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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Commission File Number: 001-32576
ITC HOLDINGS CORP.
(Exact Name of Registrant as Specified in Its Charter)
27175 Energy Way
Novi, MI 48377
(Address Of Principal Executive Offices, Including Zip Code)
(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 27, 2012 was 51,501,942.
ITC Holdings Corp.
Form 10-Q for the Quarterly Period Ended June 30, 2012
Unless otherwise noted or the context requires, all references in this report to:
ITC Holdings Corp. and its subsidiaries
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)
See notes to condensed consolidated financial statements (unaudited).
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
See notes to condensed consolidated financial statements (unaudited).
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
See notes to condensed consolidated financial statements (unaudited).
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
See notes to condensed consolidated financial statements (unaudited).
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
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, 2011 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
2. RECENT ACCOUNTING PRONOUNCEMENTS
Presentation of Comprehensive Income
The guidance set forth by the Financial Accounting Standards Board (“FASB”) 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 became effective for our interim condensed consolidated financial statements for the quarter ended March 31, 2012 and we have included a separate statement of comprehensive income.
Balance Sheet Offsetting Requirements
The FASB 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). The disclosure requirements are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods therein, with retrospective application required. The new disclosure requirements are not expected to have a material effect on our consolidated financial statements.
Fair Value Disclosures
The FASB amended guidance for fair value measurements and disclosures. The guidance requires additional disclosures relating to fair value measurements categorized within Level 3 of the fair value hierarchy, including quantitative information about unobservable inputs, the valuation process used by the entity and the sensitivity of unobservable input measurements. Additionally, entities are required to disclose the level of the fair value hierarchy for assets and liabilities that are not measured at fair value in the balance sheet, but for which disclosure of the fair value is required. We adopted this guidance as of January 1, 2012, which did not have a material impact on our disclosures. See Note 10 to the condensed consolidated financial statements.
3. REGULATORY MATTERS
ITC Great Plains
As of June 30, 2012, we have recorded a total of $14.0 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. During the first quarter of 2011, we received certain regulatory approvals relating to the Kansas V-Plan Project which resulted in the recognition of the Kansas V-Plan Project 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 Project regulatory asset in March 2011, we have recorded costs for the Kansas V-Plan Project directly to this regulatory asset. 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 FPA in order to recover these start-up, development and pre-construction expenses in future rates. If FERC authorization is received, ITC Great Plains will include the Kansas V-Plan Project and KETA Project regulatory assets in its rate base and begin amortizing them over a 10-year period upon the in-service dates. The amortization expense will be included in ITC Great Plains’ revenue requirement based on its cost-based formula rate template.
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 filing. 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.
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 accrual, including accrued interest. The current and non-current regulatory liabilities are recorded in regulatory liabilities - revenue deferral, 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 six months ended June 30, 2012:
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:
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 for the period from February 28, 2003 through December 31, 2004. The rate freeze 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 $5.0 million relating to the rate freeze revenue deferral were recognized in January through May 2011.
4. INTANGIBLE ASSETS
We have recorded intangible assets as a result of the METC acquisition in 2006. The carrying value of these assets was $41.8 million (net of accumulated amortization of $16.6 million) as of June 30, 2012.
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 $4.3 million (net of accumulated amortization of $0.2 million) as of June 30, 2012.
During the three months ended June 30, 2012 and 2011, we recognized $0.8 million of amortization expense of our intangible assets and $1.6 million and $1.5 million for the six months ended June 30, 2012 and 2011, respectively. For each of the next five years, we expect the annual amortization of our intangible assets that have been recorded as of June 30, 2012 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. The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing $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 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 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, 2012, 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 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, 2012, the fair value of the derivative instruments was a liability of $31.1 million recorded to other non-current liabilities. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 10 for additional fair value information.
ITC Midwest closed on the $100.0 million of 3.50% First Mortgage Bonds, Series E, due January 2027 on January 19, 2012. The proceeds from the issuance will be 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.
On May 31, 2012, ITC Midwest entered into a new unsecured, unguaranteed revolving credit agreement, under which ITC Midwest may borrow up to $175.0 million. The new revolving credit agreement replaced ITC Midwest's two existing revolving credit agreements, dated January 29, 2008 and February 11, 2011, respectively, which were scheduled to mature on January 29, 2013 and February 11, 2013, respectively.
Revolving Credit Agreements
At June 30, 2012, ITC Holdings and its Regulated Operating Subsidiaries had the following revolving credit facilities available:
the higher of the prime rate, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.15%, subject to adjustments based on ITCTransmission's credit rating.
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. 333-163716) filed on December 14, 2009 with the SEC. No shares have been issued under this agreement.
