XNYS:ITC ITC Holdings Corp Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended June 30, 2012
OR
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-32576
ITC HOLDINGS CORP.
(Exact Name of Registrant as Specified in Its Charter)
Michigan
(State or Other Jurisdiction of Incorporation or Organization)
 
32-0058047
(I.R.S. Employer Identification No.)
27175 Energy Way
Novi, MI 48377
(Address Of Principal Executive Offices, Including Zip Code)

(248) 946-3000
(Registrant’s Telephone Number, Including Area Code)
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ
 
Accelerated filer o
 
Non-accelerated filer o
 
Smaller Reporting Company o
 
 
 
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The number of shares of the Registrant’s Common Stock, without par value, outstanding as of July 27, 2012 was 51,501,942.
 




ITC Holdings Corp.
Form 10-Q for the Quarterly Period Ended June 30, 2012
INDEX

 
Page
Exhibit Index
 EX-10.102
 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



2


DEFINITIONS
Unless otherwise noted or the context requires, all references in this report to:
ITC Holdings Corp. and its subsidiaries
“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;
“ITC Grid Development” are references to ITC Grid Development, LLC, a wholly-owned subsidiary of ITC Holdings;
“Green Power Express” are references to Green Power Express LP, an indirect wholly-owned subsidiary of ITC Holdings;
“ITC Holdings” are references to ITC Holdings Corp. and not any of its subsidiaries;
“ITC Midwest” are references to ITC Midwest LLC, a wholly-owned subsidiary of ITC Holdings;
“ITCTransmission” are references to International Transmission Company, a wholly-owned subsidiary of ITC Holdings;
“METC” are references to Michigan Electric Transmission Company, LLC, a wholly-owned subsidiary of MTH;
“MISO Regulated Operating Subsidiaries” are references to ITCTransmission, METC and ITC Midwest together;
“MTH” are references to Michigan Transco Holdings, LLC, the sole member of METC and an indirect wholly-owned subsidiary of ITC Holdings;
“Regulated Operating Subsidiaries” are references to ITCTransmission, METC, ITC Midwest and ITC Great Plains together; and
“We,” “our” and “us” are references to ITC Holdings together with all of its subsidiaries.
Other definitions
“Consumers Energy” are references to Consumers Energy Company, a wholly-owned subsidiary of CMS Energy Corporation;
“Detroit Edison” are references to The Detroit Edison Company, a wholly-owned subsidiary of DTE Energy Company;
“Entergy” are references to Entergy Corporation;
“FERC” are references to the Federal Energy Regulatory Commission;
“FPA” are references to the Federal Power Act;
“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;
“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.


3


PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)
 
June 30,
 
December 31,
(in thousands, except share data)
2012
 
2011
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
38,518

 
$
58,344

Accounts receivable
110,458

 
76,895

Inventory
35,045

 
34,855

Deferred income taxes
21,503

 
20,636

Regulatory assets — revenue accruals, including accrued interest
6,163

 
6,639

Prepaid assets
19,327

 
4,128

Other
37

 
31

Total current assets
231,051

 
201,528

Property, plant and equipment (net of accumulated depreciation and amortization of $1,230,248 and $1,193,164, respectively)
3,798,197

 
3,415,823

Other assets
 
 
 
Goodwill
950,163

 
950,163

Intangible assets (net of accumulated amortization of $16,828 and $15,276, respectively)
46,113

 
46,885

Regulatory assets — revenue accruals, including accrued interest
10,940

 
5,637

Other regulatory assets
170,320

 
161,987

Deferred financing fees (net of accumulated amortization of $16,062 and $14,594, respectively)
20,477

