For the Quarterly Period Ended June 30, 2011

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):

     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 July 22, 2011 was 51,296,413.

 

 

ITC Holdings Corp.

Form 10-Q for the Quarterly Period Ended June 30, 2011

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 Cash Flows (Unaudited)			6
Notes to Condensed Consolidated Financial Statements (Unaudited)			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			18
Item 3. Quantitative and Qualitative Disclosures About Market Risk			29
Item 4. Controls and Procedures			29
Part II. Other Information			30
Item 1. Legal Proceedings			30
Item 1A. Risk Factors			30
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds			31
Item 6. Exhibits			32
Signatures			33
Exhibit Index
EX-4.28
EX-4.29
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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, Limited Partnership, 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;
	•		“DTE Energy” are references to DTE Energy Company;
	•		“FERC” are references to the Federal Energy Regulatory Commission;
	•		“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;
	•		“KCC” are references to the Kansas Corporation Commission;
	•		“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;
	•		“MPSC” are references to the Michigan Public Service Commission;
	•		“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.

PART I. FINANCIAL INFORMATION

See notes to condensed consolidated financial statements (unaudited).

See notes to condensed consolidated financial statements (unaudited).

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, 2010 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.

2. RECENT ACCOUNTING PRONOUNCEMENTS

Presentation of Comprehensive Income

     The guidance set forth by the Financial Accounting Standards Board for the presentation of comprehensive income in financial statements was revised to require entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. This revision is effective for our annual consolidated financial statements for the year ending December 31, 2011.

3. REGULATORY MATTERS

ITC Great Plains

     In March 2011, we recorded $2.0 million of regulatory assets for development expenses and pre-construction costs relating to the Kansas V-Plan Project incurred by ITC Great Plains that are probable of recovery and recorded a corresponding $2.0 million reduction to operating expenses, primarily to general and administrative expense. As of June 30, 2011, the regulatory asset related to the Kansas V-Plan Project totaled $3.1 million. Recovery of the Kansas V-Plan Project regulatory asset requires FERC authorization upon ITC Great Plains making an additional filing under Section 205 of the Federal Power Act to demonstrate that the costs to be recovered are just and reasonable. Subsequent to FERC authorization, ITC Great Plains will include the Kansas V-Plan Project regulatory asset in its rate base and begin amortizing it over a ten-year period upon the in-service date of the Kansas V-Plan Project. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template beginning in that year.

ITC Midwest Depreciation Study

     Effective January 1, 2010, the FERC authorized the implementation of the depreciation study filed by ITC Midwest which revised its depreciation rates. This change in accounting estimate resulted in lower composite depreciation rates for ITC Midwest primarily due to the revision of asset service lives and cost of removal values.

     For ratemaking purposes, the impact of ITC Midwest’s revised depreciation rates was initially reflected in ITC Midwest’s 2010 revenue requirement. The revised depreciation rates resulted in a reduction of depreciation expense of $3.0 million for the six months ended June 30, 2011 as compared to the amount of depreciation expense that would have been recognized under the previous depreciation rates utilized by ITC Midwest. Because of the inclusion of depreciation expense as a component of net revenue requirement under ITC Midwest’s cost-based formula rate, the offsetting effect on revenues and expenses from the change in depreciation rates had an immaterial effect on net income and earnings per share amounts for the six months ended June 30, 2011.

Cost-Based Formula Rates with True-Up Mechanism

     The transmission rates at our Regulated Operating Subsidiaries are set annually and remain in effect for a one-year period. By completing their formula rate templates on an annual basis, our Regulated Operating Subsidiaries are able to 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 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 six months ended June 30, 2011:

     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:

4. INTANGIBLE ASSETS

     We have recorded intangible assets as a result of the METC acquisition in 2006. The carrying value of these assets was $44.7 million (net of accumulated amortization of $13.7 million) as of June 30, 2011.

     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 $3.7 million (net of accumulated amortization of $0.1 million) as of June 30, 2011.

     During the three months ended June 30, 2011 and 2010, we recognized $0.8 million of amortization expense of our intangible assets and $1.5 million for the six months ended June 30, 2011 and 2010. For each of the next five years, we expect the annual amortization of our intangible assets that have been recorded as of June 30, 2011 to be $3.1 million per year.