7. SHARE-BASED COMPENSATION
Long-Term Incentive Plan Grants
On May 22, 2012, pursuant to the Second Amended and Restated 2006 Long-Term Incentive Plan, we granted 358,160 options to purchase shares of our common stock with an exercise price of $70.76 per share, which was the closing price of our common stock on the date of grant. The options vest in three equal annual installments with the first installment vesting on May 22, 2013. In addition, on May 22, 2012, we granted 114,862 shares of restricted stock at fair value of $70.76 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 vests 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 70,051 and 543,775 shares of our common stock during the six months ended June 30, 2012 and the year ended December 31, 2011, respectively, due to the exercise of stock options.
8. EARNINGS PER SHARE
We report both basic and diluted earnings per share. A reconciliation of both calculations for the three and six months ended June 30, 2012 and 2011 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, 2012 and 2011, we had 2,386,217 and 2,188,814 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, 2012 and 2011, 572,179 and 218,135 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 $7.0 million to the defined benefit retirement plan relating to the 2011 plan year in June 2012. We do not expect to make any additional contributions in 2012.
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 contributed $4.7 million to these supplemental nonqualified, noncontributory, retirement benefit plans in June 2012. We do not expect to make any additional contributions in 2012.
Net pension cost includes the following components:
Other Postretirement Benefits
We provide certain postretirement health care, dental, and life insurance benefits for employees who may become eligible for these benefits. We contributed $1.0 million to the postretirement benefit plan relating to the 2011 plan year in June 2012. We expect to contribute up to an additional $3.4 million to the postretirement benefit plan relating to the 2011 plan year in December 2012.
Net postretirement 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 the three months ended June 30, 2012 and 2011 and $1.7 million for the six months ended June 30, 2012 and 2011.
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 and liabilities measured at fair value subject to the three-tier hierarchy at June 30, 2012, were as follows:
Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2011, were as follows:
As of June 30, 2012 and December 31, 2011, 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. The liabilities related to derivatives consist of interest rate swaps discussed in Note 5. Our 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 fair value of our interest rate swap derivatives as of June 30, 2012 and December 31, 2011 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 six months ended June 30, 2012. 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, 2011 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 Long-Term Debt
Based on the borrowing rates obtained from third party lending institutions 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 $2,999.7 million and $2,862.6 million at June 30, 2012 and December 31, 2011, respectively. These fair values represent level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt, excluding revolving credit agreements, was $2,544.2 million and $2,444.0 million at June 30, 2012 and December 31, 2011, respectively.
Revolving Credit Agreements
At June 30, 2012 and December 31, 2011, we had a consolidated total of $419.1 million and $201.1 million, respectively, outstanding under our revolving credit agreements, which are variable rate loans. The fair value of these loans approximates book value. These fair values represent level 2 under the three-tier hierarchy described above.
Trade Accounts Receivables and Payables
As of June 30, 2012, 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 are 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 and allowed for deductions and credits for certain activities, none of which are part of the CIT. The change in Michigan tax law resulted in a reduction of income tax provision of $4.6 million during 2011. Additionally, we recorded regulatory assets for this change in tax law. Recovery of the Michigan CIT regulatory asset requires FERC authorization upon us making a filing under Section 205 of the FPA to demonstrate that the costs to be recovered are just and reasonable.
12. COMMITMENTS AND CONTINGENT LIABILITIES
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.
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, 2012 is estimated to be approximately $11.3 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 $11.3 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 IP&L by ITC Midwest. On September 30, 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 which requires adjustments to ITC Midwest's annual revenue requirement calculations and corresponding refunds. On October 31, 2011, ITC Holdings and ITC Midwest filed a request for hearing with the FERC to contest the findings relating to the accounting treatment for the acquisition, which was granted. On May 11, 2012, FERC issued an order that upheld the FERC audit staff position regarding the accounting treatment for the acquisition. As a result, ITC Midwest filed a compliance plan in July 2012 that calculates the effect on its revenue requirements.
ITCTransmission and METC have applied an accounting treatment for their respective acquisitions similar to ITC Midwest, and ITCTransmission and METC expect to file compliance plans with FERC subsequent to FERC accepting the refund methodology in the ITC Midwest compliance plan. As a result of the FERC order, ITC Midwest, ITCTransmission and METC
recorded an aggregate estimated liability for the refund and related interest of $13.0 million during the second quarter. The estimate of the regulatory liability was recorded primarily in other current liabilities and consisted of a reduction in revenues of $11.0 million, a reduction of AFUDC equity of $0.9 million and an increase in interest expense of $1.1 million accrued through June 30, 2012 in these condensed consolidated financial statements, which resulted in a total reduction of net income of $8.4 million after tax for the three and six months ended June 30, 2012. The refund amounts are limited to 2010 and earlier periods and remain subject to FERC acceptance. We do not believe the ultimate resolution of this matter will differ materially from the estimates recorded during the second quarter of 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 at a May 3, 2012 hearing. 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.