 
20,989

Other
26,963

 
20,354

Total other assets
1,224,976

 
1,206,015

TOTAL ASSETS
$
5,254,224

 
$
4,823,366

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
128,239

 
$
136,934

Accrued payroll
14,300

 
18,013

Accrued interest
59,844

 
43,642

Accrued taxes
30,460

 
25,627

Regulatory liabilities — revenue deferrals, including accrued interest
49,206

 
46,579

Refundable deposits from generators for transmission network upgrades
59,363

 
38,805

Other
14,689

 
5,867

Total current liabilities
356,101

 
315,467

Accrued pension and postretirement liabilities
41,689

 
44,923

Deferred income taxes
416,521

 
373,268

Regulatory liabilities — revenue deferrals, including accrued interest
36,299

 
50,917

Regulatory liabilities — accrued asset removal costs
80,607

 
83,934

Refundable deposits from generators for transmission network upgrades
2,296

 
14,570

Other
43,501

 
36,373

Long-term debt
2,963,304

 
2,645,022

Commitments and contingent liabilities (Note 12)


 


STOCKHOLDERS’ EQUITY
 
 
 
Common stock, without par value, 100,000,000 shares authorized, 51,489,481 and 51,323,368 shares issued and outstanding at June 30, 2012 and December 31, 2011, respectively
950,383

 
943,444

Retained earnings
383,015

 
330,816

Accumulated other comprehensive loss
(19,492
)
 
(15,368
)
Total stockholders’ equity
1,313,906

 
1,258,892

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
5,254,224

 
$
4,823,366

See notes to condensed consolidated financial statements (unaudited).


4


ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands, except per share data)
2012
 
2011
 
2012
 
2011
OPERATING REVENUES
$
197,375

 
$
185,098

 
$
394,088

 
$
364,484

OPERATING EXPENSES
 
 
 
 
 
 
 
Operation and maintenance
30,058

 
28,837

 
58,770

 
55,121

General and administrative
27,876

 
19,289

 
50,885

 
35,869

Depreciation and amortization
25,976

 
23,352

 
50,987

 
46,440

Taxes other than income taxes
15,185

 
13,556

 
29,465

 
27,164

Other operating (income) and expense — net
(203
)
 
(167
)
 
(396
)
 
(316
)
Total operating expenses
98,892

 
84,867

 
189,711

 
164,278

OPERATING INCOME
98,483

 
100,231

 
204,377

 
200,206

OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
Interest expense
40,084

 
36,484

 
77,994

 
72,754

Allowance for equity funds used during construction
(4,554
)
 
(4,099
)
 
(10,178
)
 
(7,609
)
Other income
(1,226
)
 
(497
)
 
(1,287
)
 
(718
)
Other expense
472

 
1,594

 
1,058

 
2,269

Total other expenses (income)
34,776

 
33,482

 
67,587

 
66,696

INCOME BEFORE INCOME TAXES
63,707

 
66,749

 
136,790

 
133,510

INCOME TAX PROVISION
21,321

 
23,753

 
48,353

 
48,512

NET INCOME
$
42,386

 
$
42,996

 
$
88,437

 
$
84,998

Basic earnings per common share (Note 8)
$
0.82

 
$
0.84

 
$
1.72

 
$
1.67

Diluted earnings per common share (Note 8)
$
0.81

 
$
0.83

 
$
1.70

 
$
1.64

Dividends declared per common share
$
0.3525

 
$
0.3350

 
$
0.7050

 
$
0.6700

See notes to condensed consolidated financial statements (unaudited).



5


ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands)
2012
 
2011
 
2012
 
2011
NET INCOME
$
42,386

 
$
42,996

 
$
88,437

 
$
84,998

OTHER COMPREHENSIVE LOSS
 
 
 
 
 
 
 
Amortization of interest rate lock cash flow hedges (net of tax of $2 and $9 for the three months ended June 30, 2012 and 2011, respectively, and net of tax of $12 and $17 for the six months ended June 30, 2012 and 2011, respectively)
22

 
16

 
37

 
32

Unrealized loss on interest rate swaps relating to interest rate cash flow hedges (net of tax of $4,486 and $1,086 for the three months ended June 30, 2012 and 2011, respectively, and net of tax of $2,683 and $630 for the six months ended June 30, 2012 and 2011, respectively)
(6,973
)
 
(1,697
)
 
(4,161
)
 
(983
)
TOTAL OTHER COMPREHENSIVE LOSS, NET OF TAX
(6,951
)
 
(1,681
)
 
(4,124
)
 
(951
)
TOTAL COMPREHENSIVE INCOME
$
35,435

 
$
41,315

 
$
84,313

 
$
84,047

See notes to condensed consolidated financial statements (unaudited).