5. LONG-TERM 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. On September 27, 2010, ITC Holdings entered into a 10-year forward starting interest rate swap agreement (the “September 2010 swap”) with a notional amount of $50.0 million. On March 16, 2011, ITC Holdings entered into two 10-year forward starting interest rate swap agreements (the “March 2011 swaps”), each with a notional amount of $25.0 million. On May 17, 2011, ITC Holdings entered into a 10-year forward starting interest rate swap agreement (the “May 2011 swap”) with a notional amount of $25.0 million. These interest rate swaps manage interest rate risk of a total notional amount of $125.0 million associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing $267.0 million ITC Holdings 5.25% Senior Notes due July 15, 2013.

     The 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 a fixed rate of 3.60% for the September 2010 swap, a fixed rate of 4.45% for the March 2011 swaps and a fixed rate of 4.20% for the May 2011 swap, effective for the ten-year period beginning July 15, 2013. The agreements will be terminated no later than the effective date of the interest rate swaps of July 15, 2013. 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. As of June 30, 2011, there has been no ineffectiveness recorded in the condensed consolidated statement of operations. The interest rate swaps qualify for hedge accounting treatment, whereby any pre-tax gain or loss recognized from the trade date to the effective date for the effective portion of the hedge is recorded 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 June 30, 2011, the fair value of the derivative instruments was an asset of $1.5 million recorded to other non-current assets. Refer to Note 10 for additional information.

     ITC Holdings and its Regulated Operating Subsidiaries had the following weighted-average interest rates on borrowings outstanding at June 30, 2011:

    ITC Holdings Revolving Credit Agreement

     On May 17, 2011, ITC Holdings entered into a new unsecured, unguaranteed revolving credit agreement (the “ITC Holdings Revolving Credit Agreement”) under which ITC Holdings may borrow up to $200.0 million. Loans under the ITC Holdings Revolving Credit Agreement will bear interest at a rate equal to LIBOR plus an applicable margin of 1.75% or at a base rate, which is defined as the higher of the prime rate at the administrative agent’s principal office in New York, New York, 0.50% above the federal funds rate or 1% above LIBOR for a one month interest period on such day, plus an applicable margin of 0.75%, subject to adjustments based on ITC Holdings’ credit rating. The ITC Holdings Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at a rate of 0.25%, subject to adjustments based on ITC Holdings’ credit rating. The new revolving credit agreement replaced the existing revolving credit agreement, which was scheduled to mature on March 29, 2012.

    ITCTransmission Revolving Credit Agreement and METC Revolving Credit Agreement

     On May 17, 2011, ITCTransmission and METC each entered into new separate unsecured, unguaranteed revolving credit agreements with various banks, financial institutions and other institutional lenders, which replaced their existing revolving credit agreement, dated as of March 29, 2007, which was scheduled to mature on March 29, 2012.

     Loans made under ITCTransmission’s new revolving credit agreement (the “ITCTransmission Revolving Credit Agreement”) under which ITCTransmission may borrow up to $100.0 million, bear interest at a rate equal to LIBOR plus an applicable margin of 1.25% or at a base rate, which is defined as the higher of the prime rate at the administrative agent’s principal office in New York, New York, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.25%, subject to adjustments based on credit rating. The ITCTransmission Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at a rate of 0.15%, subject to adjustments based on ITCTransmission’s credit rating.

     Loans made under METC’s new revolving credit agreement (the “METC Revolving Credit Agreement”) under which METC may borrow up to $100.0 million, bear interest at a rate equal to LIBOR plus an applicable margin of 1.25% or at a base rate, which is defined as the higher of the prime rate at the administrative agent’s principal office in New York, New York, 0.50% above the federal

funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.25%, subject to adjustments based on credit rating. The METC Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at a rate of 0.15%, subject to adjustments based on METC’s credit rating.

    ITC Midwest Revolving Credit Agreement

     On February 11, 2011, ITC Midwest entered into a new unsecured, unguaranteed revolving credit agreement (the “2011 ITC Midwest Revolving Credit Agreement”) under which ITC Midwest may borrow up to $75.0 million, in addition to the existing revolving credit agreement, dated January 28, 2008 (the “2008 Revolving Credit Agreement”). Loans made under the 2011 ITC Midwest Revolving Credit Agreement bear interest at a rate equal to LIBOR plus an applicable margin of 1.375% or at a base rate, which is defined as the higher of prime rate at the administrative agent’s principal office in New York, New York, 0.50% above over the federal funds rate or 1% above the one month LIBOR plus an applicable margin of 0.375%, subject to adjustments based on ITC Midwest’s credit rating. The 2011 ITC Midwest Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at a rate of 0.15%, subject to adjustments based on ITC Midwest’s credit rating.

    ITC Great Plains Revolving Credit Agreement

     On February 16, 2011, ITC Great Plains entered into an unsecured, unguaranteed revolving credit agreement (the “ITC Great Plains Revolving Credit Agreement”) under which ITC Great Plains may borrow and issue letters of credit up to $150.0 million. Loans made under the ITC Great Plains Revolving Credit Agreement will bear interest at a rate equal to LIBOR plus an applicable margin of 1.75%, or at a base rate, which is defined as the higher of prime rate at the administrative agent’s principal office in New York, New York, 0.50% above the federal funds rate or 1.00% above the one month LIBOR rate plus an applicable margin of 0.75%, subject to adjustments based on ITC Great Plains’ credit rating. The ITC Great Plains Revolving Credit Agreement also provides for the payment to the lenders of a commitment fee on the average daily unused commitments at a rate of 0.30%, subject to adjustments based on ITC Great Plains’ credit rating.

Covenants

     Our debt instruments described above 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 (the “SAFA”) with Deutsche Bank Securities Inc. (“DBS”). 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 term of the SAFA is up to July 2014. DBS will act as ITC Holdings’ agent in connection with any offerings of shares under the SAFA. 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 DBS (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 DBS a commission equal to a mutually agreed upon rate, not to exceed 2% of the sales price of all shares of common stock sold through it as 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. 333-163716) filed on December 14, 2009 with the SEC. The prior ITC Holdings Sales Agency Financing Agreement with BNY Mellon Capital Markets, LLC expired on June 27, 2011. As of July 28, 2011, no shares have been issued under either of these agreements.

7. SHARE-BASED COMPENSATION

Long-Term Incentive Plan Grants

     On May 25, 2011, pursuant to the Second Amended and Restated 2006 Long-Term Incentive Plan, we granted 212,818 options to purchase shares of our common stock. The options vest in three equal annual installments with the first installment vesting on May 25, 2012 and have an exercise price of $72.15 per share, which was the closing share price of our common stock on the date of grant. In addition, on May 25, 2011, we granted 95,862 shares of restricted stock at a fair value of $72.15 per share. Holders of restricted stock have all the rights of a holder of common stock of ITC Holdings, including dividend and voting rights. The restricted stock becomes vested three years after the grant date. The holder of the restricted stock may not sell, transfer or pledge their shares of restricted stock until vesting occurs.

Stock Option Exercises

     We issued 455,250 and 464,264 shares of our common stock during the six months ended June 30, 2011 and the year ended December 31, 2010, respectively, due to the exercise of stock options.

8. EARNINGS PER SHARE

     The computation of basic and diluted earnings per common share for the three and six months ended June 30, 2011 and 2010 is presented in the following table:

     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.

     At June 30, 2011 and 2010, we had 2,188,814 and 2,849,198 outstanding stock options, respectively. Stock options are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including the stock options would be anti-dilutive. For the three and six months ended June 30, 2011 and 2010, 218,135 and 476,853 anti-dilutive stock options were excluded from the diluted earnings per share calculations, respectively.

9. 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 contributed $3.6 million to the defined benefit retirement plan relating to the 2010 plan year in June 2011. There will be no additional contributions in 2011.

     We have also established 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 contributed $3.1 million to these supplemental nonqualified, noncontributory, retirement benefit plans relating to the 2010 plan year in June 2011. There will be no additional contributions in 2011.

     Net pension cost includes the following components:

Defined Contribution Plan

     We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $0.5 million for both the three months ended June 30, 2011 and 2010 and $1.7 million and $1.6 million for the six months ended June 30, 2011 and 2010, respectively.

10. FAIR VALUE MEASUREMENTS

     The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

     Our assets measured at fair value subject to the three-tier hierarchy at June 30, 2011, were as follows:

     Our assets measured at fair value subject to the three-tier hierarchy at December 31, 2010, were as follows:

     As of June 30, 2011, we held certain assets that are required to be measured at fair value on a recurring basis. These consist of investments recorded within cash and cash equivalents and other long-term assets, including investments held in trust associated with our nonqualified, noncontributory, supplemental retirement benefit plans for selected management and employees that are classified as trading securities and our interest rate swaps discussed in Note 5. Our investments included in cash equivalents consist of common and collective trusts that are administered similar to money market funds recorded at cost plus accrued interest to approximate fair value. Our investments classified as trading securities consist primarily of mutual funds that are publicly traded and 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 fair value of our interest rate swap derivatives as of June 30, 2011 is determined based on a discounted cash flow method.

     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 requiring non-financial assets and liabilities to be measured at fair value occurred (subsequent to initial recognition) during the six months ended June 30, 2011. For additional information on our goodwill and intangible assets please refer to the notes to the consolidated financial statements as of and for the year ended December 31, 2010 included in our Form 10-K for such period and Note 4 of this Form 10-Q.

Fair Value of Financial Assets and Liabilities

    Fixed Rate Long-Term 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, excluding revolving credit agreements, was $2,691.3 million and $2,747.2 million at June 30, 2011 and December 31, 2010, respectively. The total book value of our consolidated long-term debt, excluding revolving credit agreements, was $2,443.7 million and $2,443.5 million at June 30, 2011 and December 31, 2010, respectively.

    Revolving Credit Agreements

     At June 30, 2011 and December 31, 2010, we had a consolidated total of $122.0 million and $53.4 million, respectively, outstanding under our revolving credit agreements, which are variable rate loans. The fair value of these loans approximates book value.

    Trade Accounts Receivables and Payables

     As of June 30, 2011, our accounts receivable and accounts payable balances approximate fair value due to their short term nature.

11. MICHIGAN CORPORATE INCOME TAX

     On May 25, 2011, the Michigan Business Tax (“MBT”) was repealed and replaced with the Michigan Corporate Income Tax (“CIT”), effective January 1, 2012. Under the CIT, corporations such as ITC Holdings will be taxed at a rate of 6.0% on federal taxable income apportioned to Michigan, subject to certain adjustments. In addition to the traditional income tax, the MBT had also included a modified gross receipts tax which allowed for deductions and credits for certain activities, none of which are part of the CIT. The change in Michigan tax law required us to remove new deferred income tax balances recognized under the MBT and establish deferred tax balances under the CIT in the second quarter of 2011. The change did not have a material impact on our results of operations. Under our Regulated Operating Subsidiaries’ cost-based formula rates with true-up mechanisms, the future taxes receivable that are expected to be recovered from customers in future rates have resulted in the recognition of regulatory assets.

12. COMMITMENTS AND CONTINGENT LIABILITIES

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 June 30, 2011 is estimated to be approximately $7.9 million, which includes approximately $3.5 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 $10.2 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

     The staff of the FERC has 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 IP&L by ITC Midwest. On June 20, 2011, FERC staff provided a revised draft audit report to us for review and comment. The draft audit report contains certain

proposed findings and recommendations relating to specific aspects of the accounting treatment for the acquisition which, if finalized and approved by FERC, have the potential to result in adjustments to ITC Midwest’s revenue requirement calculations for 2008 through 2010. ITCTransmission and METC have applied accounting similar to ITC Midwest for their respective acquisitions. Adjustments to ITC Midwest’s, ITCTransmission’s and METC’s historical revenue requirements could result in refunds and have a negative effect on our results of operations. We intend to both vigorously defend our position and seek an agreed-upon resolution of the audit findings. We believe an unfavorable outcome is reasonably possible, but do not believe the range of potential loss would be material to our results of operations, cash flows or financial condition.

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. To complete this project, the Iowa Utilities Board (the “IUB”) must provide certain regulatory approvals. In the second quarter of 2011, the IUB granted the necessary regulatory approvals. Given the timing of receipt of these regulatory approvals, we do not expect the project to be completed by December 31, 2011. ITC Midwest believes it has made commercially reasonable best efforts toward completion of the project by the stipulated deadlines and will continue to do so and, therefore, we believe the likelihood of any material adverse effect from this matter is remote.