Nonconsolidated Variable Interest Entity
In April 2012, we executed a new agreement with Utility Lines Construction Services, Inc. ("ULCS"), which is a division of Asplundh Tree Expert Co., to perform the majority of maintenance for all of our Regulated Operating Subsidiaries. The agreement between us and ULCS contains a variable component related to a cost-plus arrangement which is a consideration for consolidation; however, we are not the primary beneficiary of the variable interest under the agreement. Additionally, we are not subject to risk of loss from ULCS' operations and have not provided, nor will we provide, any significant financial support other than contractual payments. We have evaluated the agreement for possible consolidation, including review of qualitative factors such as the length and terms of the agreement, and have concluded that ULCS is not required to be consolidated in our condensed consolidated financial statements.
13. ENTERGY TRANSACTION
As of December 4, 2011, Entergy and ITC Holdings executed definitive 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 15,700 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. 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, the FERC and ITC Holdings' shareholders.
For the three and six months ended June 30, 2012, we expensed external legal, advisory and financial services fees of $4.1 million and $6.5 million, respectively, and certain internal labor and related costs of approximately $2.0 million and $3.5 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.
14. 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 Item 1A Risk Factors of our Form 10-K for the fiscal year ended December 31, 2011 and the following:
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.
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 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 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 six months ended June 30, 2012 or may affect future results include:
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 April 2012. Through June 30, 2012, ITCTransmission has invested $58.4 million in the Thumb Loop Project. We estimate ITCTransmission will invest approximately $510 million to complete construction of the project.
ITC Great Plains
The KETA Project is a 225 mile transmission line that will run between Spearville, Kansas and Axtell, Nebraska. The portion of the transmission line that ITC Great Plains is responsible for constructing will run approximately 174 miles and the first phase was completed in June 2012. Through June 30, 2012, ITC Great Plains has invested $134.9 million in the KETA Project. We estimate ITC Great Plains will invest approximately $160 million to complete construction of its portion of the project.
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 approximately a 120 mile portion of the project from Spearville to Medicine Lodge, Kansas. Through June 30, 2012, ITC Great Plains has invested $16.7 million in the Kansas V-Plan Project. We estimate that ITC Great Plains will invest approximately $300 million to complete construction of its portion of the project.
As of June 30, 2012, we have recorded a total of $14.0 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 Project regulatory asset of $2.0 million and corresponding reduction to operating expenses, which resulted in net income of $1.3 million. 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 FPA in order to recover these start-up, development and pre-construction expenses in future rates.
North Central Region Development
The Green Power Express project consists 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.
Green Power Express has certain FERC-authorized 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. The amount of future capital expenditures by Green Power Express, if any, is currently unknown.
The total development expenses through June 30, 2012 at Green Power Express 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 have been recorded as of June 30, 2012.
As of December 4, 2011, Entergy and ITC Holdings executed definitive 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 15,700 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 of approximately $700 million, 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. This indebtedness will be assumed by us upon completion of the transaction.
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, the FERC and ITC Holdings’ shareholders. 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 ended December 31, 2011.
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.
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 for the period from February 28, 2003 through December 31, 2004. The rate freeze 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 $5.0 million relating to the rate freeze revenue deferral were recognized in January through May 2011 which resulted in a reduction to after-tax net income of approximately $1.3 million and $3.2 million in the three and six months ended June 30, 2012, respectively, compared to 2011.
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 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.
Monthly Peak Load (in MW) (a)
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 and interconnect 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. Additionally, construction work in progress balances for our KETA Project and Kansas V-Plan Project are included in rate base prior to being placed in service, and are expected to result in significant revenues in 2012 compared to 2011.
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 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.
On October 7, 2010, the NERC issued a recommendation for transmission owners to inspect their transmission systems in order to verify their facility ratings methodology is based on actual field conditions. Each of our MISO Regulated Operating Subsidiaries is undertaking a program to assess its system as a response to the recommendation. There are likely to be costs associated with the assessment and potential system modifications to mitigate instances where actual field conditions necessitate a facility rating that is unacceptable to the reliable operation of the transmission system. The costs and timing for any mitigation will be determined after the assessment is completed, and the appropriate mitigation is planned and may result
in significant operating expenses and/or capital investment. These operating expenses and capital investments would be recovered through higher revenue requirements under the cost-based formula rates of our MISO Regulated Operating Subsidiaries.
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.
RESULTS OF OPERATIONS
Results of Operations and Variances
Three months ended June 30, 2012 compared to three months ended June 30, 2011
The following table sets forth the components of and changes in operating revenues:
Network revenues increased due primarily to higher revenue requirements at our Regulated Operating Subsidiaries during the three months ended June 30, 2012 as compared to the same period in 2011. 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, partially offset by the final amortization of the ITCTransmission rate freeze revenue deferral in May 2011 and the recognition of the FERC audit refund totaling $11.0 million during the second quarter of 2012 as discussed in Note 12 to the condensed consolidated financial statements under “Commitments and Contingent Liabilities — FERC Audit of ITC Midwest.”
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 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.
Six months ended June 30, 2012 compared to six months ended June 30, 2011
The following table sets forth the components of and changes in operating revenues: