utility Practice and subject to Section 3.1 hereto. In the case of such interruption, Local Distribution Company shall immediately confer with Transmission Provider regarding the conditions causing such interruption and its recommendation concerning timely correction thereof. Both Parties shall act promptly to correct the condition leading to such interruption and to restore the connection.

3.10Outages

3.10.1 Outage Authority and Coordination. In accordance with Good Utility Practice, each Party may, in close cooperation with the other, remove from service its system elements that may impact the other Party's system as necessary to perform maintenance or testing or to replace installed equipment. Absent the existence of an Emergency, the Party scheduling a removal of a system element from service will schedule such removal on a date mutually acceptable to both Parties, in accordance with Good Utility Practice.

3.10.2 The Parties shall coordinate inspections, Planned Outages, and maintenance of their respective equipment, facilities and systems so as to minimize the impact on the availability, reliability and security of both Parties' systems and operations when the outage is likely to have a materially adverse impact on the other Party's system or the Local Distribution Company's end-use customers. Subject to the confidentiality provisions of Article 20, on or before October 1 of each year during the term hereof, the Parties shall exchange non-binding Planned Outage schedules for the following calendar year, which shall be developed and followed in accordance with Good Utility Practice, for the Distribution System and Transmission System. The Parties shall communicate the outage schedules as promptly as possible, provided that in no event shall such schedule be provided less than fifteen (15) days prior to a Planned Outage. The Parties shall keep each other updated regarding any changes to such schedules.

3.10.3 Unplanned Outages

3.10.3.1 Distribution System Unplanned Outage. In the event of an Unplanned Outage of a system element of the Distribution System adversely affecting the Transmission System, the Local Distribution Company will act in accordance with Good Utility Practice to promptly restore

that system element to service unless the Local Distribution Company obtains concurrence from the Transmission Provider that some deferral is reasonable, and this concurrence shall not be unreasonably withheld. The Local Distribution Company shall plan and maintain its Distribution System such that the average length of distribution system outages having a direct impact on the Transmission System shall not exceed 166 minutes per event on an annual basis. For any year in which the average outage duration exceeds this limit, the Local Distribution Company shall develop a plan to improve the outage restoration process and reduce outages and shall obtain the Transmission Provider's concurrence with this plan. Within forty-eight hours (48) of the beginning of any Unplanned Outage, the Local Distribution Company shall provide the Transmission Provider with a restoration plan.

3.10.3.2 Transmission System Unplanned Outage. In the event of an Unplanned Outage of a system element of the Transmission System adversely affecting the Local Distribution Company's Distribution System, the Transmission Provider will restore the system to normal as soon as possible unless the Transmission Provider obtains concurrence from the Local Distribution Provider that some deferral is reasonable, and this concurrence shall not be unreasonably withheld. The Transmission Provider shall plan and maintain its Transmission System such that the average length of Transmission System outages having a direct

impact on customers of the Local Distribution Company shall not exceed 166 minutes on an annual basis. For any year in which the average outage duration exceeds this limit, the Transmission Provider shall develop a plan to improve the outage restoration process and reduce outages and shall obtain the Local Distribution Company's concurrence with this plan. Within forty-eight hours (48) of the beginning of any Unplanned Outage the Transmission Provider shall provide the Local Distribution Company with a restoration plan. For any 138 kV system outage it is expected that the system will be restored to its normal configuration within seven (7) days; for any 345 kV system outage it is expected that the system will be restored to its normal configuration within thirty (30) days. If it is expected that any Unplanned Outage will exceed these limits the Transmission Provider shall provide the Local Distribution

Company with detailed information on measures being taken to minimize the outage time.

3.10.4 Planned Outages

3.10.4.1 Distribution System Planned Outage. In the event of a Planned Outage of a system element of the Distribution System adversely affecting the Transmission System, the Local Distribution Company will act in accordance with Good Utility Practice to promptly restore that system element to service in accordance with its schedule for the work that necessitated the Planned Outage.

3.10.4.2 Transmission System Planned Outage. The Transmission Provider shall review all Transmission System Planned Outages with the Local Distribution Company. In the event of a Planned Outage of a system element of the Transmission System adversely affecting the Local Distribution Company's Distribution System, the Transmission Provider will act in accordance with Good Utility Practice to promptly restore that system element to service in accordance with its schedule for the work that necessitated the Planned Outage.

3.11 The Parties shall use best efforts in accordance with Good Utility Practice to coordinate operations in the event of any Forced or Planned Outage that affects the other Party's system.

3.12 Black Start Plan Participation. In accordance with Good Utility Practice, Local Distribution Company agrees to participate in Transmission Provider's Black Start Plan for the Distribution System and the Transmission System, as well as any verification testing.

3.13 The Parties shall notify and make available in a timely manner, electric system modeling information necessary for the other Party to monitor, analyze, and protect its facilities in a real time environment, no less than 30 days prior to the energization of new or reconfigured network facilities.

ARTICLE 4. Supervisory Control and Data Acquisition, SCADA

4.1 If the Transmission Provider chooses to operate its own SCADA system, or to make modifications or additions to the existing system, the following terms and conditions of this Article 4 will apply.

4.2 Interconnection Points containing SCADA and communications equipment installed prior to April 1, 2001, shall be considered to satisfy the terms and conditions of this article. For those Interconnection Points that existed prior to April 1, 2001 that did not contain SCADA and

communications equipment, and for new Interconnection Points installed after April 1, 2001 where SCADA and communications equipment is necessary for and requested by the Transmission Provider to perform monitoring, state estimation and contingency analysis, the Local Distribution Company shall install and operate such equipment at the Transmission Provider's expense. Each Interconnection Point or other mutually agreeable location with SCADA and communications equipment shall have one dedicated communications path to the Local Distribution Company's control center for the RTU data. The cost of the dedicated communications path and general use station phone shall be shared on an equal basis. Additional data paths and communications equipment requested, either emanating from the substation, the Local Distribution Company's control center, or the Transmission Provider's control center, will be at the expense of the requestor. This data and status information may be real time or with a time delay mutually acceptable to the Parties. The method of providing this data and control will be via an industry standard protocol such as Inter-Control Center Protocol (ICCP) or other method agreed to by the Parties. Such data may include, but not be limited to megawatts, megavars, voltage, amperes, device status, interchange schedule error, and communication system status.

4.3 The Transmission Provider reserves the right at its expense, to require, for new, or modified Local Distribution Company Interconnection Points, installation of a Transmission Provider's RTU or installation of a dual port RTU to provide data and control directly to the Transmission Provider within the Local Distribution Company's substation. The Local Distribution Company will assist in furnishing desired inputs for the Transmission Provider's RTU.

4.4 The operating metering system shall consist of instantaneous values of MW, MVAR, and voltage.

4.4.1 Values shall be inputted to a RTU or comparable communication device for communication with the Party having Control Area responsibility.

4.4.2 Transducers may utilize the voltage transformers and current transformer secondary circuits also utilized by the revenue metering equipment for a particular interconnection. In such case, the performance criteria listed in Exhibit 4 of the Agreement, Metering Specifications, for the voltage transformers and the current

transformers, shall apply. Relaying class voltage transformers and or current transformers shall not be utilized unless mutually agreed between all the owners of the metering equipment and the Local Distribution Company.

4.4.3 Transducers shall have maximum 0.3% inaccuracy. Transducers shall be field calibrated as necessary but at least once every ten (10) years and documentation shall be retained showing the calibration results until next calibration.

4.4.4 Telemetry shall be maintained and calibrated such that overall inaccuracy of MW, MVAR, and voltage values is less than 1.0% of full scale.

4.5 To the extent new RTUs and associated communications equipment is to be installed, the Local Distribution Company shall install or facilitate installation of the RTU and associated communications equipment as soon as practicable, provided that installation shall be accomplished within a time period of no more than 270 days following notice by Transmission Provider or prior to commissioning of any new Interconnection Points.

ARTICLE 5. Revenue Metering

5.1 Transmission Provider shall own, operate, test and maintain any metering equipment at the Interconnection Points, as required by this Article 5 not including any metering equipment owned by the Local Distribution Company for use in metering its end-use customers. Transmission Provider and Local Distribution Company agree that, as to all Interconnection Points in existence as of the Effective Date, no new or different metering equipment or arrangements shall be required. For existing Interconnection Points where low-side metering exists without loss compensation, the Parties will agree to adjust the metering data in such a manner to account for any real power losses between the location of the meter and the Interconnection Point. To the extent existing metering equipment is replaced and when new metering equipment is installed at Interconnection Points in existence as of the Effective Date, such replacements or installations shall meet the standards set in Section 5.2. Transmission Provider shall provide, install, own, operate, test and maintain the new metering equipment located at the Interconnection Points.

5.2 The Revenue Quality Metering System shall consist of all instrument transformers (current and voltage), secondary wiring, test switches, and meter(s) required to determine the metering values for record for any given metering point.

5.2.1Metering shall be form 9, 3-element for 4-wire systems and form 5, 2-element for 3-wire systems.

5.2.2Meters shall measure, at a minimum, megawatt hours and megavar hours and have bi-directional capability, where applicable. All measured values shall have individual outputs where applicable and a minimum 35-day interval data recording capability for each measured value.

5.2.3Whenever feasible, any new metering facilities shall be located at the same physical location as the Interconnection Point. If it is not reasonable to have the metering facilities and the Interconnection Point at the same physical location, the metering data will be adjusted to account for real power losses between the location of the meter and the Interconnection Point.

5.2.4Transmission Provider shall maintain records that demonstrate compliance with all meter tests and maintenance conducted in accordance with Good Utility Practice for the life of the Interconnection Point. Local Distribution Company shall have reasonable access to the records.

5.2.5For installations where the metering is performed using loss compensation, the factory certified test results of the power transformer, if available, including load, no-load losses and calculated meter loss calculations, shall be recorded in a written record. Local Distribution Company shall have reasonable access to the records.

5.2.6Transmission Provider shall maintain records of the factory certified test results, or the utility test shop test results, showing compliance of the meters with the applicable metering test standards.

5.2.7Transmission Provider's Metering equipment shall be tested by Transmission Provider at its own expense not less than once every year, unless an extension of the testing cycle is agreed upon by the Parties. The accuracy of such metering equipment shall be maintained by Transmission Provider in accordance with applicable regulatory

standards. At the request of either Party, special tests shall be made. If any special meter test discloses the metering device to be registering within acceptable limits of accuracy as specified herein, then the Party requesting such special meter test shall bear the expense thereof. Otherwise, the

expense of such test shall be borne by the owner. Representatives of either Party shall be afforded opportunity to be present at all routine or special tests and upon occasions when any readings for purposes of settlements hereunder are taken from meters not producing an automatic record.

5.2.8If, as a result of any test, any meter shall be found to be registering more than two (2) percent above or below one hundred (100) percent of accuracy, the account between the Parties hereto shall be corrected for a period equal to one-half of the elapsed time since the last prior test, according to the percentage of inaccuracy so found, except that if the meter shall have become defective or inaccurate at a reasonably ascertainable time since the last prior test of such meter, the correction shall extend back to such time. No meter shall be left in service if found to be more than two (2) percent above or below one hundred (100) percent of accuracy. Should metering equipment at any time fail to register, the energy delivered shall be determined from the best available data. All meters shall be kept under seal, such seals to be broken only when the meters are to be tested or adjusted.

5.2.9Test switches shall be installed to allow independent testing and/or replacement of each meter and transducer utilizing the secondary circuit so as not to interrupt the operation of other devices utilizing the secondary circuit.

5.2.10In substations where an RTU or other remote data collecting and telecommunication device is present, meters shall have form C, 3-wire outputs with programmable values determined by the Transmission Provider for bi-directional MWHs and MVARs.

5.2.11In the event an interconnection meter needs replacement or repair, a representative from Local Distribution Company shall be given a reasonable opportunity to be present during such repair or replacement.

ARTICLE 6. Protective Relaying and Control

6.1 Transmission Provider and the Local Distribution Company shall, in accordance with Good Utility Practice, coordinate, review and approve all new Protective Relaying equipment, including equipment settings, Protective Relay schemes, drawings, and functionality associated with each Interconnection Point. Protective Relaying equipment and schemes installed before the date of this agreement shall be considered to satisfy

the terms and conditions of this Article 6. When existing equipment or schemes are replaced or when new equipment or schemes are installed per this Article 6 or in association with new Interconnection Points, then the terms and conditions of Article 6 shall apply. Each Party shall incur the expense for the work on its system.

6.2 To the extent that there is generation on the Distribution System which, in the reasonable judgment of either Party, may contribute material amounts of current to a fault on the Transmission System, the Local Distribution Company shall have and enforce standards to ensure the provision, installation and maintenance of relays, circuit breakers, and all other devices necessary to

promptly remove any fault contribution of such generation to any short circuit occurring on the Transmission System and not otherwise isolated by the Transmission Provider equipment. Such standards will be included in the Local Distribution Company's connection requirements for generation. Transmission Provider and Local Distribution Company shall not be responsible for protection of such generation.

6.3 Transmission Provider shall own, operate, maintain and test those Protective Relay Systems that control their breakers or equivalent protective devices. Local Distribution Company shall own, operate, maintain, and test those Protective Relay Systems that control their breakers or equivalent protective devices governed by this Article 6. The Parties shall maintain, and, as necessary, upgrade their respective Protective Relay Systems and shall provide the other Party with access to available copies of operation and maintenance manuals and test records for all relay equipment upon request. The Transmission Provider will provide protective relay settings for the relays that control breakers or equivalent protective devices owned by the Local Distribution Company that also protect Transmission Provider's equipment. The Local Distribution Company will review and apply the settings.

6.4 The owner (Transmission Provider or Local Distribution Company) of the line will provide the relay communication channel necessary for line protection at its expense. Owner will participate with other Party to test communication schemes upon request without charge.

6.5 The Parties shall test their respective relays associated with the Interconnection Points for correct calibration and operation. Parties shall coordinate design, installation, operation, and testing of Protective Relay schemes to insure that such relays operate in a coordinated manner so as to not cause adverse operating conditions on the other Party's system.

6.6 Local Distribution Company shall be responsible for Protective Relay maintenance, calibration and functional testing of relay systems that protect Local Distribution Company's equipment associated with the Interconnection Points and that protect Transmission Provider from Local Distribution Company's Interconnection Equipment to the extent such calibration and testing are in accordance with Good Utility Practice. All such maintenance and testing must be performed by Qualified Personnel selected by the Local Distribution Company. In addition, Local Distribution Company shall allow Transmission Provider to conduct visual inspection of all Protective Relays and associated maintenance records directly related to the interconnection. Related maintenance and operational records shall be maintained by the Local Distribution Company in accordance with Good Utility Practice. Upon completion of Protective Relay calibration testing and relay functional testing, Local Distribution Company shall make available copies of test reports and related records for review by Transmission Provider upon request. Local Distribution Company shall review test reports and document that Protective Relay System's tests and settings, as shown on such test reports, have been done in accordance with the equipment's specifications and Good Utility Practice.

6.7(a) As Transmission Provider's system protection requirements change, Transmission Provider will upgrade its Protective Relaying System in accordance with Good Utility Practice. If these upgrades affect the serviceability and acceptability of the Protective Relaying Systems on the Interconnection Equipment which may be installed, owned, and operated by Local Distribution Company, the Local Distribution Company must upgrade its Protective Relay Systems at its expense (unless such modifications are required in association with the addition of generation to the system in which case Section 9.8 shall apply) as necessary to bring them into compatibility with that installed by Transmission Provider. Transmission Provider shall give Local Distribution

Company notice of such upgrade as soon as practicable prior to the anticipated date of such upgrade. Any proposed protective system upgrades shall be reviewed by the Planning Committee in accordance with Section 7.3 (vi) hereof.

6.7(b) As Local Distribution Company's system protection requirements change, Local Distribution Company will upgrade its Protective Relaying System in accordance with Good Utility Practice. If these upgrades affect the serviceability and acceptability of the Protective Relaying Systems on the Interconnection Equipment which may be installed, owned, and operated by Transmission Provider, Transmission Provider must upgrade its Protective Relaying Systems at its expense (unless such modifications are required in association with the addition of generation to the system in which case Section 9.8 shall apply) as necessary to bring them into compatibility with that installed by Local Distribution Company. Local Distribution Company shall give Transmission Provider notice of such upgrade as soon as practicable prior to the anticipated date of such

upgrade. Any proposed protective system upgrades shall be reviewed by the Planning Committee in accordance with Section 7.3 (vi) hereof.

6.8 Local Distribution Company shall provide necessary space to install or expand relay panels for substation system protection if requested by Transmission Provider. Any incremental costs required to accommodate such request shall be the responsibility of the Transmission Provider.

6.9 Transmission Provider shall provide the necessary space to install or expand relay panels for substation system protection if requested by Local Distribution Company. Any incremental costs required to accommodate such request shall be the responsibility of the Local Distribution Company.

6.10 Each Party will provide access to the other to fault recorder, sequence of events and relay information such as dial up access of digital relays.

ARTICLE 7. Planning and Obligation to Serve

7.1 Adequacy Obligation. Subject to applicable regulatory approvals, including adherence to Least-Cost planning requirements and principles, adherence to applicable NERC, ECAR or other regional reliability council or successor organization's reliability requirements, and all other applicable operating reliability criteria and subject to the oversight and direction of the appropriate RTO or ISO, the Transmission Provider shall operate, maintain, plan and construct its Transmission System in accordance with Good Utility Practice in order to:

(i) deliver on a reliable basis the projected capacity and energy needs of all loads served by the Local Distribution Company's Distribution System and dependent upon the Transmission Provider's facilities for delivery of such energy to the Distribution System;

(ii) provide needed support to the Local Distribution Company where a transmission addition is the Least-Cost electric solution to an improvement need, including but not limited to, the reliability needs of the Local Distribution Company; and

(iii) deliver energy from both existing and new generating facilities connected to and dependent upon Transmission Provider's transmission of such energy

7.2 With regard to planning and construction of projects which affect Local Distribution Company and Local Distribution Company's load-serving area, the Parties shall develop methods and procedures covering at least the following areas:

(i) coordination between short-term and long-term distribution and transmission planning;

(ii) developing and sharing computer simulation models needed to support Transmission Provider and Local Distribution Company planning activities;

(iii) coordination of permitting (including local and state approvals) and siting;

(iv) engineering and scheduling of new projects;

(v) construction and inspection standards;

(vi) information-sharing and priority-setting; and

(vii) health and safety issues.

7.3 With respect to Local Distribution Company's load-serving area, the Planning Committee, shall:

(i) implement the methods and procedures developed pursuant to Section 7.2;

(ii) review planning studies and reports regarding projects needed or proposed for the area in the next five (5) years, or as determined by the Planning Committee;

(iii) recommend additional studies or evaluation of plans;

(iv) follow Least-Cost planning principles in recommending specific projects;

(v) at least once every year, prepare a planning report which shall include in priority order a list of projects proposed by either Party for the next year, the estimated costs of such projects, and the timetable for such projects, including the in-service date; and

(vi) review proposed programmatic changes to the electric system, including protective system upgrades

7.4 If the Parties agree upon the need for any such project, they shall cooperate and coordinate in seeking all necessary regulatory approvals for such project. Transmission Provider shall coordinate and cooperate with Local Distribution Company with respect to all communications and commitments to municipal, county, and state agencies involved in such project.

7.5 If Local Distribution Company proposes construction of a transmission project and Transmission Provider does not agree that such project is needed, Local Distribution Company shall have the right to petition an appropriate RTO, ISO or applicable regulatory agency for a declaratory ruling on whether the proposed project is needed pursuant to Transmission Provider's public-utility duty to plan and construct a reliable, adequate Transmission System.

7.6 Load Growth and Reliability Needs. Transmission Provider is obligated to plan and install any Transmission System components that may be necessary, as determined by a Least-Cost planning process in accordance with Section 7.1 and consistent with the established and consistently applied reliability criteria of the Parties, to accommodate Local Distribution Company's planned load growth and planned reliability improvements. Transmission Provider will construct new interconnections to Local Distribution Company facilities in accordance with Transmission Provider's planning criteria, other agreements in effect between the Parties, and

Good Utility Practice. Transmission Provider shall bear the responsibility for such planning and installing in accordance with this Article 7. Transmission Provider's obligations under this Section 7.6 shall include the planning and installation of any new Interconnection Points that may be necessary to accommodate Local Distribution Company's planned load growth and planned reliability improvements. Recovery of the cost of such additions shall be in accordance with the OATT or other applicable tariff.

7.7 Local Distribution Company shall be the first point of contact and the wire-services provider for end-use customers.

7.8 Transmission Provider shall annually submit to Local Distribution Company, no later than February 1 of each year:

(i) Transmission Provider's plans covering the next five (5) years, or as determined by the Planning Committee, for installing Transmission System components that may be necessary to accommodate Local Distribution Company's planned load growth and reliability improvements as described in Section 7.6. Transmission Provider's plans shall include, but not be limited to,

cost estimates and installation schedules for Transmission System components, and shall provide specific detail sufficient to allow Local Distribution Company to compare Transmission Provider's plans with Local Distribution Company's in-service requirements to meet its planned load growth and reliability needs.

(ii) A description of any changes to the Local Distribution Company's Distribution System that may be needed to accommodate Transmission Provider's plans set forth in Section 7.8(i) will be requested by the Transmission Provider.

(iii) Projected voltage levels under Normal System Conditions and Transmission Provider's FERC 715 Planning criteria conditions at anticipated annual peak load and 80% of anticipated annual peak load for each Interconnection Point with planned additions for the next five (5) years, or as determined by the Planning Committee.

7.9 Local Distribution Company shall annually submit to Transmission Provider,

(a) no later than December 1 of each year, the most recent actual summer and winter demands in megawatts (MW) and megavars (Mvar) for all Interconnection Points connected to the Transmission System at the time of the Transmission Provider's most recent seasonal system peaks (Transmission Provider must provide the Local Distribution Company the day and hour of such peak no later than September 1); and

(b) no later than February 1 of each year:

(i) annual peak demand forecasts in MW for each Local Distribution Company Interconnection Point to the Transmission System for the next five (5) years, or as determined by the Planning Committee, together with corresponding projected power factors; and

(ii) planned facility (new Interconnection Points) connections to the Transmission System for the next five (5) years, or as determined by the Planning Committee.

ARTICLE 8. Transmission Service Level

8.1 Subject to applicable regulatory approvals, including adherence to Least-Cost planning requirements and principles, adherence to applicable NERC, ECAR or other regional reliability council or successor

organization's reliability requirements, and all other applicable operating reliability criteria and subject to the oversight and direction of the appropriate RTO or ISO, the Transmission Provider shall operate, maintain, plan and construct its Transmission System in accordance with Good Utility Practice to provide the following service levels:

(i) A minimum Steady-State Voltage of 0.97 Per Unit (PU) at all Interconnection Points with Local Distribution Company with all influential Transmission Provider facilities in service (no contingency conditions);

(ii) A minimum Steady-State Voltage of 0.92 PU at all Interconnection Points with the Local Distribution Company influenced by one or more Transmission Provider facilities out of service (contingency conditions);

(iii) A maximum Steady-State Voltage of 1.05 PU at all Interconnection Points with the Local Distribution Company during all operating conditions;

(iv) An adequate Transmission System that shall not load Local Distribution Company facilities above normal ratings during peak load conditions with all influential Transmission Provider facilities in service (no contingency conditions);

(v) An adequate Transmission System that shall not load Local Distribution Company facilities above emergency ratings during peak load conditions with one or more influential Transmission Provider facilities out of service (contingency conditions);

(vi) On a three-year rolling average, experience no more than 0.357 Momentary Outage Events per 138 kV line protective zone (system average) and 0.743 Momentary Outage Events per 345 kV line protective zone (system average) per year. As used in this Article 8 the term “year” shall mean calendar year; and the term “line protective zone” is illustrated and defined as follows: Any given electrical fault on a transmission line will trip specific circuit breakers in a normally functioning system. All of the possible line fault locations that will trip these specific circuit breakers constitute the same line protective zone. Physically, a line protective zone consists of the conductors located between the current transformers that provide sensing to trip the circuit breakers for a line fault;

(vii) Experience no more than three (3) Momentary Outage Events on any given 138 kV line protective zone and two (2) Momentary Outage Events on any given 345 kV line protective zone per year;

(viii) On a three-year rolling average, experience no more than 0.21 Unplanned Outages per 138 kV line protective zone (system average) and 0.18 Unplanned Outages per 345 kV line protective zone (system average) per year;

(ix) Experience no more than four (4) Unplanned Outages on any given 138 kV line protective zone and three (3) Unplanned Outages on any given 345 kV line protective zone per year;

(x) Should the Transmission Provider fail to meet any of the requirements of Section 8.1(vi) or 8.1(viii) by more than 10% two years in a row, the Transmission Provider shall pay, as liquidated damages and not as a penalty, to the Local Distribution Company, an amount equal to one half of one percent (0.5%) of the annual revenue paid by the Local Distribution Company under the applicable transmission tariff; such liquidated damages amount shall be based upon the revenue received in the second year of such failure. Such liquidated damages amount shall be increased by one half of a percent (0.5%) for each additional 10% by which the Transmission Provider fails to meet the any of the given outage targets, up to a maximum of 4.0% of the annual revenue. Outage events affecting 15% or more of transmission line protective zones within a 24-hour period will not be counted toward the requirements of Section 8.1.

If transmission service does not meet the requirements of this Article 8, Transmission Provider shall present an action plan acceptable to the Local Distribution Company within sixty (60) days of non-compliance of this Article 8 to restore transmission service to the minimum standards as described in this Article 8 in a timely manner. Should the Transmission Provider fail to correct the deficiency(s) within one year of notification from the Local Distribution Company, the Local Distribution Company shall have the right to take corrective action at the Transmission Provider's expense. The Local Distribution Company shall defer taking such actions for corrective measures normally requiring longer than one year to complete, provided the Transmission Provider is diligently pursuing such measures.

8.2 Should the Michigan Public Service Commission (MPSC) adopt service quality standards that the Local Distribution Company must meet that are more stringent than current historical performance; and should the

transmission service level provided by the Transmission Provider directly or indirectly influence the Local Distribution Company's ability to meet such standards, the Local Distribution Company will promptly notify the Transmission Provider of such proposal and the Transmission Provider shall have an opportunity to participate either as a party or in cooperation with the Distribution Company, in any related MPSC hearings or proceedings. Subject to the foregoing and to any required approval by FERC, the Transmission Provider shall be responsible for meeting its proportional share of the adopted service quality standard and for any penalties that might be assessed if the standards are not met.

8.3 Transmission Provider shall be responsible for those compensable disruptions/interruptions caused by the Transmission Provider's Transmission System to those Local Distribution Company customers under Special Manufacturing Contracts in existence at the time of execution of this document as set forth in Exhibit 3, including any contractual payments due.

ARTICLE 9. New Construction and Modification

9.1 Subject to this Article 9, Transmission Provider may construct additional Transmission System elements or modify the existing Transmission System and Local Distribution Company may construct additional Distribution System elements or modify the existing Distribution System. All such modifications and construction provided for herein, shall be conducted in accordance with Good Utility Practice and all applicable NERC and ECAR Standards. The Party that modifies the system elements or constructs new system elements is obligated to maintain the transmission, distribution and communications capabilities of the other Party in accordance with Good Utility Practice to avoid or minimize any adverse impact on the other Party. The Parties shall look to the operating history of the Local Distribution Company in the relevant geographic

area prior to the Effective Date of this Agreement, where available, in determining what constitutes Good Utility Practice.

9.2 Notwithstanding the foregoing, no modifications to or new construction of facilities or access thereto, including but not limited to rights-of-way, fences, and gates, shall be made by either Party which might reasonably be expected to have a material effect upon the other Party with respect to operations or performance under this Agreement, without providing the other Party with sufficient information regarding the work prior to commencement to enable such Party to evaluate the impact of the proposed work on its operations. The information provided must be of sufficient detail to satisfy reasonable Transmission Provider or Local

Distribution Company review and operational requirements. Each Party shall use reasonable efforts to minimize any adverse impact on the other Party.

9.3 If any Party intends to install any new facilities, equipment, systems, or circuits or any modifications to existing or future facilities, equipment, systems or circuits that could reasonably be expected to have a material effect upon the operation of the other Party, the Party desiring to perform said work shall, in addition to the requirements of Section 9.2, provide the other Party with drawings, plans, specifications and other necessary documentation for review at least 60 days prior to the start of the construction of any such installation. This notice period shall not apply to modifications or new installations made to resolve or prevent pending Emergency or Network Security Conditions.

9.4 The Party reviewing any drawings, plans, specifications, or other necessary documentation for review shall promptly review the same and provide any comments to the performing Party no later than 30 days prior to the start of the construction of any installation. Unless system modifications are required in association with the addition of generation to the system (in which case Section 9.8 hereof shall apply) all such reviews shall be performed at no cost to either Party. The performing Party shall incorporate all requested modifications to the extent required in accordance with Good Utility Practice and compliance with this Agreement.

9.5 Within 180 days following placing in-service of any modification or construction subject to this Article 9, the Party initiating the work shall provide “as built” drawings, plans and related technical data to the other Party. Approval or review of any document referenced herein shall not relieve the initiating Party of its responsibility for the design or construction of any proposed facility, nor shall it subject the other Party to any liability, except with respect to the confidentiality provisions of Article 20.

9.6 Each Party shall, at its own expense, have the right to inspect or observe all maintenance activities, equipment tests, installation work, construction work, and modification work to the facilities of the other Party that could have a material effect upon the facilities or operations of the first Party.

9.7 Construction and installation of any facility shall meet all or exceed all environmental permitting requirements, reviews or approvals as required by Federal, State or local law prior to the installation of such facilities. The Parties agree to coordinate environmental permitting related

activities such as site review for regulated resources, permit application and project oversight (e.g. monitoring as applicable).

9.8 Whenever system modifications are required to connect generating facilities to either the Local

Distribution Company's or the Transmission Provider's system it is expected that the party installing the generating facilities will normally be responsible for much or all of the associated costs. The Parties agree to cooperate in sharing information regarding such projects and to individually make arrangements with the party adding the generation to obtain payment of all related costs as appropriate.

ARTICLE 10. Access to Facilities

10.1 The Parties hereby agree to provide each other reasonable access to their respective property as may be necessary and appropriate to enable each Party to operate and maintain its respective facilities and equipment on such property. Such right of access shall be provided in a manner so as not to unreasonably interfere with either Party's ongoing business operations, rights, and obligations.

10.2 Each Party shall provide the other Party keys, access codes or other access methods necessary to enter the other Party's facilities to exercise rights under this Agreement. Access shall only be granted to Qualified Personnel.

ARTICLE 11. Notifications and Reporting

11.1 Unless otherwise provided, any notice required to be given by either Party to the other Party in connection with this Agreement shall be given in writing: (a) personally; (b) by facsimile transmission (if sender thereafter sends such notice to recipient by any of the other methods provided in this Section 11.1; (c) by registered or certified U.S. mail, return receipt requested, postage prepaid; or (d) by reputable overnight carrier, with acknowledged receipt of delivery; or (e) any other method mutually agreed by the Parties in writing. Notice shall be deemed given on the date of receipt personally. Notice sent by facsimile shall be deemed given on the date the transmission is confirmed by sender's facsimile machine, so long as the facsimile is sent on a business day during normal business hours of the recipient. Otherwise, the notice shall be deemed given on the next succeeding business day. Notice provided by mail or overnight courier shall be deemed given at the date of acceptance or refusal of acceptance shown on such receipt.

11.2 Notice to the Transmission Provider shall be to the Transmission Provider's Representative, at the addresses identified in Exhibit 2. Notice to the Local Distribution Company shall be to the Local Distribution Company's Representative, at the addresses identified in Exhibit 2.

11.3 Each Party shall provide prompt notice describing the nature and extent of the condition, the impact on operations, and all corrective action, to the other Party of any Emergency or Network Security Condition which may be reasonably anticipated to affect the other Party's equipment, facilities or operations. Either Party may take reasonable and necessary action, both on its own and the other Party's system, equipment, and facilities, to prevent, avoid or mitigate injury, danger, damage or loss to its own equipment and facilities, or to expedite restoration of service; provided however, that the Party taking such action shall give the other Party prior notice, if at all possible, before taking any action on the other Party's system, equipment, or facilities.

11.4 In the event of an Emergency or Network Security Condition contemplated by Section 11.3, each Party shall provide the other with such information, documents, and data necessary for operation of the Transmission System and Distribution System, including, without limitation, such information which is to be supplied to any Governmental Authority, NERC, ECAR, or Transmission System Operations Center or Distribution System Control Center.

11.5 In order to continue interconnection of the Distribution System and Transmission System, each Party shall promptly provide the other Party with all relevant information, documents, or data regarding the Distribution System and the Transmission System that would be expected to affect the Distribution System or Transmission System, and which is reasonably requested by NERC, ECAR, or any Governmental Authority.

11.6.For routine maintenance and inspection activities on either Parties system that will require major equipment or system outages, and could impact the other Party's system, the Party performing the same shall provide the other Party with not less than seventy-two (72) hours prior notice, if practicable; provided that the provisions of Section 3.9 remain applicable to the outages, and said notice is in addition to, and does not substitute for, the requirements of Section 3.9 (maintenance and inspection activities in generating plant substations require 20 working days notification).

11.7 Transmission Provider shall notify Local Distribution Company prior to entering Local Distribution Company's facilities for routine measurements, inspections and meter reads in accordance with the requirements of Section 11.6. Local Distribution Company shall notify Transmission Provider prior to entering Transmission Provider's facilities, including switchyards, for routine maintenance, operations, measurements, inspections and meter reads, in accordance with the requirements of Section 11.6.

11.8 Each Party shall provide prompt verbal notice to the other Party of any system alarm that applies to the other Party's equipment, unless the system alarm is automatically sent to the other Party.

11.9 Each Party shall provide a report or a copy of the data from a system events recorder, SCADA system sequence of events or digital fault recorder that applies to the other Party's equipment.

11.10 Each Party agrees to immediately notify the other Party verbally, and then in writing, of any labor dispute or anticipated labor dispute of which its management has actual Knowledge that might reasonably be expected to affect the operations of the other Party with respect to this Agreement.

ARTICLE 12. Safety

12.1 Each Party agrees that all work performed by either Party that may reasonably be expected to affect the other Party shall be performed in accordance with Good Utility Practice and all applicable laws, regulations, safety standards, practices and procedures and other requirements pertaining to the safety of Persons or property, (including, but not limited to those of the Occupational Safety and Health Administration, the National Electrical Safety Code and those developed or accepted by Transmission Provider and Local Distribution Company for use on their respective systems) when entering or working in the other Party's property or facilities or switching area. A Party performing work within the boundaries of the other Party's facilities must abide by the safety rules applicable to the site.

12.2 Each Party shall be solely responsible for the safety and supervision of its own employees, agents, representatives, and subcontractors.

12.3 Transmission Provider shall immediately report any injuries that occur while working on the Local Distribution Company's property or facilities or switching area to appropriate agencies and the Local Distribution Company's Site Representative. Local Distribution Company shall

immediately report any injuries that occur while working on the Transmission Provider's property or facilities or switching area to appropriate agencies and the Transmission Provider's Site Representative. Each Party will provide the other with its clearing/tagging/lockout procedures. For clearances requested or initiated by the Local Distribution Company on the Local Distribution Company's equipment that utilizes the Transmission Provider's equipment as an isolation device, Local Distribution Company procedures shall govern. For clearances requested or initiated by the Transmission Provider on the Transmission Provider's' equipment that utilizes the Local Distribution Company's equipment as an isolation device, Transmission Provider procedures shall govern. Under no circumstances shall either Party remove the other Party's protective tags without proper authorization.

ARTICLE 13. Environmental Compliance and Procedures

13.1 Release Prevention and Response. Each Party shall notify the other Party, verbally within 24 hours upon discovery of any Release of any Regulated Substance caused by the Party's operations or equipment that impacts the property or facilities of the other Party, or which may migrate to, or adversely impact the property, facilities or operations of the other Party and shall promptly furnish to the other Party copies of any reports filed with any governmental agencies addressing such events. Such verbal notification shall be followed by written notification within five (5) days. The Party responsible for the Release of any Regulated Substance on the property or facilities of the other Party, or which may migrate to, or adversely impact the property, facilities or operations of the other Party shall be responsible for: (1) the cost and completion of reasonable remediation or abatement activity for that Release, and; (2) required notifications to governmental agencies and submitting of all reports or filings required by environmental laws for that Release. Advance written notification (except in Emergency situations, in which verbal, followed by written notification, shall be provided as soon as practicable) shall be provided to the other Party by the Party responsible for any remediation or abatement activity on the property or facilities of the other Party, or which may adversely impact the property, facilities, or operations of the other Party. Except in Emergency situations such remediation or abatement activity shall be performed only with the consent of the Party owning the affected property or facilities.

13.2 The Parties agree to coordinate, to the extent necessary, the preparation of site plans, reports, environmental permits, clearances and notifications required by federal and state law or regulation, including but

not limited to Spill Prevention, Control and Countermeasures (SPCC), Storm Water Pollution Prevention Plans (SWPP), Act 451 Part 31 Part 5 Rules, CERCLA, EPCRA, TSCA, soil erosion and sedimentation control plans (SESC) or activities, wetland or other water-related permits, threatened or endangered species reviews or management and archeological clearances or notifications required by any regulatory agency or competent jurisdiction. Notification of permits applied for and/or received will occur in a timeframe manner suitable to the interests of both Parties.

ARTICLE 14. Billings and Payment

14.1 Any invoices payable under this Agreement shall be provided to the other Party under this Agreement during the preceding month. Invoices 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 within twenty (20) days of the invoice date, 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 the other Party, or by wire transfer to a bank of the Party being paid, provided that payments expressly required by this Agreement to be mailed shall be mailed in accordance with Section 14.2.

14.2 Any payments required to be made by Local Distribution Company under this Agreement shall be made to Transmission Provider at the following address:

Michigan Electric Transmission Company, LLC

P.O. Box 673971

Detroit, MI 48267-3971

Any payments required to be made by Transmission Provider under this Agreement shall be made to Local Distribution Company at the following address:

Consumers Energy Company

One Energy Plaza

Jackson, MI 49201

Attention: Treasurer

14.3 The rate of interest on any amount not paid when due shall be equal to the Interest Rate in effect at the time such amount became due. Interest on delinquent amounts shall be calculated from the due date of the invoice to the date of the payment. When payments are made by mail, invoices shall be considered as having been paid on the date of receipt by the other Party. Nothing contained in this article is intended to limit either Party's remedies under Article 21 of this Agreement.

14.4 Payment of an invoice shall not relieve the paying Party from any responsibilities or obligations it has under this Agreement, nor shall such payment constitute a waiver of any claims arising hereunder.

14.5 If all or part of any bill is disputed by a Party, that Party shall promptly pay the amount that is not disputed and provide the other Party a reasonably detailed written explanation of the basis for the dispute pursuant to Article 26. 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 at the Interest Rate through the date on which payment is made, within ten (10) business days of such resolution.

14.6 Subject to the Confidentiality provisions of Article 20, within two (2) years following a calendar year, during normal business hours, Local Distribution Company and Transmission Provider shall have the right to audit each other's accounts and records pertaining to transactions under this Agreement that occurred during such calendar year at the offices where such accounts and records are maintained; provided that the audit shall be limited to those portions of such accounts and records that reasonably relate to the services provided to the other Party under this Agreement for said calendar year. The Party being audited shall be entitled to review the audit report and any supporting materials. To the extent that audited information includes Confidential Information, the auditing Party shall keep all such information confidential pursuant to Article

20.

14.7 Neither Party shall be responsible for the other Party's costs of collecting amounts due under this Agreement, including attorney fees and expenses and the expenses of arbitration.

ARTICLE 15. Applicable Regulations and Interpretation

15.1 Each Party's performance under this Agreement is subject to the condition that all requisite governmental and regulatory approvals for such performance are obtained in form and substance satisfactory to the other Party in its reasonable judgment. Each Party shall exercise Due Diligence and shall act in good faith to secure all appropriate approvals in a timely fashion.

15.2 This Agreement and all rights, obligations, and performances of the Parties hereunder, are subject to present or future state or federal laws, regulations, or orders properly issued by state or federal bodies having jurisdiction. When not in conflict with or pre-empted by Federal law, this Agreement shall be interpreted pursuant to the laws of the State of Michigan, exclusive of its conflicts of law principles.

ARTICLE 16. Force Majeure

16.1 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 equipment, 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.

16.2 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 Transmission Provider's and Local Distribution Company's obligation under Section 16.3 of this Agreement to provide protection 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.

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

ARTICLE 17. Indemnification And Limitation on Liability

17.1 Each Party shall at all times assume all liability for, and shall indemnify and save the other Party 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 facilities or facilities controlled by it, unless caused by the sole negligence, or intentional wrongdoing, of the other Party.

17.2 EXCEPT AS SET FORTH IN SECTION 8.3, NEITHER PARTY SHALL BE LIABLE TO THE OTHER FOR ANY SPECIAL, INCIDENTAL, EXEMPLARY, PUNITITIVE 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 18. Insurance

18.1 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.

2. A Party may, at its option, [A] be an approved self-insurer by the State of Michigan 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.

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 Party 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 19. Several Obligations

19. Except where specifically stated in this Agreement to be otherwise, the duties, obligations and liabilities of the Parties are intended to be several and not joint or collective. Nothing contained in this Agreement shall ever be construed to create an association, trust, partnership, or joint venture or to impose a trust or partnership duty, obligation or liability or agency relationship on or with regard to either Party. Each Party shall be individually and severally liable for its own obligations under this Agreement.

ARTICLE 20. Confidentiality

20.1(a) “Confidential Information” shall mean any confidential, proprietary or trade secret information of a plan, specification, pattern, procedure, design, device, list concept, policy or compilation relating to the present or planned business of a Party, which is designated in good faith as Confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection or otherwise. Confidential Information shall include, without limitation, all information relating to a Party's technology, research and development, business affairs, and pricing, customer-specific load data that constitutes a trade secret,

and any information supplied by either of the Parties to the other prior to the execution of this Agreement.

(b) General. Each Party will hold in confidence any and all Confidential Information unless (1) compelled to disclose such information by judicial or administrative process or other provisions of law or as otherwise provided for in this Agreement, or (2) to meet obligations imposed by FERC or by a state or other federal entity or by membership in NERC or ECAR (including other Transmission Providers). Information required to be disclosed under (b)(1) or (b)(2) above, does not, by itself, cause any information provided by Local Distribution Company to Transmission Provider to lose its confidentiality. To the extent it is necessary for either Party to release or disclose such information to a third party in order to perform that Party's obligations herein, such Party shall advise said third party of the confidentiality provisions of this Agreement and use its best efforts to require said third party to agree in writing to comply with such provisions. Transmission Provider will develop and file with FERC standards of conduct relating to the sharing of a market-related Confidential Information with and by Transmission Provider employees.

(c) Term: During the term of this Agreement, and for a period of three (3) years after the expiration or termination of this Agreement, except as otherwise provided in this Article 20, each Party shall hold in confidence and shall not disclose to any Person Confidential Information.

(a) Standard of Care: Each Party shall use at least the same standard of care to protect Confidential Information it receives as that it uses to protect its own Confidential Information from unauthorized disclosure, publication or dissemination.

20.2 Scope: Confidential Information shall not include information that the receiving Party can demonstrate: (1) is generally available to the public other than as a result of disclosure by the receiving Party (2) was in the lawful possession of the receiving Party on a non-confidential basis prior to receiving it from the disclosing Party; or (3) was supplied to the receiving Party without restriction by a third party, who, to the Knowledge of the receiving Party, after due inquiry was under no obligation to the disclosing Party to keep such information confidential; (4) was independently developed by the receiving Party without reference to Confidential Information of the disclosing Party; (5) is, or becomes, publicly known, through no wrongful act or omission of the receiving Party or breach of this Agreement; or (6) is required, in accordance with Section 20.1(b) of this Agreement, to be disclosed by any federal or

state government or agency or is otherwise required to be disclosed by law or subpoena, or is necessary in any legal proceeding establishing rights and obligations under this Agreement. Information designated as Confidential Information will no longer be deemed confidential if the Party that designated the information as confidential notifies the other Party that it no longer is confidential.

20.3 Order of Disclosure. If a court or a government agency or entity with the right power, and apparent authority to do so requests or requires either Party, by subpoena, oral deposition, interrogatories, requests for production of documents, administrative order, or otherwise, to disclose Confidential Information, that Party shall provide the other Party with prompt notice of such request(s) or requirement(s) so that the other Party may seek an appropriate protective order or waive compliance with the terms of this Agreement. The notifying Party shall have no obligation to oppose or object to any attempt to obtain such production except to the extent requested to do so by the disclosing Party and at the disclosing Party's expense. If either Party desires to object or oppose such production, it must do so at its own expense. The disclosing Party may request a protective order to prevent any Confidential Information from being made public. Notwithstanding the absence of a protective order or waiver, the Party may disclose such Confidential Information which, in the opinion of its counsel, the Party is legally compelled to disclose. Each Party will use reasonable effort to obtain reliable assurance that confidential treatment will be accorded any Confidential Information so furnished.

20.4 Use of Information or Documentation. Each Party may utilize information or documentation furnished by the disclosing Party and subject to Section 20.1 in any proceeding under Article 26 or in an administrative agency or court of competent jurisdiction addressing any dispute arising under this Agreement, subject to a confidentiality agreement with all participants (including, if applicable, any arbitrator) or a protective order.

20.5 Remedies Regarding Confidentiality. The Parties agree that monetary damages by themselves will be inadequate to compensate a Party for the other Party's breach of its obligations under this article. Each Party accordingly agrees that the other Party is entitled to equitable relief, by way of injunction or otherwise, if it breaches or threatens to breach its obligations under this article.

ARTICLE 21. Breach, Default and Remedies

21.1 General. A breach of this Agreement (“Breach”) shall occur upon the failure by a Party to perform or observe a material term or condition of this Agreement. A 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 Section 21.4.

21.2 Events of Breach. A Breach of this Agreement shall include:

(a) The failure to pay any amount when due;

(b) 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;

(c) A Party's abandonment of its work or the facilities contemplated in this Agreement;

(d) If a Party: (1) becomes insolvent; (2) 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; (3) makes a general assignment for the benefit of its creditors; or (4) consents to the appointment of a receiver, trustee or liquidator;

(e) Failure of either Party to provide information or data to the other Party 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.