6


ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
Six months ended
 
June 30,
(in thousands)
2012
 
2011
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
88,437

 
$
84,998

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
50,987

 
46,440

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
(16,818
)
 
18,116

Deferred income tax expense
30,728

 
31,421

Allowance for equity funds used during construction
(10,178
)
 
(7,609
)
Other
6,171

 
7,554

Changes in assets and liabilities, exclusive of changes shown separately:
 
 
 
Accounts receivable
(24,551
)
 
(16,036
)
Inventory
(190
)
 
2,537

Prepaid assets
(15,198
)
 
(4,034
)
Other current assets
(6
)
 
2,432

Accounts payable
(2,437
)
 
969

Accrued payroll
(2,187
)
 
(5,143
)
Accrued interest
16,202

 
304

Accrued taxes
5,914

 
10,292

Other current liabilities
8,822

 
(2,012
)
Other non-current assets and liabilities, net
(1,995
)
 
(2,444
)
Net cash provided by operating activities
133,701

 
167,785

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Expenditures for property, plant and equipment
(435,745
)
 
(228,028
)
Proceeds from sale of securities
5,453

 
3,809

Purchases of securities
(10,105
)
 
(7,160
)
Other
(881
)
 
578

Net cash used in investing activities
(441,278
)
 
(230,801
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
100,000

 

Borrowings under revolving credit agreements
723,350

 
377,415

Repayments of revolving credit agreements
(505,300
)
 
(308,775
)
Issuance of common stock
2,831

 
15,025

Dividends on common stock
(36,238
)
 
(34,189
)
Refundable deposits from generators for transmission network upgrades
22,114

 
9,054

Repayment of refundable deposits from generators for transmission network upgrades
(13,830
)
 
(4,876
)
Other
(5,176
)
 
(4,512
)
Net cash provided by financing activities
287,751

 
49,142

NET DECREASE IN CASH AND CASH EQUIVALENTS
(19,826
)
 
(13,874
)
CASH AND CASH EQUIVALENTS — Beginning of period
58,344

 
95,109

CASH AND CASH EQUIVALENTS — End of period
$
38,518

 
$
81,235

See notes to condensed consolidated financial statements (unaudited).


7


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. GENERAL
These condensed consolidated financial statements should be read in conjunction with the notes to the consolidated financial statements as of and for the year ended December 31, 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
 
Six months ended
 
June 30,
(in thousands)
2012
 
2011
Supplementary cash flows information:
 
 
 
Interest paid (net of interest capitalized)
$
59,607

 
$
71,168

Income taxes paid
24,733

 
14,196

Supplementary non-cash investing and financing activities:
 
 
 
Additions to property, plant and equipment (a)
$
94,625

 
$
73,282

Allowance for equity funds used during construction
10,178

 
7,609

____________________________
(a)
Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of June 30, 2012 or 2011, respectively, but have been or will be included as a cash outflow from investing activities for expenditures for property, plant and equipment when paid.
2. RECENT ACCOUNTING PRONOUNCEMENTS
Presentation of Comprehensive Income
The guidance set forth by the Financial Accounting Standards Board (“FASB”) 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.


8


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.


9


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:
(in thousands)
ITCTransmission
 
METC
 
ITC Midwest
 
ITC Great Plains
 
Total
Balance as of December 31, 2011
$
(56,269
)
 
$
(20,910
)
 
$
(6,164
)
 
$
(1,877
)
 
$
(85,220
)
Net refunds (collections) of 2010 revenue deferrals and accruals, including interest
15,320

 
4,745

 
299

 
(48
)
 
20,316

Net revenue accruals (deferrals) for the six months ended June 30, 2012
(1,472
)
 
1,061

 
3,872

 
(5,519
)
 
(2,058
)
Net accrued interest payable for the six months ended June 30, 2012
(883
)
 
(310
)
 
(202
)
 
(45
)
 
(1,440
)
Balance as of June 30, 2012
$
(43,304
)
 
$
(15,414
)
 
$
(2,195
)
 
$
(7,489
)
 
$
(68,402
)
Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals are recorded in our condensed consolidated statement of financial position as follows:
(in thousands)
ITCTransmission
 
METC
 
ITC Midwest
 
ITC Great Plains
 
Total
Current assets
$
433

 
$
1

 
$
4,597

 
$
1,132

 
$
6,163

Non-current assets

 
4,304

 
5,881

 
755

 
10,940

Current liabilities
(28,968
)
 
(10,422
)
 
(7,745
)
 
(2,071
)
 
(49,206
)
Non-current liabilities
(14,769
)
 
(9,297
)
 
(4,928
)
 
(7,305
)
 
(36,299
)
Balance as of June 30, 2012
$
(43,304
)
 
$
(15,414
)
 
$
(2,195
)
 
$
(7,489
)
 
$
(68,402
)
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


10


Notes due July 15, 2013:
Interest Rate Swaps
 
Notional Amount
 
Fixed Rate
 
Original Term
 
Effective Date
(amounts in millions)
 
 
 
 
 
 
 
 
September 2010 swap
 
$
50.0

 
3.60%
 
10 years
 
July 2013
March 2011 swaps
 
50.0

 
4.45%
 
10 years
 
July 2013
May 2011 swap
 
25.0

 
4.20%
 
10 years
 
July 2013
August 2011 swaps
 
50.0

 
3.80%
 
10 years
 
July 2013
Total
 
$
175.0

 
 
 
 
 
 
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
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:
(amounts in millions)
 Total
Available
Capacity
 
Outstanding
Balance (a)
 
Unused
Capacity
 
Weighted-Average
Interest Rate on
Outstanding Balance
 
Commitment
Fee Rate (b)
 
Original
Term
 
Date of Maturity
Revolving Credit Agreements:
ITC Holdings
$
200.0

 
$
155.6

 
$
44.4

 
2.0%
(c)
 
0.25
%
 
5 years
 
May 2016
ITCTransmission
100.0

 
44.8

 
55.2

 
1.4%
(d)
 
0.125
%
 
5 years
 
May 2016
METC
100.0

 
71.4

 
28.6

 
1.4%
(e)
 
0.125
%
 
5 years
 
May 2016
ITC Midwest
175.0

 
66.9

 
108.1

 
1.2%
(f)
 
0.10
%
 
5 years
 
May 2017
ITC Great Plains
150.0

 
80.4

 
69.6

 
2.0%
(g)
 
0.30
%
 
4 years
 
February 2015
Total
$
725.0

 
$
419.1

 
$
305.9

 
 
 
 
 
 
 
 
 
____________________________
(a)
Included within long-term debt.
(b)
Calculation based on the average daily unused commitments, subject to adjustment based on the borrower's credit rating.
(c)
Loan bears 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, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.75%, subject to adjustments based on ITC Holdings' credit rating.
(d)
Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.15% or at a base rate, which is defined as


11


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.
(e)
Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.15% or at a base rate, which is defined as 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 METC's credit rating.
(f)
Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.00% or at a base rate, which is defined as the higher of prime rate, 0.50% above over the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.00%, subject to adjustments based on ITC Midwest's credit rating.
(g)
Loan bears 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, 0.50% above the federal funds rate or 1% above the one month LIBOR, plus an applicable margin of 0.75%, subject to adjustments based on ITC Great Plains' credit rating.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries, selling or otherwise disposing of all or substantially all of our assets and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and maintaining certain interest coverage ratios. We are currently in compliance with all debt covenants.
6. STOCKHOLDERS' EQUITY
ITC Holdings Sales Agency Financing Agreement
On July 27, 2011, ITC Holdings entered into a Sales Agency Financing Agreement with Deutsche Bank Securities Inc. as sales agent (the "SAFA"). Under the terms of the SAFA, ITC Holdings may issue and sell shares of common stock, without par value, from time to time, up to an aggregate sales proceeds amount of $250.0 million. The SAFA terminates in July 2014, although the agreements relating to the Entergy Transaction generally prohibit us from issuing shares under the SAFA until approximately two years after the closing except under certain limited circumstances. The shares of common stock may be offered in one or more selling periods. Any shares of common stock sold under the SAFA will be offered at market prices prevailing at the time of sale. Moreover, ITC Holdings will specify to the sales agent (i) the aggregate selling price of the shares of common stock to be sold during each selling period, and (ii) the minimum price below which sales may not be made. ITC Holdings will pay a commission equal to a mutually agreed upon rate with its agent, not to exceed 2% of the sales price of all shares of common stock sold through its agent under the SAFA, plus expenses. The shares we would issue under the SAFA have been registered under ITC Holdings’ shelf registration statement on Form S-3 (File No. 333-163716) 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.


12


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:
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands, except share, per share data and percentages)
2012
 
2011
 
2012
 
2011
Numerator:
 
 
 
 
 
 
 
Net income
$
42,386

 
$
42,996

 
$
88,437

 
$
84,998

Less: dividends declared — common shares, restricted shares and deferred stock units (a)
(18,137
)
 
(17,182
)
 
(36,238
)
 
(34,189
)
Undistributed earnings
24,249

 
25,814

 
52,199

 
50,809

Percentage allocated to common shares (b)
98.7
%
 
98.2
%
 
98.7
%
 
98.2
%
Undistributed earnings — common shares
23,934

 
25,349

 
51,520

 
49,894

Add: dividends declared — common shares
17,907

 
16,857

 
35,758

 
33,571

Numerator for basic and diluted earnings per common share
$
41,841

 
$
42,206

 
$
87,278

 
$
83,465

Denominator:
 
 
 
 
 
 
 
Denominator for basic earnings per common share — weighted-average common shares
50,743,576

 
50,236,721

 
50,689,888

 
50,082,531

Incremental shares for stock options and employee stock purchase plan
748,599

 
784,659

 
758,716

 
787,643

Denominator for diluted earnings per common share — adjusted weighted-average shares and assumed conversion
51,492,175

 
51,021,380

 
51,448,604

 
50,870,174

Per common share net income:
 
 
 
 
 
 
 
Basic
$
0.82

 
$
0.84

 
$
1.72

 
$
1.67

Diluted
$
0.81

 
$
0.83

 
$
1.70

 
$
1.64

____________________________
(a)
Includes dividends paid in the form of shares for deferred stock units.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(b)
Weighted-average common shares outstanding
50,743,576

 
50,236,721

 
50,689,888

 
50,082,531

 
Weighted-average restricted shares and deferred stock units (participating securities)
678,248

 
911,487

 
693,669

 
896,276

 
 Total
51,421,824

 
51,148,208

 
51,383,557

 
50,978,807

 
 Percentage allocated to common shares
98.7
%
 
98.2
%
 
98.7
%
 
98.2
%
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.