Complaint of IP&L

     On November 18, 2008, IP&L filed a complaint with the FERC against ITC Midwest under Section 206 of the Federal Power Act. The complaint alleged that: (1) the operations and maintenance expenses and administrative and general expenses projected in the 2009 ITC Midwest rate appeared excessive; (2) the true-up amount related to ITC Midwest’s posted network rate for the period through December 31, 2008 will cause ITC Midwest to charge an excessive rate in future years; and (3) the methodology of allocating administrative and general expenses among ITC Holdings’ operating companies was changed, resulting in such additional expenses being allocated to ITC Midwest. Among other things, IP&L’s complaint sought investigative action by the FERC relating to ITC Midwest’s transmission service charges reflected in its 2009 rate, as well as hearings regarding the justness and reasonableness of the 2009 rate (with the ultimate goal of reducing such rate).

     On April 16, 2009, the FERC dismissed the IP&L complaint, citing that IP&L failed to meet its burden as the complainant to establish that the current rate is unjust and unreasonable and to establish that IP&L’s alternative rate proposal is just and reasonable. IP&L and other parties subsequently filed for rehearing. On May 19, 2011, FERC denied the requests for rehearing and motion to reopen the record and, as a result, this matter is now closed.

13. 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:

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 Part I, Item 1A Risk Factors of our Form 10-K for the fiscal year ended December 31, 2010 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 recent acquisitions (including ITC Midwest’s acquisition of IP&L’s electric transmission assets) that could have an 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 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 cash flows and could reduce the dividends we may be able to pay our stockholders.
	•		If the amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower 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 would adversely affect our revenues and our ability to service our debt obligations and affect our ability to pay dividends.
	•		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.
	•		If ITC Midwest’s operating agreement with IP&L is terminated early, ITC Midwest may face a shortage of labor or replacement contractors to provide the services formerly provided by IP&L.
	•		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. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our financial condition, results of operations and cash flows.
	•		Acts of war, terrorist attacks and threats or the escalation of military activity in response to such attacks or otherwise may negatively affect our business, financial condition 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.
	•		The amount of our federal net operating loss carryforwards for income taxes that we may use to reduce our tax liability in any given period is limited.
	•		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.
	•		Other risk factors discussed herein and listed from time to time in our public filings with the Securities and Exchange Commission (“SEC”).

     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. Actual future results may vary materially. 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 and Kansas 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 allow new generating resources to interconnect 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.

     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 network transmission service, point-to-point transmission service and other related services over our Regulated Operating Subsidiaries’ transmission systems to investor-owned utilities such as Detroit Edison, Consumers Energy, 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 and six months ended June 30, 2011 or may affect future results include:

	•		Our capital investment of $271.6 million at our Regulated Operating Subsidiaries ($36.5 million, $66.0 million, $133.8 million and $35.3 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) for the six months ended June 30, 2011, resulting primarily from our focus on improving system reliability and interconnecting new generating resources;
	•		Debt issuances and borrowings under our revolving credit agreements in 2011 to fund capital investment at our Regulated Operating Subsidiaries, resulting in higher interest expense; and
	•		Final recognition of revenues for the ITCTransmission rate freeze revenue deferral in May 2011, described below under “Cost-Based Formula Rates with True-Up Mechanism — ITCTransmission’s Rate Freeze Revenue Deferral.” There will be a $6.9 million reduction in network revenues in 2011 relating to the collection of the revenue accrual for the period from January through May 2011 compared to the year ended December 31, 2010, which is expected to result in a reduction to after-tax net income of approximately $4.3 million in 2011 compared to 2010.

     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

   ITC Great Plains

    KETA Project

     The KETA Project is a 225 mile transmission line that will run between Spearville, Kansas and Axtell, Nebraska. Through June 30, 2011, ITC Great Plains has recorded construction work in progress of $43.8 million for the KETA Project. We estimate that the cost for ITC Great Plains’ portion of the KETA Project will be approximately $203 million.

   Kansas V-Plan Project

     The Kansas V-Plan Project is a 200 mile long transmission line that will run between Spearville and Wichita, Kansas. The portion of the transmission line that ITC Great Plains is responsible for constructing from Spearville to Medicine Lodge, Kansas will run approximately 120 miles. The Kansas Corporation Commission approved ITC Great Plains’ request for a transmission line siting permit on July 12, 2011. ITC Great Plains is in the process of obtaining the remaining permits necessary to begin construction related activities for the project. We estimate that ITC Great Plains will invest approximately $300 million to construct its portion of the project.

   Regulatory Assets

     As of June 30, 2011, we have recorded a total of $13.6 million of regulatory assets for start-up and development expenses incurred by ITC Great Plains, which include certain costs incurred for the KETA Project and the Kansas V-Plan Project prior to construction. In March 2011, we recognized the Kansas V-Plan regulatory asset of $2.0 million and corresponding reduction to operating expenses, which resulted in net income of $1.3 million. Subsequent to the initial recognition of the Kansas V-Plan regulatory asset in March 2011, we recorded an additional $1.1 million of cost incurred for the Kansas V-Plan Project during the quarter ended June 30, 2011 directly to regulatory assets. Based on ITC Great Plains’ application and the related FERC order, ITC Great Plains will be required to make an additional filing with the FERC under Section 205 of the Federal Power Act in order to recover these start-up, development and pre-construction expenses in future rates.

   Green Power Express

     The Green Power Express project consists of transmission line segments that would facilitate the movement of power from the wind-abundant areas in the Dakotas, Minnesota and Iowa to Midwest load centers that demand clean, renewable energy. The FERC issued an order authorizing certain transmission investment incentives, including the establishment of a regulatory asset for start-up and development costs of Green Power Express and certain pre-construction costs for the project to be recovered pursuant to a future FERC filing. Further, the FERC order conditionally accepted Green Power Express’ proposed formula rate tariff sheets, subject to refund, and set them for hearing and settlement procedures. On February 22, 2010, Green Power Express filed an Offer of Settlement

that intended to resolve all of the issues set for hearing. On May 19, 2011, the FERC approved the proposed settlement of the formula rate and related issues that had been pending since the February 2010 offer. The amount of any future capital expenditures on this project is currently unknown.

     The total development expenses through June 30, 2011 that may be recoverable through regulatory assets were approximately $5.5 million, which have been recorded to expenses in the periods in which they were incurred. If in a future reporting period it becomes probable that future revenues will result from the authorization to recover these development expenses, we will recognize the regulatory assets. No regulatory assets or construction work in progress for Green Power Express has been recorded as of June 30, 2011.

   Thumb Loop Project

     In 2010, we received MISO approval of the Thumb Loop Project primarily located in ITCTransmission’s region with a total expected capital investment of $510 million. The Thumb Loop Project 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. Siting approval was requested from the MPSC in August 2010 and granted by the MPSC in February 2011. Certain parties have filed an appeal of the MPSC approval, but the MPSC decision remains valid during the appeal process. Significant capital investments for this project are expected to occur beginning in 2012.

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 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.

   ITCTransmission’s Rate Freeze Revenue Deferral

     ITCTransmission’s rate freeze revenue deferral resulted from the regulatory authority to bill and collect certain revenue requirements calculated for historical periods. This revenue deferral resulted from the difference between the revenue ITCTransmission would have collected under its cost based formula rate and the actual revenue ITCTransmission received based on the frozen rate of $1.075 kW/month for the period from February 28, 2003 through December 31, 2004. The cumulative revenue deferral at the end of the rate freeze was $59.7 million ($38.8 million net of tax). The revenue deferral was amortized for ratemaking on a straight-line basis for five years from June 2006 through May 2011 and was included in ITCTransmission’s revenue requirement for those periods. Revenues of $11.9 million were recognized in 2010 relating to the rate freeze revenue deferral and revenues of $5.0 million were recognized in January through May 2011. The $6.9 million reduction in revenues is also expected to result in a reduction to after-tax net income of approximately $4.3 million in 2011 compared to 2010.

   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 revenue requirement for a reporting period, a revenue accrual is recorded for the difference. To the extent that amounts billed are more than 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 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.

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

Capital Investment Forecasts 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 and interconnect new generating resources. 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 accessibility to generation sources of choice, including renewable sources. The Energy Policy Act of 2005 requires the FERC to implement mandatory electric transmission reliability standards to be enforced by an Electric Reliability Organization. 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 capital investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.

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

system to address demographic changes that have impacted transmission load and the changing role that 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:

     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.

     Network revenues increased due primarily to higher revenue requirements at our Regulated Operating Subsidiaries during the three months ended June 30, 2011 as compared to the same period in 2010. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service.

     Regional cost sharing revenues increased due primarily to additional capital projects that have been identified by MISO as eligible for regional cost sharing. 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.

     Other revenues increased due primarily to revenue recognized at METC for utilization of its jointly-owned lines under its transmission ownership and operating agreements.

      Six months ended June 30, 2011 compared to six months ended June 30, 2010

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