21.3 Continued Operation. Except as specifically provided in this Agreement, in the event of a Breach or Default by either Party, the Parties shall continue to operate and maintain, as applicable, facilities and appurtenances that are reasonably necessary for the Transmission Provider to operate and maintain the Transmission System, or the Local Distribution Company to operate and maintain the Distribution System, in a safe and reliable manner.

21.4 Cure and Default. Upon the occurrence of an event of Breach, 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 a Party to this Agreement identifies in writing to the other Party 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. In the event of a Default, the non-Defaulting Party has the right to take whatever action at law or equity as may be permitted under this Agreement.

21.5 Right to Compel Performance. Notwithstanding the foregoing, upon the occurrence of an event of Default, the non-Defaulting Party shall be entitled to 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 exercise such other rights and remedies as it may have in equity or at law.

ARTICLE 22. Term

22.1 Term. This Agreement shall become effective as of the Effective Date and shall continue in full force and effect so long as any Interconnection Point is connected to the Transmission System, except that it may be terminated by mutual agreement of the Parties.

22.2 Material Adverse Change.

(a) In the event of a material change in law or regulation that adversely affects, or may reasonably be expected to adversely affect, either Party's performance under this Agreement, including but not limited to the following:

(i) this Agreement is not accepted for filing by the FERC without material modification or condition;

(ii) NERC or ECAR prevents, in whole or in part, either Party from performing any provision of this Agreement in accordance with its terms; or

(iii) The FERC, the United States Congress, any state, or any federal or state regulatory agency or commission implements any change in any law, regulation, rule or practice which

materially affects or is reasonably expected to materially affect either Party's ability to perform under this Agreement.

The Parties will negotiate in good faith any amendment or amendments to the Agreement necessary to adapt the terms of this Agreement to such change in law or regulation, and the Transmission Provider shall file such amendment or amendments with FERC.

(b) If the Parties are unable to reach agreement on any such amendments, then the Parties shall continue to perform under this Agreement to the maximum extent possible, taking all reasonable steps to mitigate any adverse effect on each other resulting from the Event. If the Parties are unable to reach agreement on any such amendments, Transmission Provider shall have the right to make a unilateral filing with FERC to modify this Agreement pursuant to Section 205 of the Federal Power Act and Local Distribution Company shall have the right to make a unilateral filing with FERC to modify this Agreement pursuant to Section 206 of the Federal Power Act. Each Party shall have the right to protest any such filing by the other Party and to participate fully in any proceeding before FERC.

22.3 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 23. Assignment/Change in Corporate Identity

23.1 Transmission Provider Assignment Rights. Transmission Provider may not assign this Agreement or any of its rights, interests, or obligations hereunder without the prior written consent of Local Distribution Company, which consent shall not be unreasonably withheld; provided however, that Transmission Provider may assign this Agreement or any of its rights or obligations hereunder without the prior consent of Local Distribution Company and may assign this Agreement to any entity(ies) in connection with a merger, consolidation, or reorganization, provided that the surviving entity(ies) or assignee owns the Transmission System, agrees in writing to be bound by all the obligations and duties of Transmission Provider provided for in this Agreement and the assignee's creditworthiness is equal to or higher than that of Transmission Provider.

23.2 Local Distribution Company Assignment Rights. Local Distribution Company may not assign this Agreement or any of its rights, interests or obligations hereunder without the prior written consent of Transmission Provider, which consent shall not be unreasonably withheld; provided however, that Local Distribution Company may, without the consent of Transmission Provider, and by providing prior reasonable notice under the circumstances to Transmission Provider, assign, this Agreement to any entity(ies) in connection with a merger, consolidation, or reorganization, provided that the surviving entity(ies) or assignee owns the Local Distribution Company, agrees in writing to be bound by all the obligations and duties of Local Distribution Company provided for in this Agreement and the assignee's creditworthiness is equal to or higher than that of Local Distribution Company.

23.3 Assigning Party to Remain Responsible. Any assignments authorized as provided for in this article will not operate to relieve the Party assigning this Agreement or any of its rights, interests or obligations hereunder of the responsibility of full compliance with the requirements of this Agreement unless (a) the other Party consents, such consent not to be unreasonably withheld,

and (b) the assignee agrees in writing to be bound by all of the obligations and duties of the assigning Party provided for in this Agreement.

23.4 This Agreement and all of the provisions hereof are binding upon, and inure to the benefit of, the Parties and their respective successors and permitted assigns.

ARTICLE 24. Subcontractors

24.1 Nothing in this Agreement shall prevent the Parties from utilizing the services of subcontractors as they deem appropriate; provided, however, the Parties agree that, where applicable, all said subcontractors shall comply with the terms and conditions of this Agreement.

24.2 Except as provided herein, the creation of any subcontract relationship shall not relieve the hiring Party of any of its obligations under this Agreement. Each Party shall be fully responsible to the other Party for the acts and/or omissions of any subcontractor it hires as if no subcontract had been made. Any obligation imposed by this Agreement upon the Parties, where applicable, shall be equally binding upon and shall be construed as having application to any subcontractor.

24.3 No subcontractor is intended to be or shall be deemed a third-party beneficiary of this Agreement.

24.4 The obligations under this Article 26 shall not be limited in any way by any limitation on subcontractor's insurance.

24.5 Each Party shall require its subcontractors to comply with all federal and state laws regarding insurance requirements and shall maintain standard and ordinary insurance coverages.

ARTICLE 25. Dispute Resolution

Any dispute between the parties arising out of or relating to this Contract or the breach thereof shall be brought to the Administrative Committee. If the Administrative Committee can resolve the dispute, such resolution shall be reported in writing to and shall be binding upon the Parties. If the Administrative Committee cannot resolve the dispute within a reasonable time, the senior officer of Local Distribution Company or the senior officer of Transmission Provider may, by written notice to the senior officer of the other Party and the members of the Administrative Committee, withdraw the matter from consideration by the Administrative Committee and submit the same for resolution to the senior officers of the Parties. If the senior officers of the Parties agree to a resolution of the matter, such resolution shall be reported in writing to, and shall be binding upon, the Parties; but if said senior officers fail to resolve the matter within five (5) Business Days after its submission to them, then the Parties agree to try in good faith to settle the dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules before resorting to litigation.

ARTICLE 26. Miscellaneous Provisions

26.1 This Agreement shall constitute the entire Agreement between the Parties hereto relating to the subject matter hereof. In all other respects, special contracts or superseding rate schedules shall govern Transmission Provider's transmission service to Local Distribution Company.

26.2 No failure or delay on the part of Transmission Provider or Local Distribution Company in exercising any of its rights under this Agreement, no partial exercise by either Party of any of its rights under this Agreement, and no course of dealing between the Parties shall constitute a waiver

of the rights of either Party under this Agreement. Any waiver shall be effective only by a written instrument signed by the Party granting such waiver, and such shall not operate as a waiver of, or estoppel with respect to, any subsequent failure to comply therewith.

26.3 Nothing in this Agreement, express or implied, is intended to confer on any other Person except the Parties hereto any rights, interests, obligations or remedies hereunder.

26.4 In the event that any clause or provision of this Agreement or any part hereof shall be held to be invalid, void, or unenforceable by any court or Governmental Authority of competent jurisdiction, said holding or action shall be strictly construed and shall not affect the validity or effect of any other provision hereof, and the Parties shall endeavor in good faith to replace such invalid or unenforceable provisions with a valid and enforceable provision which achieves the purposes intended by the Parties to the greatest extent permitted by law.

26.5 The article and section headings herein are inserted for convenience only and are not to be construed as part of the terms hereof or used in the interpretation of this Agreement.

26.6 In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the Parties and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of authorship of any of the provisions of this Agreement. Any reference to any federal, state, local, or foreign statute or law shall be deemed also to refer to all rules and regulations promulgated thereunder, unless the context requires otherwise. The word “including” in this Agreement shall mean including without limitation.

26.7 This Agreement may be executed in one or more counterparts, each of which shall be deemed an original.

26.8 Each Party shall act as an independent contractor with respect to the provision of services hereunder.

IN WITNESS WHEREOF, Transmission Provider and Local Distribution Company have caused this instrument to be executed by their duly authorized representatives as of the day and year first above written.

CONSUMERS ENERGY COMPANY

By: _/s/ Garrick J. Rochow ________________

Name: Garrick J. Rochow

Title: Vice President of Energy Delivery

MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC

By: ITC Holdings Corp., its manager

By: _/s/ Gregory Ioanidis____________________

Name: Gregory Ioanidis

Title: Vice President

EXHIBIT 1 - Interconnection Points (Substations) Addendum 7, Final 11/28/12

Substation

1 Abbe

2 Acme (04/10)

3 Alcona

4 Alder Creek

5 Alger

6 Algoma

7 Alma

8 Almeda

9 Alpena

10 Alpine

11 Amber

12 American Bumper

13 Arthur (06/06)

14 Aubil Lake

15 Backus

16 Bagley

17 Bangor

18 Baraga (12/07)

19 Bard Road

20 Barnum Creek

21 Barry

22 Bass Creek

23 Batavia

24 Bay Road

25 Bayberry

26 Beals Road

27 Becker

28 Beecher

29 Begole

30 Bell Road

31 Bennington

32 Beveridge

33 Bilmar

34 Bingham

35 Birchwood (06/12)

36 Black River

37 Blackman

38 Blackstone

39 Blinton

40 Blue Water

41 Bluegrass

42 Boardman

43 Boxboard

44 Bricker

45 Brickyard

46 Briggs & Stratton

47 Broadmoor

48 Bronco

49 Broughwell

50 Buck Creek

51 Bullock

52 Busch Road (02/08)

53 Calhoun

54 Camelot Lake

55 Campbell 138

56 Canal

57 Cannon

58 Carpenter Rd (08/06)

59 Carter

60 Cedar Springs

61 Cement City

62 Chase

63 Cheesman

64 Chicago

65 Churchill

66 Clare

67 Claremont

68 Clearwater

69 Cleveland

70 Club

71 Cobb

72 Cochran

73 Cole Creek

74 Colony Farm

75 Convis

76 Cork Street

77 Cornell

78 Cottage Grove

79 Covert

80 Cowan Lake

81 Crahen (10/07)

82 Croton

83 David

84 Dean Road

85 Deja

86 Delaney

87 Delhi

88 Denso Jackson

89 Derby

90 Discovery Way (04/11)

91 Dorr Corners

92 Dort

93 Dow Corning

94 Dowling

95 Drake Road

96 Duffield Rd

97 Dupont

98 Duquite

99 Dutton

100 East Paris

101 East Tawas

102 Easton

103 Edenville

104 Ellis

105 Emmet

106 Englishville

107 Eureka

108 Farr Road

109 Felch Road

110 Filer City

111 Fillmore

112 Forty Fourth Street

113 Foundry

114 Four Mile

115 Gaines (05/06)

116 Gallagher

117 Garfield

118 Gaylord

119 Geddes(04/08)

120 Gleaner

121 Grand Blanc BOC

122 Gray Road(04/10)

123 Greenwood

124 Grey Iron

125 Grodi Road

126 Grout

127 Hackett

128 Hagadorn

129 Hager Park

130 Halsey

131 Haring

132 Harvard Lake (06/09)

133 Hazelwood

134 Hemphill

135 Hendershot

136 Higgins

137 Hillman Cogen

138 Hodenpyl

139 Holland Road

140 Hotchkiss

141 HSC

142 Hubbard Lake (12/07)

143 Hubbardston Road(06/10)

144 Hudsonville

145 Hughes Road

146 Hull Street

147 Iosco

148 Island Road

149 Jamestown

150 Karn 138

151 Kentwood

152 Keystone

153 Kinderhook (05/07)

154 Kipp Road

155 Kraft

156 Lafayette

157 Laundra (05/07)

158 Lawndale

159 Layton

160 Leoni

161 Letts Road

162 Lewiston

163 Lindbergh

164 Livingston Peaker

165 Lovejoy

166 Ludington

167 Malleable (decomm 10/07)

168 Manlius

169 Marquette

170 McGulpin

171 MCV

172 Meadowbrooke

173 Mecosta

174 Michigan

175 Michigan Power (MPLP)

176 Milham

177 Mio

178 Monitor

179 Moore Road

180 Morrow

181 Mullins

182 Neff Road

183 Nineteen Mile Road

184 North Belding

185 North Corunna

186 Northern Fibre

187 Nugent Sand

188 Oakland

189 Oceana

190 Orr Road(03/09)

191 Packard

192 Palisades

193 Parkville (08/12)

194 Parr Road

195 Parshallville

196 Pasadena

197 Pavilion

198 Pearline (06/11)

199 Pettis Road

200 Pigeon River/Rondo

201 Pingree (10/08)

202 Piston Ring

203 Plaster Creek

204 Plum (07/10)

205 Plymouth Street

206 Plywood

207 Port Calcite

208 Port Sheldon

209 Porter

210 Portsmouth

211 Price Road (09/07)

212 Progress Street

213 Race Street

214 Raisin

215 Ransom

216 Ratigan (CWIP)

217 Renaissance

218 Rice Creek

219 Riggsville

220 Rivertown

221 Riverview

222 Rockport/Presque Isle

223 Roedel Road

224 Rogue River (06/07)

225 Saginaw River

226 Samaria

227 Sanderson

228 Savidge

229 Scott Lake

230 Seamless East/Seamless

231 Simpson (08/12)

232 Sonoma (05/06)

233 Spaulding

234 Spruce Road

235 Stacey

236 Stamping Plant

237 Sternberg Road (05/11)

238 Steelcase

239 Stonegate

240 Stover

241 Stronach

242 Summerton

243 Thetford 138

244 Tihart

245 Tinsman

246 Tippy

247 Titus Lake

248 Trillium (06/07)

249 Trowbridge

250 Twelfth Street

251 Twilight

252 Twining

253 Upjohn

254 Van Atta

255 Van Buren(06/08)

256 Vanderbilt

257 Vernon

258 Verona

259 Vevay

260 Viking Lincoln

261 Vrooman

262 Wackerly

263 Warner

264 Warren

265 Washtenaw

266 Wayland

267 Weadock

268 Wealthy Street

269 West Fenton (05/07)

270 Wexford

271 White Lake

272 White Road

273 Whiting

274 Whittemore

275 Willard

276 Withey Lake (05/06)

277 Zeeland

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

New interconnections have (month/year) in-service date after substation name if their in-service date was after May of 2002.

Note, this list of substations is not necessarily a list of the true points of facility ownership change between the Transmission Provider and the Local Distribution Company. This also is not a complete listing of all Local Distribution Company substations that have a 138 kV high-side supply voltage

EXHIBIT 2 - Contact Information For Local Distribution Company's

Representatives and Transmission

Provider's Representatives

Local Distribution Company

Consumers Energy Company

4000 Clay Ave SW, PO Box 201

Grand Rapids, MI 49501-0201

Attn: Executive Manager of System Planning and Control

Transmission Provider

Michigan Electric Transmission Company, LLC:

27175 Energy Way

Novi, MI 48377

Attn: Legal Department - Contracts

EXHIBIT 3

SPECIAL MANUFACTURING CONTRACTS INFLUENCED BY TRANSMISSON SYSTEM
CUSTOMER		SUBSTATION	PAYMENT PER DISRUPTION EVENT
			INTERRUPTION	VOLTAGE SAG
GM		BUICK STEWART	$150,000	NOT APPLICABLE
		MALLEABLE	$150,000	NOT APPLICABLE
		FLORENCE ST.	$150,000	NOT APPLICABLE
		GRAND BLANC BOC	$100,000	NOT APPLICABLE
		GREY IRON	$150,000	NOT APPLICABLE
		STAMPING PLANT	$100,000	NOT APPLICABLE
DELPHI		HOLLAND RD.	$150,000	NOT APPLICABLE
NOTES FOR GM & DELPHI:
	1. NO PAYMENTS FOR VOLTAGE AGS.
	2. CUMULATIVE ANNUAL PAYMENT IS CAPPED AT $3,000,000.
	3. INITIAL TERM OF GM AND DELPHI CONTRACTS EXPIRE IN 2005.
	4. CONTRACTS MAY BE EXTENDED TO 2010 BY MUTUAL AGREEMENT.
					EVENT #

DOW CORNING		CARTER	($15,000	$(15,000)	no events
			$15,000	—	1st /yr
			$15,000	$15,000	2nd/yr
			$55,000	NOT APPLICABLE	3rd/yr
DOW CORNING		DOW CORNING	($25,000	$(25,000)	no events
			$25,000	—	1st /yr
			$35,000	$25,000	2nd/yr
			$105,000	NOT APPLICABLE	3rd/yr
HEMLOCK		HSC	($40,000	$(20,000)	no events
SEMICONDUCTOR			$40,000	—	1st /yr
			$60,000	$20,000	2nd/yr
			$150,000	NOT APPLICABLE	3rd/yr
HEMLOCK		SILICON	NOT APPLICABLE	$(15,000)	no events
SEMICONDUCTOR			NOT APPLICABLE	—	1st /yr
			NOT APPLICABLE	—	2nd/yr
			NOT APPLICABLE	—	3rd/yr
			NOT APPLICABLE	$15,000	4th/yr
NOTES FOR DOW CORNING & HEMLOCK SEMICONDUCTOR:
	1. IF NO EVENTS IN A YEAR, PAYMENT IS MADE TO CONSUMERS.
	2. MAXIMUM # OF PAYABLE EVENTS/YR IS 3 FOR INTERRUPTIONS & 1 FOR SAGS.
	3. WEATHER RELATED EVENTS ARE NOT PAYABLE.

EXHIBIT 4 - Metering Specifications

Performance criteria:

1. Meters shall meet or exceed the latest version of ANSI C12.16 (Standard for Solid State Electricity Meters) specifications for solid state metering.

2. Current transformers used for metering shall meet or exceed an accuracy class of 0.3%. Secondary connected burdens shall not exceed rated burden of any current transformer. Current transformers shall comply with most current applicable ANSI Standards including C57.13 (IEEE Standard Requirements for Instrument Transformers) and C12.11 (Instrument Transformers for Revenue Metering 10 kV BIL through 350 kV BIL). Meter installations shall comply with manufacturer's accuracy and burden class information on the nameplate of each device.

3. Voltage transformers used for metering shall meet or exceed an accuracy class of 0.3%. Secondary connected burdens shall not exceed rated burden of any voltage transformer. Voltage transformers shall comply with most current applicable ANSI Standards including C57.13 (IEEE Standard Requirements for Instrument Transformers), and C12.11 (Instrument Transformers for Revenue Metering 10 kV BIL through 350 kV BIL). Meter installations shall comply with manufacturer's accuracy and burden class information on the nameplate of each device.

4. PT secondary circuits shall have a disconnect switch installed which provides a visible air gap for worker safety, and which allows for attachment of a protective safety tag.

EXHIBIT 5

Addendum 5 - Final 11/28/12

For ownership changes since August 7, 2007, refer to the drawings in each Party's Drawing Management System (DMS), as discussed in Section 3.2 of this Agreement.

The WDs of the following substations have been revised since the last update of 11/28/11 (Addendum 4):

Consumers Energy (CE)Michigan Electric Transmission Company (METC)

AlmaBullock

BataviaClaremont

BeecherCobb

BullockCornell

ClaremontMcGulpin

Cobb PlantTippy

CornellTwining

CrotonVerona

DelhiWhiting

Emmet

Four Mile

Gaylord

Lawndale

McGulpin

Moore Road

Morrow

Riverview

Saginaw River

Spaulding

Stover

Tippy

Twining

Verona

Weadock

Wealthy Street

Wexford

Whiting

EXHIBIT 6 - Jointly Owned Assets Ownership by Percent of Major Equipment Addendum 7 - Final 11/28/12

Substations

Jointly Owned Assets

 Percentage Split by Major Equipment Count

Substation Name	Distribution	Transmission	Generation Owned by Local Distribution Company	Third-Party Assets	Last Revision Date
Alma	66.67	33.33			10/24/2003
Bard Road	41.67	58.33			6/10/2010
Batavia	63.64	36.36			10/24/2003
Beals Road	84.62	15.38			6/10/2010
Beecher	82.50	17.50			11/28/2011
Bingham	90.91	9.09			11/28/2011
Black River	66.67	25.93		7.40	11/28/2011
Blackstone	70.83	29.17			11/28/2011
Bullock	76.00	24.00			11/20/2008
Claremont	68.00	32.00			5/1/2002
Cobb Plant	47.22	25.00	27.78		5/1/2002
Cornell	66.67	33.33			11/28/2011
Croton	54.54	31.82			6/10/2010
Delhi	61.90	38.10			10/24/2003
Dort2	68.18	31.82	13.64		11/28/2011
Emmet	92.31	7.69			5/1/2002
Eureka	88.89	11.11			6/10/2010
Felch Road	83.33	16.67			3/31/2006
Four Mile	73.33	26.67			3/16/2006
Gaylord	44.44	44.44	11.12		11/20/2008
Halsey	76.92	23.08			10/24/2003
Hemphill	64.29	35.71			11/28/2011
HSC	33.33	66.67			11/28/2011
Iosco	83.33	16.67			5/30/2007
Lawndale	70.59	29.41			11/28/2012
Marquette	62.5	37.50			11/28/2012

McGulpin	55.56	44.44			11/28/2011
Mecosta	86.67	13.33			11/28/2011
Milham	70.59	29.41			11/28/2012
Moore Road3	64.65	10.00		25.35	8/7/2007
Morrow1	63.33	30.00	6.67		11/28/2012
North Belding	66.67	33.33			10/24/2003
Oakland	87.50	12.50			10/24/2003
Ransom	88.89	11.11			1/5/2005
Rice Creek	92.86	7.14			10/24/2003
Riggsville	75.00	25.00			11/20/2008
Riverview	93.75	6.25			10/24/2003
Saginaw River	42.86	57.14			11/28/2012
Spaulding	60.00	40.00			3/31/2006
Stover	85.71	14.29			11/20/2008
Stronach2	66.67	33.33			5/24/2004
Tihart	66.67	33.33			11/28/2012
Tippy	33.33	66.67			11/13/2002
Twining	76.92	23.08			5/1/2002
Verona	60.87	39.13			3/31/2006
Weadock	35.14	24.32	40.54		3/16/2006
Wealthy Street	86.11	13.89			3/16/2006
Wexford	92.86	7.14			11/28/2011
White Lake	81.25	18.75			10/24/2003
Whiting	31.58	31.58	36.84		8/7/2007

EX-31.1

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, Joseph L. Welch, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 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: April 24, 2013

/s/ Joseph L. Welch

Joseph L. Welch

President and Chief Executive Officer

EX-31.2

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, Cameron M. Bready, certify that:

1. I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 2013 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: April 24, 2013

/s/ Cameron M. Bready

Cameron M. Bready

Executive Vice President and Chief Financial Officer

EX-32

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 March 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Joseph L. Welch, President and Chief Executive Officer of the Registrant, and Cameron M. Bready, Executive Vice President and Chief Financial Officer 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: April 24, 2013

/s/ Joseph L. Welch

Joseph L. Welch

President and Chief Executive Officer

/s/ Cameron M. Bready

Cameron M. Bready

Executive Vice President and Chief Financial Officer

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Additional Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			3 Months Ended
	Dec. 31, 2013 Retirement Plan Benefits	Dec. 31, 2013 Supplemental Retirement Benefit Plans	Mar. 31, 2013 Other Postretirement Benefit Plan	Mar. 31, 2013 Defined Contribution Plan	Mar. 31, 2012 Defined Contribution Plan
Retirement Benefits Disclosure
Employer contribution	$ 6.9	$ 0.6
Expected additional current year contribution			3.8
Employer match contribution				$ 1.7	$ 1.3

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DEBT Schedule of Revolving Credit Agreements (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Revolving Credit Agreement
Total available capacity	$ 725.0
Outstanding balance	291.3	[1]
Unused capacity	433.7
ITC Holdings
Revolving Credit Agreement
Total available capacity	200.0
Outstanding balance	0	[1]
Unused capacity	200.0
Commitment fee rate	0.25%	[2]
Original term	5 years
ITCTransmission
Revolving Credit Agreement
Total available capacity	100.0
Outstanding balance	2.5	[1]
Unused capacity	97.5
Weighted-average interest rate	1.40%
Commitment fee rate	0.125%	[2]
Original term	5 years
METC
Revolving Credit Agreement
Total available capacity	100.0
Outstanding balance	31.3	[1]
Unused capacity	68.7
Weighted-average interest rate	1.30%
Commitment fee rate	0.125%	[2]
Original term	5 years
ITC Midwest
Revolving Credit Agreement
Total available capacity	175.0
Outstanding balance	146.2	[1]
Unused capacity	28.8
Weighted-average interest rate	1.20%
Commitment fee rate	0.10%	[2]
Original term	5 years
ITC Great Plains
Revolving Credit Agreement
Total available capacity	150.0
Outstanding balance	111.3	[1]
Unused capacity	$ 38.7
Weighted-average interest rate	2.00%
Commitment fee rate	0.30%	[2]
Original term	4 years

[1] Included within long-term debt.

[2] Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.

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FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Assets Measured at Fair Value Subject to Three-Tier Hierarchy

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at March 31, 2013, 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	$	35,935	$	30,243		$	—
Mutual funds — fixed income securities	21,113		—			—
Mutual funds — equity securities	1,766		—			—
Interest rate swap derivatives	—		5,142			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(30,468		)	—
Total	$	58,814	$	4,917		$	—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2012, 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	$	13,127	$	10,037		$	—
Mutual funds — fixed income securities	21,332		—			—
Mutual funds — equity securities	1,612		—			—
Interest rate swap derivatives	—		2,725			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(31,507		)	—
Total	$	36,071	$	(18,745	)	$	—

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COMMITMENTS AND CONTINGENT LIABILITIES (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
FERC audit
Commitments and Contingent Liabilities
Estimated liability for refund and related interest	$ 12.8
ITCTransmission | Sales and use tax audit
Commitments and Contingent Liabilities
Use tax liability associated with exemptions taken	15.6
ITCTransmission | Sales and use tax audit | Audit period
Commitments and Contingent Liabilities
Use tax liability associated with exemptions taken	3.7
METC | Sales and use tax audit
Commitments and Contingent Liabilities
Use tax liability associated with exemptions taken	$ 11.0
ITC Midwest
Commitments and Contingent Liabilities
Rate of return on actual equity	12.38%
Reduced rate of return on actual equity	10.39%

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EARNINGS PER SHARE Additional Information (Details)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Earnings Per Share, Basic and Diluted [Abstract]
Outstanding stock options and ESPP shares	1,549,860	2,066,083
Anti-dilutive stock options excluded from diluted earnings per share calculation	356,730	214,993

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RECENT ACCOUNTING PRONOUNCEMENTS

3 Months Ended

Mar. 31, 2013

RECENT ACCOUNTING PRONOUNCEMENTS [Abstract]

RECENT ACCOUNTING PRONOUNCEMENTS

RECENT ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income

The guidance set forth by the Financial Accounting Standards Board (“FASB”) has been updated for the presentation of comprehensive income in financial statements. Under this guidance, we are required to (1) disclose the changes in accumulated other comprehensive income (“AOCI”) by component and (2) disclose the effects on the line items of net income of significant amounts reclassified out of AOCI. We adopted this guidance as of January 1, 2013. For the three months ended March 31, 2013, the requirements under (1) above are presented in the condensed consolidated statements of comprehensive income, however, there were no significant amounts reclassified out of AOCI that would require disclosure.

Balance Sheet Offsetting Requirements

The FASB has created new disclosure requirements regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires entities to disclose, at a minimum, the following information in tabular format, separately for assets and liabilities: (a) the gross amounts of those recognized assets and those recognized liabilities; (b) the amounts offset to determine the net amounts presented in the statement of financial position; (c) the net amounts presented in the statement of financial position; (d) the amounts subject to an enforceable master netting arrangement or similar agreement; and (e) the net amount after deducting the amounts in (d) from the amounts in (c). We adopted this guidance as of January 1, 2013. As of March 31, 2013, we did not have any material assets and liabilities that are subject to the new disclosure requirements.

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ENTERGY TRANSACTION (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
External Legal, Advisory and Financial Services Fees
Business Acquisition
Transaction related expenses	$ 8.7	$ 2.4
Internal Labor and Related Costs
Business Acquisition
Transaction related expenses	2.3	1.5
ITC Holdings
Business Acquisition
Ownership percentage of pro forma shares	49.90%
Entergy
Business Acquisition
Miles of transmission lines	15,400
Ownership percentage of pro forma shares	50.10%
Gross cash proceeds for assets	$ 1,775

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REGULATORY MATTERS Schedule of Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Schedule of Regulatory Assets and Liabilities
Non-current assets	$ 181,797	$ 180,378
Non-current liabilities	74,549	75,477
Revenue Accruals, Including Accrued Interest
Schedule of Regulatory Assets and Liabilities
Current assets	6,310
Non-current assets	14,594
Revenue Deferrals, Including Accrued Interest
Schedule of Regulatory Assets and Liabilities
Current liabilities	47,736
Non-current liabilities	33,479
Revenue Deferrals and Accruals, Including Accrued Interest
Schedule of Regulatory Assets and Liabilities
Ending balance	$ (60,311)	$ (72,168)

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REGULATORY MATTERS Changes in Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Revenue Deferrals and Accruals, Including Accrued Interest	Dec. 31, 2012 Revenue Deferrals and Accruals, Including Accrued Interest
Schedule of Regulatory Assets and Liabilities
Beginning balance		$ (60,311)	$ (72,168)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	11,766
Net revenue accrual for the three months ended March 31, 2013	687
Net accrued interest payable for the three months ended March 31, 2013	(596)
Ending balance		$ (60,311)	$ (72,168)

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SEGMENT INFORMATION (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012		Dec. 31, 2012
OPERATING REVENUES:
Operating revenues	$ 217,304		$ 196,713
INCOME BEFORE INCOME TAXES:
Income before income taxes	81,750		73,083
NET INCOME:
Net income	50,190		46,051
TOTAL ASSETS:
Assets	5,795,487		5,564,809		5,564,809
Regulated Operating Subsidiaries
OPERATING REVENUES:
Operating revenues	217,379		196,733
INCOME BEFORE INCOME TAXES:
Income before income taxes	119,260		100,924
NET INCOME:
Net income	73,756		62,475
TOTAL ASSETS:
Assets	5,536,371		5,440,401
ITC Holdings and Other
OPERATING REVENUES:
Operating revenues	152		152
INCOME BEFORE INCOME TAXES:
Income before income taxes	(37,510)		(27,841)
NET INCOME:
Net income	50,190		46,051
TOTAL ASSETS:
Assets	3,500,265		3,252,047
Intercompany Eliminations
OPERATING REVENUES:
Operating revenues	(227)		(172)
NET INCOME:
Net income	(73,756)		(62,475)
Reconciliations and Intercompany Eliminations
TOTAL ASSETS:
Assets	$ (3,241,149)	[1]	$ (3,127,639)	[1]

[1] Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our Regulated Operating Subsidiaries as compared to the classification in our condensed consolidated statements of financial position.

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REGULATORY MATTERS Additional Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Regulatory Assets
Transmission rate, applicable period	1 year
Revenue true-up amount reflected in customer bill, period of recognition	2 years
ITC Great Plains | Start-up and Development Expenses
Regulatory Assets
Regulatory asset	14.1
ITC Great Plains | Kansas V-Plan
Regulatory Assets
Amortization period	10

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INTANGIBLE ASSETS (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Acquired Finite-Lived Intangible Assets
Intangible assets	$ 47,701,000		$ 48,492,000
Accumulated amortization	19,188,000		18,397,000
Amortization expense	800,000	800,000
Expected amortization expense in 2013	3,200,000
Expected amortization expense in 2014	3,200,000
Expected amortization expense in 2015	3,200,000
Expected amortization expense in 2016	3,200,000
Expected amortization expense in 2017	3,200,000
METC
Acquired Finite-Lived Intangible Assets
Intangible assets	39,500,000
Accumulated amortization	18,900,000
ITC Great Plains
Acquired Finite-Lived Intangible Assets
Intangible assets	8,200,000
Accumulated amortization	$ 300,000

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GENERAL

3 Months Ended

Mar. 31, 2013

GENERAL [Abstract]

GENERAL

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, 2012 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

	Three months ended
	March 31,
(in thousands)	2013		2012
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	38,144	$	56,262
Income taxes paid	1,100		9,324
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment (a)	$	79,933	$	78,252
Allowance for equity funds used during construction	8,733		5,624

____________________________

(a) Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of March 31, 2013 or 2012, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

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DEBT Schedule of Interest Rate Swap Agreements (Details) (USD $)			3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2013 Interest Rate Swap	Dec. 31, 2012 Interest Rate Swap	Nov. 30, 2012 Interest Rate Swap	Aug. 31, 2011 Interest Rate Swap	May 31, 2011 Interest Rate Swap	Mar. 31, 2011 Interest Rate Swap	Sep. 30, 2010 Interest Rate Swap	Apr. 30, 2013 Interest Rate Swap Tranche One	Feb. 28, 2013 Interest Rate Swap Tranche One	Apr. 30, 2013 Interest Rate Swap Tranche Two	Feb. 28, 2013 Interest Rate Swap Tranche Two	Jul. 15, 2013 ITC Holdings Senior Notes due July 15, 2013 Unsecured Debt	Aug. 23, 2013 ITC Holdings 2012 Term Loan Credit Agreement Unsecured Debt	Aug. 23, 2012 ITC Holdings 2012 Term Loan Credit Agreement Unsecured Debt	Dec. 31, 2013 ITC Holdings 2013 Term Loan Credit Agreement Unsecured Debt
Derivative
Long-term debt	$ 2,619,500,000	$ 2,619,400,000												$ 267,000,000
Interest rate														5.25%
Short-term debt															200,000,000	200,000,000	250,000,000
Notional amount			275,000,000	25,000,000	25,000,000	50,000,000	25,000,000	50,000,000	50,000,000	75,000,000	25,000,000	125,000,000	25,000,000
Fixed interest rate				2.58%	2.60%	3.80%	4.20%	4.45%	3.60%	3.37%	2.98%	2.82%	2.93%
Original term				30 years	30 years	10 years	10 years	10 years	10 years	10 years	30 years	30 years	30 years
Ineffectiveness recorded in the condensed consolidated statement of operations			0
Fair value of derivative instruments, asset			5,100,000
Fair value of liability for derivative instruments			$ 30,500,000

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FAIR VALUE MEASUREMENTS Assets Measured at Fair Value Subject to Three-Tier Hierarchy (Details) (Fair Value Measured on a Recurring Basis, USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Total - net assets	$ 58,814	$ 36,071
Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Cash and cash equivalents - cash equivalents	35,935	13,127
Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Fixed Income Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Mutual funds	21,113	21,332
Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets (Level 1) | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Mutual funds	1,766	1,612
Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Total - net assets	4,917
Total - net liabilities		(18,745)
Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Cash and cash equivalents - cash equivalents	30,243	10,037
Fair Value Measurements at Reporting Date Using Significant Other Observable Inputs (Level 2) | Interest Rate Swap Derivatives
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis
Interest rate swap derivatives - asset	5,142	2,725
Interest rate swap derivatives - liability	$ (30,468)	$ (31,507)

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CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 67,582	$ 26,187
Accounts receivable	78,412	72,192
Inventory	37,092	37,357
Deferred income taxes	21,094	23,014
Regulatory assets - revenue accruals, including accrued interest	6,310	7,489
Prepaid assets	18,367	29,235
Other	5,179	2,752
Total current assets	234,036	198,226
Property, plant and equipment (net of accumulated depreciation and amortization of $1,289,769 and $1,269,810, respectively)	4,317,746	4,134,579
Other assets
Goodwill	950,163	950,163
Intangible assets (net of accumulated amortization of $19,188 and $18,397, respectively)	47,701	48,492
Regulatory assets — revenue accruals, including accrued interest	14,594	2,719
Other regulatory assets	181,797	180,378
Deferred financing fees (net of accumulated amortization of $18,742 and $17,838, respectively)	18,721	19,293
Other	30,729	30,959
Total other assets	1,243,705	1,232,004
TOTAL ASSETS	5,795,487	5,564,809
Current liabilities
Accounts payable	109,646	123,022
Accrued payroll	10,174	20,740
Accrued interest	44,722	44,708
Accrued taxes	23,221	28,117
Regulatory liabilities - revenue deferrals, including accrued interest	47,736	53,763
Refundable deposits from generators for transmission network upgrades	30,083	40,745
Debt maturing within one year	901,962	651,929
Other	38,408	40,287
Total current liabilities	1,205,952	1,003,311
Accrued pension and postretirement liabilities	55,349	53,243
Deferred income taxes	484,577	460,072
Regulatory liabilities - revenue deferrals, including accrued interest	33,479	28,613
Regulatory liabilities - accrued asset removal costs	74,549	75,477
Refundable deposits from generators for transmission network upgrades	6,019	7,623
Other	23,088	26,317
Long-term debt	2,458,881	2,495,298
Commitments and contingent liabilities (Note 10)
STOCKHOLDERS' EQUITY
Common stock, without par value, 100,000,000 shares authorized, 52,317,093 and 52,248,514 shares issued and outstanding at March 31, 2013 and December 31, 2012, respectively	995,509	989,334
Retained earnings	474,026	443,569
Accumulated other comprehensive loss	(15,942)	(18,048)
Total stockholders' equity	1,453,593	1,414,855
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 5,795,487	$ 5,564,809

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parentheticals) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Amortization of interest rate lock cash flow hedges, tax	$ 10	$ 9
Unrealized gain on interest rate swaps relating to interest rate cash flow hedges, tax	$ 1,365	$ 1,803

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STOCKHOLDERS' EQUITY (Details) (USD $) In Millions, except Share data, unless otherwise specified			3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2013 Sales Agency Financing Agreement	Jul. 27, 2011 Sales Agency Financing Agreement	Jul. 27, 2011 Sales Agency Financing Agreement Maximum
Stock Issuance Arrangements
Common stock, par value				$ 0
Common stock issuable shares value				$ 250.0
Description of restriction			Agreements relating to the Entergy Transaction generally prohibit us from issuing shares under the SAFA until approximately two years after the closing except under certain limited circumstances
Restriction period			2 years
Commission rate					2.00%
Shares issued	52,317,093	52,248,514	0

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DEBT (Tables)

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Abstract]

Schedule of Interest Rate Swap Agreements

The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuances of fixed-rate debt related to (1) the expected refinancing of the $267.0 million ITC Holdings 5.25% Senior Notes, due July 15, 2013, prior to its maturity and (2) the expected financing required to repay the $200.0 million and $250.0 million borrowed under the existing ITC Holdings unsecured, unguaranteed term loan credit agreements, due August 23, 2013 and December 31, 2013, respectively, prior to their maturity:

Interest Rate Swaps	Notional Amount		Fixed Rate	Original Term	Effective Date
(amounts in millions)
September 2010 swap	$	50.0	3.60%	10 years	July 2013
March 2011 swaps	50.0		4.45%	10 years	July 2013
May 2011 swap	25.0		4.20%	10 years	July 2013
August 2011 swaps	50.0		3.80%	10 years	July 2013
November 2012 swap	25.0		2.60%	30 years	June 2013
December 2012 swap	25.0		2.58%	30 years	June 2013
February 2013 swap	25.0		2.98%	30 years	June 2013
February 2013 swap	25.0		2.93%	30 years	June 2013
Total	$	275.0

Schedule of Revolving Credit Agreements

At March 31, 2013, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available, each of which bears interest at a variable rate based on the prime rate or LIBOR (subject to adjustment based on credit rating):

(amounts in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity		Weighted-Average Interest Rate on Outstanding Balance	Commitment Fee Rate (b)		Original Term	Date of Maturity
Revolving Credit Agreements:
ITC Holdings	$	200.0	$	—	$	200.0	n/a	0.25	%	5 years	May 2016
ITCTransmission	100.0		2.5		97.5		1.4%	0.125	%	5 years	May 2016
METC	100.0		31.3		68.7		1.3%	0.125	%	5 years	May 2016
ITC Midwest	175.0		146.2		28.8		1.2%	0.10	%	5 years	May 2017
ITC Great Plains	150.0		111.3		38.7		2.0%	0.30	%	4 years	February 2015
Total	$	725.0	$	291.3	$	433.7

____________________________

(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.

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EARNINGS PER SHARE Schedule of Basic and Diluted Earnings Per Common Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Numerator:
Net income	$ 50,190		$ 46,051
Dividends declared	(19,733)		(18,101)
Undistributed earnings	30,457		27,950
Percentage allocated to common shares	99.00%	[1]	98.60%	[1]
Numerator for basic and diluted earnings per common share	49,689		45,410
Denominator:
Denominator for basic earnings per common share - weighted-average common shares	51,756,765		50,636,200
Incremental shares for stock options and employee stock purchase plan	378,406		768,834
Denominator for diluted earnings per common share - adjusted weighted-average shares and assumed conversion	52,135,171		51,405,034
Per common share net income:
Basic	$ 0.96		$ 0.90
Diluted	$ 0.95		$ 0.88
Percentage allocated to common shares:
Weighted-average shares outstanding, participating securities	519,996		709,091
Denominator for percentage allocated to common shares - total weighted-average shares outstanding	52,276,761		51,345,291
Common Shares
Numerator:
Dividends declared	19,537		17,851
Undistributed earnings	$ 30,152		$ 27,559

[1] Weighted-average common shares outstanding51,756,765 50,636,200Weighted-average restricted shares (participating securities)519,996 709,091 Total52,276,761 51,345,291 Percentage allocated to common shares99.0% 98.6%

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST (Tables)

3 Months Ended

Mar. 31, 2013

Retirement Plan Benefits

Defined Benefit Plan Disclosure

Schedule of Net Defined Benefit Cost Components

Net pension cost includes the following components:

	Three months ended
	March 31,
(in thousands)	2013			2012
Service cost	$	1,315		$	1,040
Interest cost	763			647
Expected return on plan assets	(717		)	(570		)
Amortization of prior service cost	(10		)	(10		)
Amortization of unrecognized loss	679			868
Net pension cost	$	2,030		$	1,975

Other Postretirement Benefits

Defined Benefit Plan Disclosure

Schedule of Net Defined Benefit Cost Components

Net postretirement cost includes the following components:

	Three months ended
	March 31,
(in thousands)	2013			2012
Service cost	$	1,443		$	1,358
Interest cost	390			388
Expected return on plan assets	(353		)	(254		)
Amortization of prior service cost	—			31
Amortization of unrecognized loss	55			134
Net postretirement cost	$	1,535		$	1,657

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 50,190	$ 46,051
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense	28,486	25,011
Recognition, refund and collection of revenue accruals and deferrals - including accrued interest	(11,857)	(16,779)
Deferred income tax expense	21,329	16,191
Allowance for equity funds used during construction	(8,733)	(5,624)
Other	3,992	2,974
Changes in assets and liabilities, exclusive of changes shown separately:
Accounts receivable	(4,341)	1,232
Inventory	265	1,771
Prepaid and other current assets	10,857	(4,421)
Accounts payable	(5,193)	(4,840)
Accrued payroll	(7,040)	(6,726)
Accrued interest	14	(19,448)
Accrued taxes	(4,896)	(6,505)
Other current liabilities	(839)	(3,641)
Other non-current assets and liabilities, net	(266)	4,429
Net cash provided by operating activities	71,968	29,675
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(214,111)	(224,079)
Other	(103)	(50)
Net cash used in investing activities	(214,214)	(224,129)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt	0	100,000
Borrowings under revolving credit agreements	369,500	342,250
Borrowings under term loan credit agreement	250,000	0
Repayments of revolving credit agreements	(406,000)	(268,500)
Issuance of common stock	2,632	1,050
Dividends on common stock and restricted stock	(19,733)	(18,101)
Refundable deposits from generators for transmission network upgrades	8,058	9,636
Repayment of refundable deposits from generators for transmission network upgrades	(20,325)	(5,661)
Other	(491)	(1,512)
Net cash provided by financing activities	183,641	159,162
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	41,395	(35,292)
CASH AND CASH EQUIVALENTS - Beginning of period	26,187	58,344
CASH AND CASH EQUIVALENTS - End of period	$ 67,582	$ 23,052

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CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED) (Parentheticals) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Property, plant and equipment, accumulated depreciation and amortization	$ 1,289,769	$ 1,269,810
Intangible assets, accumulated amortization	19,188	18,397
Deferred financing fees, accumulated amortization	$ 18,742	$ 17,838
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	52,317,093	52,248,514
Common stock, shares outstanding	52,317,093	52,248,514

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COMMITMENTS AND CONTINGENT LIABILITIES

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENT LIABILITIES

COMMITMENTS AND CONTINGENT LIABILITIES

Environmental Matters

Our Regulated Operating Subsidiaries’ operations 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 hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate 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 at properties currently owned or operated by our Regulated Operating Subsidiaries. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of 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 Regulated Operating Subsidiaries’ 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 Regulated Operating Subsidiaries’ assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties our Regulated Operating Subsidiaries 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 PCBs. Our Regulated Operating Subsidiaries’ facilities and equipment are often situated close to or on property owned by others so that, if they are the source of contamination, other’s property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that our Regulated Operating Subsidiaries do not own, and, at some of our Regulated Operating Subsidiaries’ transmission stations, transmission assets (owned or operated by our Regulated Operating Subsidiaries) and distribution assets (owned or operated by our Regulated Operating Subsidiaries’ transmission customer) are commingled.

Some properties in which our Regulated Operating Subsidiaries have an ownership interest or at which they operate are, and others are suspected of being, affected by environmental contamination. Our Regulated Operating Subsidiaries are not aware of any pending or threatened claims against them with respect to environmental contamination, or of any investigation or remediation of contamination at any properties, that entail costs likely to materially affect them. Some facilities and properties are located near environmentally sensitive areas such as wetlands.

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 our Regulated Operating Subsidiaries do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, if such a relationship is established or accepted, the liabilities and costs imposed on our business could be significant. We are not aware of any pending or threatened claims against our Regulated Operating Subsidiaries 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, 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. The resolution of pending proceedings is not expected to have a material effect on our operations or consolidated financial statements in the period in which they are resolved.

Michigan Sales and Use Tax Audit

The Michigan Department of Treasury conducted a sales and use tax audit of ITCTransmission for the audit period April 1, 2005 through June 30, 2008 and has denied ITCTransmission’s use of the industrial processing exemption from use tax it has taken beginning January 1, 2007. ITCTransmission has certain administrative and judicial appeal rights.

ITCTransmission believes that its utilization of the industrial processing exemption is appropriate and intends to defend itself against the denial of such exemption. However, it is reasonably possible that the assessment of additional use tax could be sustained after all administrative appeals and litigation have been exhausted.

The amount of use tax liability associated with the exemptions taken by ITCTransmission through March 31, 2013 is estimated to be approximately $15.6 million, which includes approximately $3.7 million assessed for the audit period April 1, 2005 through June 30, 2008, including interest. In the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission 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. METC has also taken the industrial processing exemption, estimated to be approximately $11.0 million for periods still subject to audit since 2006. These higher use tax expenses would be passed on to ITCTransmission’s and METC’s customers as the amounts are included as components of net revenue requirements and resulting rates.

FERC Audit of ITC Midwest

Certain staff of the FERC (“FERC audit staff”) have conducted an audit of ITC Midwest’s compliance with certain of the FERC’s regulations and the conditions established in the 2007 FERC order approving the acquisition of the transmission assets of Interstate Power and Light Company by ITC Midwest. In 2011, the FERC issued an order that identified certain findings and recommendations of FERC audit staff relating to specific aspects of the accounting treatment for the acquisition that requires adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. In 2012, ITC Midwest filed a refund report with the FERC which included adjustments to ITC Midwest’s annual revenue requirement calculations and corresponding refunds. On January 30, 2013, the FERC accepted ITC Midwest’s refund report which included the amount expected to be refunded in 2014.

ITCTransmission and METC have applied an accounting treatment for their respective acquisitions similar to ITC Midwest, and on February 1, 2013, voluntarily filed compliance plans with FERC to address the findings raised with respect to the ITC Midwest audit, which includes the amount expected to be refunded in 2014.

As a result of the FERC order, ITC Midwest, ITCTransmission and METC have recorded an aggregate estimated liability for the refund and related interest of $12.8 million as of March 31, 2013 in the condensed consolidated statements of financial position. The refund amounts are limited to 2010 and earlier periods. The ITCTransmission and METC compliance plans and refund reports remain subject to FERC acceptance, however, we do not believe the ultimate resolution of this matter will differ materially from the estimates recorded during 2012.

ITC Midwest Project Commitment

In the Minnesota regulatory proceeding to approve ITC Midwest’s December 2007 acquisition of the transmission assets of IP&L, ITC Midwest agreed to build a certain project in Iowa, the 345 kV Salem-Hazelton line, and made a commitment to use commercially reasonable best efforts to complete the project prior to December 31, 2011. In the event ITC Midwest is found to have failed to meet this commitment, the allowed 12.38% rate of return on the actual equity portion of its capital structure would be reduced to 10.39% until such time as ITC Midwest completes the project, and ITC Midwest would refund with interest any amounts collected since the close date of the transaction that exceeded what would have been collected if the 10.39% return on equity had been used. Certain regulatory approvals were needed from the Iowa Utilities Board (“IUB”) before construction of the project could commence, but due to the IUB’s case schedule, these approvals were not received until the second quarter of 2011. As a result of the delay in the receipt of the necessary regulatory approvals, the project was not completed by December 31, 2011. The Minnesota Public Utilities Commission is monitoring the status of the project, and ITC Midwest is providing it with periodic status updates about the project and other information about transmission system conditions, as requested in a May 15, 2012 Order. We believe we used commercially reasonable best efforts to meet the December 31, 2011 deadline and will continue to pursue completion of the project using our commercially reasonable best efforts. Therefore, we believe the likelihood of any material effect from this matter is remote.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2013	Apr. 19, 2013
Document - Document and Entity Information [Abstract]
Entity Registrant Name	ITC HOLDINGS CORP.
Entity Central Index Key	0001317630
Trading Symbol	ITC
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		52,332,830

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ENTERGY TRANSACTION

3 Months Ended

Mar. 31, 2013

Business Combinations [Abstract]

ENTERGY TRANSACTION

ENTERGY TRANSACTION

As of December 4, 2011, Entergy and ITC Holdings executed definitive agreements (as subsequently amended, the “transaction agreements”) under which Entergy will divest and then merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings (“Entergy Transaction”). Entergy’s electric transmission business consists of approximately 15,400 miles of interconnected transmission lines at voltages of 69 kV and above and associated substations across its utility service territory in the Mid-South.

The terms of the transaction agreements call for Entergy to divest its electric transmission business to a newly-formed entity, Mid South TransCo LLC (“Mid South TransCo”), and Mid South TransCo’s subsidiaries, and distribute the equity interests in Mid South TransCo to Entergy’s shareholders in the form of a tax-free spin-off. Mid South TransCo will then merge with a newly-created merger subsidiary of ITC Holdings in an all-stock, Reverse Morris Trust transaction, and will survive the merger as a wholly-owned subsidiary of ITC Holdings. Prior to the merger, we expect to effectuate a recapitalization, which may take the form of a one-time special dividend to ITC Holdings’ pre-merger shareholders, a repurchase of ITC Holdings common stock from its shareholders, or a combination of a special dividend and share repurchase. The merger will result in shareholders of Entergy receiving approximately 50.1% of the shares of pro forma ITC Holdings in exchange for their shares of Mid South TransCo, with existing shareholders of ITC Holdings owning the remaining approximately 49.9% of the combined company. In addition, Entergy will receive gross cash proceeds of $1.775 billion from indebtedness that will be incurred by Mid South TransCo and its subsidiaries prior to the merger and assumed under the acquisition. On April 16, 2013, ITC Holdings received the necessary shareholder approvals to consummate the merger. Completion of the transaction is expected in 2013 subject to the satisfaction of certain closing conditions, including the receipt of necessary approvals of Entergy’s retail regulators and the FERC.

For the three months endedMarch 31, 2013 and 2012, we expensed external legal, advisory and financial services fees of $8.7 million and $2.4 million, respectively, and certain internal labor and related costs of approximately $2.3 million and $1.5 million, respectively, related to the Entergy Transaction recorded primarily within general and administrative expenses. The external and internal costs related to the Entergy Transaction are not included as components of revenue requirement at our Regulated Operating Subsidiaries as they were incurred at ITC Holdings.

Per the transaction agreements, prior to completion of the Entergy Transaction, there are certain restrictions on our ability to pay dividends other than those paid in the ordinary course of business with record dates and payment dates consistent with our past practice and, if elected, a one-time special dividend to ITC Holdings’ pre-merger shareholders in accordance with the transaction agreements. Management does not expect the restrictions to have an impact on our ability to pay dividends at the current level in the foreseeable future.

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
OPERATING REVENUES	$ 217,304	$ 196,713
OPERATING EXPENSES
Operation and maintenance	24,513	28,712
General and administrative	34,926	23,009
Depreciation and amortization	28,486	25,011
Taxes other than income taxes	16,670	14,280
Other operating (income) and expense - net	(172)	(193)
Total operating expenses	104,423	90,819
OPERATING INCOME	112,881	105,894
OTHER EXPENSES (INCOME)
Interest expense	39,063	37,910
Allowance for equity funds used during construction	(8,733)	(5,624)
Other income	(236)	(306)
Other expense	1,037	831
Total other expenses (income)	31,131	32,811
INCOME BEFORE INCOME TAXES	81,750	73,083
INCOME TAX PROVISION	31,560	27,032
NET INCOME	$ 50,190	$ 46,051
Basic earnings per common share	$ 0.96	$ 0.90
Diluted earnings per common share	$ 0.95	$ 0.88
Dividends declared per common share	$ 0.3775	$ 0.3525

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DEBT

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Abstract]

DEBT

DEBT

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. The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuances of fixed-rate debt related to (1) the expected refinancing of the $267.0 million ITC Holdings 5.25% Senior Notes, due July 15, 2013, prior to its maturity and (2) the expected financing required to repay the $200.0 million and $250.0 million borrowed under the existing ITC Holdings unsecured, unguaranteed term loan credit agreements, due August 23, 2013 and December 31, 2013, respectively, prior to their maturity:

Interest Rate Swaps	Notional Amount		Fixed Rate	Original Term	Effective Date
(amounts in millions)
September 2010 swap	$	50.0	3.60%	10 years	July 2013
March 2011 swaps	50.0		4.45%	10 years	July 2013
May 2011 swap	25.0		4.20%	10 years	July 2013
August 2011 swaps	50.0		3.80%	10 years	July 2013
November 2012 swap	25.0		2.60%	30 years	June 2013
December 2012 swap	25.0		2.58%	30 years	June 2013
February 2013 swap	25.0		2.98%	30 years	June 2013
February 2013 swap	25.0		2.93%	30 years	June 2013
Total	$	275.0

The 10 year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 10-year period beginning July 15, 2013 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 July 15, 2013. The 30 year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 30-year period beginning June 15, 2013 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 July 15, 2013 and June 15, 2013 for the 10- and 30-year swaps, respectively. 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 debt issuance attributable to changes in benchmark interest rates from the trade date of the interest rate swaps to the issuance date of the debt obligation. In April 2013, we entered into additional interest rate swap contracts with terms that are comparable to the interest rate swaps described above, consisting of an additional $75.0 million notional amount of 10-year term interest rate swaps with a weighted average fixed rate of 3.37% and $125.0 million notional amount of 30-year term interest rate swaps with a weighted average fixed rate of 2.82%.

As of March 31, 2013, there has been no material ineffectiveness recorded in the condensed consolidated statement of operations. The interest rate swaps qualify for 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. These amounts will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. As of March 31, 2013, the fair value of the derivative instruments was an asset of $5.1 million recorded to other current assets and a liability of $30.5 million recorded to other current liabilities. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 9 for additional fair value information.

ITC Holdings

On August 23, 2012, ITC Holdings entered into a new unsecured, unguaranteed term loan credit agreement (“2012 Term Loan”), under which ITC Holdings had borrowed $200.0 million as of March 31, 2013 and as of December 31, 2012. On February 15, 2013, ITC Holdings entered into a new unsecured, unguaranteed term loan credit agreement with a borrowing capacity of $250.0 million (“2013 Term Loan”), under which ITC Holdings borrowed $250.0 million as of March 31, 2013. The proceeds from each term loan were used for general corporate purposes, including the repayment of borrowings under the ITC Holdings’ revolving credit agreement. The 2012 Term Loan and the 2013 Term Loan are scheduled to mature on August 23, 2013 and December 31, 2013, respectively. The weighted-average interest rate on the borrowings outstanding under the term loans was 1.2% at March 31, 2013.

ITC Midwest

On April 4, 2013, ITC Midwest issued $100.0 million aggregate principal amount of 4.09% First Mortgage Bonds, Series F, due 2043. The proceeds from the issuance were used to refinance existing indebtedness, partially fund capital expenditures and for general corporate purposes. All of ITC Midwest’s First Mortgage Bonds are issued under its First Mortgage and Deed of Trust, and therefore have the benefit of a first mortgage lien on substantially all of ITC Midwest’s property.

Revolving Credit Agreements

At March 31, 2013, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured revolving credit facilities available, each of which bears interest at a variable rate based on the prime rate or LIBOR (subject to adjustment based on credit rating):

(amounts in millions)	Total Available Capacity		Outstanding Balance (a)		Unused Capacity		Weighted-Average Interest Rate on Outstanding Balance	Commitment Fee Rate (b)		Original Term	Date of Maturity
Revolving Credit Agreements:
ITC Holdings	$	200.0	$	—	$	200.0	n/a	0.25	%	5 years	May 2016
ITCTransmission	100.0		2.5		97.5		1.4%	0.125	%	5 years	May 2016
METC	100.0		31.3		68.7		1.3%	0.125	%	5 years	May 2016
ITC Midwest	175.0		146.2		28.8		1.2%	0.10	%	5 years	May 2017
ITC Great Plains	150.0		111.3		38.7		2.0%	0.30	%	4 years	February 2015
Total	$	725.0	$	291.3	$	433.7

____________________________

(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.

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. We are currently in compliance with all debt covenants.

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INTANGIBLE ASSETS

3 Months Ended

Mar. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

INTANGIBLE ASSETS

INTANGIBLE ASSETS

We have recorded intangible assets as a result of the METC acquisition in 2006. The carrying value of these assets was $39.5 million (net of accumulated amortization of $18.9 million) as of March 31, 2013.

We have also recorded intangible assets for payments made by ITC Great Plains to certain transmission owners 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 $8.2 million (net of accumulated amortization of $0.3 million) as of March 31, 2013.

During the three months endedMarch 31, 2013 and 2012, we recognized $0.8 million of amortization expense of our intangible assets. For each of the next five years, we expect the annual amortization of our intangible assets that have been recorded as of March 31, 2013 to be $3.2 million per year.

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EARNINGS PER SHARE (Tables)

3 Months Ended

Mar. 31, 2013

Earnings Per Share, Basic and Diluted [Abstract]

Schedule of Basic and Diluted Earnings Per Common Share

We report both basic and diluted earnings per share. Our restricted stock and deferred stock units contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing earnings per share. A reconciliation of both calculations for the three months endedMarch 31, 2013 and 2012 is presented in the following table:

	Three months ended
	March 31,
(in thousands, except share, per share data and percentages)	2013			2012
Numerator:
Net income	$	50,190		$	46,051
Less: dividends declared — common shares and restricted shares	(19,733		)	(18,101		)
Undistributed earnings	30,457			27,950
Percentage allocated to common shares (a)	99.0		%	98.6		%
Undistributed earnings — common shares	30,152			27,559
Add: dividends declared — common shares	19,537			17,851
Numerator for basic and diluted earnings per common share	$	49,689		$	45,410
Denominator:
Denominator for basic earnings per common share — weighted-average common shares	51,756,765			50,636,200
Incremental shares for stock options and employee stock purchase plan	378,406			768,834
Denominator for diluted earnings per common share — adjusted weighted-average shares and assumed conversion	52,135,171			51,405,034
Per common share net income:
Basic	$	0.96		$	0.90
Diluted	$	0.95		$	0.88

____________________________

(a)	Weighted-average common shares outstanding	51,756,765		50,636,200
	Weighted-average restricted shares (participating securities)	519,996		709,091
	Total	52,276,761		51,345,291
	Percentage allocated to common shares	99.0	%	98.6	%

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SEGMENT INFORMATION

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

SEGMENT INFORMATION

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. The following tables show our financial information by reportable segment:

	Three months ended
OPERATING REVENUES:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	217,379		$	196,733
ITC Holdings and other	152			152
Intercompany eliminations	(227		)	(172		)
Total Operating Revenues	$	217,304		$	196,713

	Three months ended
INCOME BEFORE INCOME TAXES:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	119,260		$	100,924
ITC Holdings and other	(37,510		)	(27,841		)
Total Income Before Income Taxes	$	81,750		$	73,083

	Three months ended
NET INCOME:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	73,756		$	62,475
ITC Holdings and other	50,190			46,051
Intercompany eliminations	(73,756		)	(62,475		)
Total Net Income	$	50,190		$	46,051

TOTAL ASSETS:	March 31,			December 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	5,536,371		$	5,440,401
ITC Holdings and other	3,500,265			3,252,047
Reconciliations / Intercompany Eliminations (a)	(3,241,149		)	(3,127,639		)
Total Assets	$	5,795,487		$	5,564,809

____________________________

(a) Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our Regulated Operating Subsidiaries as compared to the classification in our condensed consolidated statements of financial position.

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

3 Months Ended

Mar. 31, 2013

Compensation and Retirement Disclosure [Abstract]

RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

RETIREMENT BENEFITS AND ASSETS HELD IN TRUST

Retirement Plan Benefits

We have a qualified 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 the employees’ 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. While we are obligated to fund the retirement plan by contributing the minimum amount required by the Employee Retirement Income Security Act of 1974, as amended, it is our practice to contribute the maximum allowable amount as defined by section 404 of the Internal Revenue Code. We expect to contribute up to $6.9 million to the defined benefit retirement plan in 2013.

We also have two supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees. The plans provide for benefits that supplement those provided by our other retirement plans. We expect to contribute up to $0.6 million to these supplemental nonqualified, noncontributory, retirement benefit plans in 2013.

Net pension cost includes the following components:

	Three months ended
	March 31,
(in thousands)	2013			2012
Service cost	$	1,315		$	1,040
Interest cost	763			647
Expected return on plan assets	(717		)	(570		)
Amortization of prior service cost	(10		)	(10		)
Amortization of unrecognized loss	679			868
Net pension cost	$	2,030		$	1,975

Other Postretirement Benefits

We provide certain postretirement health care, dental, and life insurance benefits for employees who may become eligible for these benefits. We expect to contribute up to $3.8 million to the postretirement benefit plan in 2013.

Net postretirement cost includes the following components:

	Three months ended
	March 31,
(in thousands)	2013			2012
Service cost	$	1,443		$	1,358
Interest cost	390			388
Expected return on plan assets	(353		)	(254		)
Amortization of prior service cost	—			31
Amortization of unrecognized loss	55			134
Net postretirement cost	$	1,535		$	1,657

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 $1.7 million and $1.3 million for the three months endedMarch 31, 2013 and 2012, respectively.

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STOCKHOLDERS' EQUITY

3 Months Ended

Mar. 31, 2013

Stockholders' Equity Attributable to Parent [Abstract]

STOCKHOLDERS' EQUITY

STOCKHOLDERS’ EQUITY

ITC Holdings Sales Agency Financing Agreement

On July 27, 2011, ITC Holdings entered into a Sales Agency Financing Agreement with Deutsche Bank Securities Inc. as sales agent (the “SAFA”). Under the terms of the SAFA, ITC Holdings may issue and sell shares of common stock, without par value, from time to time, up to an aggregate sales proceeds amount of $250.0 million. The SAFA terminates in July 2014, although the agreements relating to the Entergy Transaction generally prohibit us from issuing shares under the SAFA until approximately two years after the closing except under certain limited circumstances. The shares of common stock may be offered in one or more selling periods. Any shares of common stock sold under the SAFA will be offered at market prices prevailing at the time of sale. Moreover, ITC Holdings will specify to the sales agent (i) the aggregate selling price of the shares of common stock to be sold during each selling period, and (ii) the minimum price below which sales may not be made. ITC Holdings will pay a commission equal to a mutually agreed upon rate with its agent, not to exceed 2% of the sales price of all shares of common stock sold through its agent under the SAFA, plus expenses. The shares we would issue under the SAFA have been registered under ITC Holdings’ shelf registration statement on Form S-3 (File No. 333-187994) filed on April 18, 2013 with the SEC. No shares have been issued under the SAFA.

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EARNINGS PER SHARE

3 Months Ended

Mar. 31, 2013

Earnings Per Share, Basic and Diluted [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

We report both basic and diluted earnings per share. Our restricted stock and deferred stock units contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing earnings per share. A reconciliation of both calculations for the three months endedMarch 31, 2013 and 2012 is presented in the following table:

	Three months ended
	March 31,
(in thousands, except share, per share data and percentages)	2013			2012
Numerator:
Net income	$	50,190		$	46,051
Less: dividends declared — common shares and restricted shares	(19,733		)	(18,101		)
Undistributed earnings	30,457			27,950
Percentage allocated to common shares (a)	99.0		%	98.6		%
Undistributed earnings — common shares	30,152			27,559
Add: dividends declared — common shares	19,537			17,851
Numerator for basic and diluted earnings per common share	$	49,689		$	45,410
Denominator:
Denominator for basic earnings per common share — weighted-average common shares	51,756,765			50,636,200
Incremental shares for stock options and employee stock purchase plan	378,406			768,834
Denominator for diluted earnings per common share — adjusted weighted-average shares and assumed conversion	52,135,171			51,405,034
Per common share net income:
Basic	$	0.96		$	0.90
Diluted	$	0.95		$	0.88

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(a)	Weighted-average common shares outstanding	51,756,765		50,636,200
	Weighted-average restricted shares (participating securities)	519,996		709,091
	Total	52,276,761		51,345,291
	Percentage allocated to common shares	99.0	%	98.6	%

The incremental shares for stock options and the employee stock purchase plan (“stock options and ESPP shares”) are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including them would be anti-dilutive. The outstanding stock options and ESPP shares as of March 31, 2013 and 2012 and the anti-dilutive stock options and ESPP shares excluded from the diluted earnings per share calculations for the three months endedMarch 31, 2013 and 2012 were as follows:

	2013	2012
Outstanding stock options and ESPP shares	1,549,860	2,066,083
Anti-dilutive stock options and ESPP shares	356,730	214,993

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FAIR VALUE MEASUREMENTS

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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.

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at March 31, 2013, 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	$	35,935	$	30,243		$	—
Mutual funds — fixed income securities	21,113		—			—
Mutual funds — equity securities	1,766		—			—
Interest rate swap derivatives	—		5,142			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(30,468		)	—
Total	$	58,814	$	4,917		$	—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2012, 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	$	13,127	$	10,037		$	—
Mutual funds — fixed income securities	21,332		—			—
Mutual funds — equity securities	1,612		—			—
Interest rate swap derivatives	—		2,725			—
Financial liabilities measured on a recurring basis:
Interest rate swap derivatives	—		(31,507		)	—
Total	$	36,071	$	(18,745	)	$	—

As of March 31, 2013 and December 31, 2012, we held certain assets and liabilities that are required to be measured at fair value on a recurring basis.

The assets 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 that are classified as trading securities. Our Level 1 investments included in cash equivalents consist of money market mutual funds and common and collective trusts that are administered similar to money market funds recorded at cost plus accrued interest to approximate fair value. Our mutual funds consist primarily of publicly traded mutual funds for which market prices are readily available. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost. The cash and cash equivalents that are classified as a Level 2 investment consist of deposits held with financial institutions that are then invested by the financial institution in money market mutual funds and common and collective trusts that are administered similar to money market funds. The underlying money market funds and common and collective trusts are recorded at cost plus accrued interest.

The assets and liabilities related to derivatives consist of interest rate swaps discussed in Note 5. The fair value of our interest rate swap derivatives as of March 31, 2013 and December 31, 2012 is determined based on a discounted cash flow 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 three months endedMarch 31, 2013. 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 endedDecember 31, 2012 included in our Form 10-K for such period and to Note 4 of this Form 10-Q.

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, was $3,034.8 million and $3,072.9 million at March 31, 2013 and December 31, 2012, respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $2,619.5 million and $2,619.4 million at March 31, 2013 and December 31, 2012, respectively.

Revolving and Term Loan Credit Agreements

At March 31, 2013 and December 31, 2012, we had a consolidated total of $741.3 million and $527.8 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.

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DEBT Additional Information (Details) (USD $) In Millions, unless otherwise specified	Aug. 23, 2013 ITC Holdings 2012 Term Loan Credit Agreement Unsecured Debt	Mar. 31, 2013 ITC Holdings 2012 Term Loan Credit Agreement Unsecured Debt	Aug. 23, 2012 ITC Holdings 2012 Term Loan Credit Agreement Unsecured Debt	Dec. 31, 2013 ITC Holdings 2013 Term Loan Credit Agreement Unsecured Debt	Mar. 31, 2013 ITC Holdings 2013 Term Loan Credit Agreement Unsecured Debt	Apr. 04, 2013 ITC Midwest First Mortgage Bonds, Series E Secured Debt
Debt Instrument
Short-term debt	$ 200.0		$ 200.0	$ 250.0
Borrowing capacity					250.0
Weighted-average interest rate		1.20%			1.20%
Principle amount						$ 100.0
Interest rate						4.09%

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REGULATORY MATTERS (Tables)

3 Months Ended

Mar. 31, 2013

Regulated Operations [Abstract]

Changes in Regulatory Assets and Liabilities

The changes in regulatory assets and liabilities (net) associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the three months endedMarch 31, 2013:

(in thousands)	Total
Balance as of December 31, 2012	$	(72,168	)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	11,766
Net revenue accrual for the three months ended March 31, 2013	687
Net accrued interest payable for the three months ended March 31, 2013	(596		)
Balance as of March 31, 2013	$	(60,311	)

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals are recorded in our condensed consolidated statement of financial position as follows:

(in thousands)	Total
Current assets	$	6,310
Non-current assets	14,594
Current liabilities	(47,736		)
Non-current liabilities	(33,479		)
Balance as of March 31, 2013	$	(60,311	)

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SEGMENT INFORMATION (Tables)

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Schedule of Financial Information by Reportable Segment

The following tables show our financial information by reportable segment:

	Three months ended
OPERATING REVENUES:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	217,379		$	196,733
ITC Holdings and other	152			152
Intercompany eliminations	(227		)	(172		)
Total Operating Revenues	$	217,304		$	196,713

	Three months ended
INCOME BEFORE INCOME TAXES:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	119,260		$	100,924
ITC Holdings and other	(37,510		)	(27,841		)
Total Income Before Income Taxes	$	81,750		$	73,083

	Three months ended
NET INCOME:	March 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	73,756		$	62,475
ITC Holdings and other	50,190			46,051
Intercompany eliminations	(73,756		)	(62,475		)
Total Net Income	$	50,190		$	46,051

TOTAL ASSETS:	March 31,			December 31,
(in thousands)	2013			2012
Regulated Operating Subsidiaries	$	5,536,371		$	5,440,401
ITC Holdings and other	3,500,265			3,252,047
Reconciliations / Intercompany Eliminations (a)	(3,241,149		)	(3,127,639		)
Total Assets	$	5,795,487		$	5,564,809

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(a) Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our Regulated Operating Subsidiaries as compared to the classification in our condensed consolidated statements of financial position.

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FAIR VALUE MEASUREMENTS Additional Information (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]
Fair value of long-term debt, excluding revolving credit agreements	$ 3,034.8	$ 3,072.9
Book value of long-term debt, excluding revolving credit agreements	2,619.5	2,619.4
Book value of revolving credit agreements and term loan credit agreements	$ 741.3	$ 527.8

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Net income	$ 50,190	$ 46,051
OTHER COMPREHENSIVE INCOME
Amortization of interest rate lock cash flow hedges (net of tax of $10 and $9, respectively)	14	15
Unrealized gain on interest rate swaps relating to interest rate cash flow hedges (net of tax of $1,365 and $1,803, respectively)	2,092	2,812
TOTAL OTHER COMPREHENSIVE INCOME, NET OF TAX	2,106	2,827
TOTAL COMPREHENSIVE INCOME	$ 52,296	$ 48,878

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REGULATORY MATTERS

3 Months Ended

Mar. 31, 2013

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

ITC Great Plains

As of March 31, 2013, we have recorded a total of $14.1 million of regulatory assets for start-up and development expenses incurred by ITC Great Plains, which include certain costs incurred for the Kansas Electric Transmission Authority (“KETA”) Project and the Kansas V-Plan Project prior to construction. Based on ITC Great Plains’ FERC application under which authority to recognize these regulatory assets was sought and the related FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the FPA in order to recover these start-up, development and pre-construction expenses in future rates. If FERC authorization to recover these costs is received, ITC Great Plains will include the balance of the regulatory assets in its rate base and will amortize them over a 10-year period beginning at the later of the project in-service date or the FERC authorization date. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template beginning in the period in which amortization begins.

Order on Formula Rate Protocols

On May 17, 2012, the FERC issued an order pursuant to Section 206 of the FPA to determine whether the formula rate protocols under the MISO Tariff are sufficient to ensure just and reasonable rates. The MISO Regulated Operating Subsidiaries were named in the order. We do not expect the resolution of this proceeding and its ultimate impact on our MISO Regulated Operating Subsidiaries’ formula rates will be material to our results of operations, cash flows or financial condition.

Complaint of IP&L

On September 14, 2012, IP&L filed a complaint with the FERC against ITC Midwest’s reimbursement policy under Section 206 of the Federal Power Act. The complaint challenges ITC Midwest’s FERC approved reimbursement policy for network upgrades to qualifying generators. IP&L requests that the FERC (1) investigate the justness and reasonableness of ITC Midwest’s Attachment FF policy; (2) establish a refund effective date of September 14, 2012; and (3) establish hearing procedures. On October 4, 2012, ITC Midwest filed an answer to the complaint with the FERC outlining the reasons ITC Midwest’s Attachment FF provision remains just and reasonable and requesting dismissal of the complaint.

Cost-Based Formula Rates with True-Up Mechanism

The transmission rates at our Regulated Operating Subsidiaries are set annually, using the FERC-approved formula rates, and the rates 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 adjust their transmission rates 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 FERC-approved formula rates do not require further action or FERC filings for the calculated joint zone rates to go into effect, although the rates are subject to legal challenge at the FERC. Our Regulated Operating Subsidiaries will continue to use formula rates to calculate their respective annual revenue requirements unless the FERC determines the rates to be unjust and unreasonable or another mechanism is determined by the FERC to be just and reasonable.

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 requirements. The over- or under-collection typically results from differences between the projected revenue requirement used to establish the billing rate 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. 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 customer bills within two years under the provisions of the formula rate templates.

The current and non-current regulatory assets are recorded on the balance sheet in regulatory assets revenue accruals, including accrued interest. The current and non-current regulatory liabilities are recorded in regulatory liabilities revenue deferrals, including accrued interest. The changes in regulatory assets and liabilities (net) associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the three months endedMarch 31, 2013:

(in thousands)	Total
Balance as of December 31, 2012	$	(72,168	)
Net refund of 2011 revenue deferrals and accruals, including accrued interest	11,766
Net revenue accrual for the three months ended March 31, 2013	687
Net accrued interest payable for the three months ended March 31, 2013	(596		)
Balance as of March 31, 2013	$	(60,311	)

Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals are recorded in our condensed consolidated statement of financial position as follows:

(in thousands)	Total
Current assets	$	6,310
Non-current assets	14,594
Current liabilities	(47,736		)
Non-current liabilities	(33,479		)
Balance as of March 31, 2013	$	(60,311	)

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GENERAL (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$ 38,144		$ 56,262
Income taxes paid	1,100		9,324
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment	79,933	[1]	78,252	[1]
Allowance for equity funds used during construction	$ 8,733		$ 5,624

[1] Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of March 31, 2013 or 2012, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.

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RETIREMENT BENEFITS AND ASSETS HELD IN TRUST Schedule of Net Defined Benefit Cost Components (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Retirement Plan Benefits
Defined Benefit Plan Disclosure
Service cost	$ 1,315	$ 1,040
Interest cost	763	647
Expected return on plan assets	(717)	(570)
Amortization of prior service cost	(10)	(10)
Amortization of unrecognized loss	679	868
Net cost	2,030	1,975
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	1,443	1,358
Interest cost	390	388
Expected return on plan assets	(353)	(254)
Amortization of prior service cost	0	31
Amortization of unrecognized loss	55	134
Net cost	$ 1,535	$ 1,657

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GENERAL (Tables)

3 Months Ended

Mar. 31, 2013

GENERAL [Abstract]

Supplementary Cash Flows Information

	Three months ended
	March 31,
(in thousands)	2013		2012
Supplementary cash flows information:
Interest paid (net of interest capitalized)	$	38,144	$	56,262
Income taxes paid	1,100		9,324
Supplementary non-cash investing and financing activities:
Additions to property, plant and equipment (a)	$	79,933	$	78,252
Allowance for equity funds used during construction	8,733		5,624

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(a) Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of March 31, 2013 or 2012, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.