13


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:
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands)
2012
 
2011
 
2012
 
2011
Service cost
$
1,040

 
$
894

 
$
2,080

 
$
1,792

Interest cost
648

 
604

 
1,295

 
1,229

Expected return on plan assets
(569
)
 
(474
)
 
(1,139
)
 
(948
)
Amortization of prior service cost
(11
)
 
(11
)
 
(21
)
 
(21
)
Amortization of unrecognized loss
867

 
591

 
1,735

 
1,304

Net pension cost
$
1,975

 
$
1,604

 
$
3,950

 
$
3,356

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:
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
(in thousands)
2012
 
2011
 
2012
 
2011
Service cost
$
1,359

 
$
857

 
$
2,717

 
$
1,715

Interest cost
388

 
322

 
776

 
643

Expected return on plan assets
(254
)
 
(185
)
 
(508
)
 
(369
)
Amortization of prior service cost
31

 
79

 
62

 
157

Amortization of unrecognized loss
133

 
56

 
267

 
110

Net postretirement cost
$
1,657

 
$
1,129

 
$
3,314

 
$
2,256

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.


14


Our assets and liabilities measured at fair value subject to the three-tier hierarchy at June 30, 2012, were as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
Active Markets for
Identical Assets
 
Significant
Other Observable
Inputs
 
Significant
Unobservable
Inputs
(in thousands)
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Cash and cash equivalents — cash equivalents
$
26,115

 
$
9,268

 
$

Mutual funds — fixed income securities
20,561

 

 

Mutual funds — equity securities
1,514

 

 

Financial liabilities measured on a recurring basis:
 
 
 
 
 
Interest rate swap derivatives

 
(31,103
)
 

Total
$
48,190

 
$
(21,835
)
 
$

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2011, were as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
Active Markets for
Identical Assets
 
Significant
Other Observable
Inputs
 
Significant
Unobservable
Inputs
(in thousands)
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Cash and cash equivalents — cash equivalents
$
15,004

 
$
34,246

 
$

Mutual funds — fixed income securities
15,551

 

 

Mutual funds — equity securities
1,107

 

 

Financial liabilities measured on a recurring basis:
 
 
 
 
 
Interest rate swap derivatives

 
(24,258
)
 

Total
$
31,662

 
$
9,988

 
$


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.


15


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
Environmental Matters
Our Regulated Operating Subsidiaries’ operations are subject to federal, state, and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as at properties currently owned or operated by our Regulated Operating Subsidiaries. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our Regulated Operating Subsidiaries’ costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.
Our Regulated Operating Subsidiaries’ assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties our Regulated Operating Subsidiaries own or operate have been used for many years, and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained PCBs. Our Regulated Operating Subsidiaries’ facilities and equipment are often situated close to or on property owned by others so that, if they are the source of contamination, other’s property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that our Regulated Operating Subsidiaries do not own, and, at some of our Regulated Operating Subsidiaries’ transmission stations, transmission assets (owned or operated by our Regulated Operating


16


Subsidiaries) and distribution assets (owned or operated by our Regulated Operating Subsidiaries’ transmission customer) are commingled.
Some properties in which our Regulated Operating Subsidiaries have an ownership interest or at which they operate are, and others are suspected of being, affected by environmental contamination. Our Regulated Operating Subsidiaries are not aware of any pending or threatened claims against them with respect to environmental contamination, or of any investigation or remediation of contamination at any properties, that entail costs likely to materially affect them. Some facilities and properties are located near environmentally sensitive areas such as wetlands.
Claims have been made or threatened against electric utilities for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields associated with electric transmission and distribution lines. While our Regulated Operating Subsidiaries do not believe that a causal link between electromagnetic field exposure and injury has been generally established and accepted in the scientific community, if such a relationship is established or accepted, the liabilities and costs imposed on our business could be significant. We are not aware of any pending or threatened claims against our Regulated Operating Subsidiaries for bodily injury, disease or other damages allegedly related to exposure to electromagnetic fields and electric transmission and distribution lines that entail costs likely to have a material adverse effect on our results of operations, financial position or liquidity.
Litigation
We are involved in certain legal proceedings before various courts, governmental agencies and mediation panels concerning matters arising in the ordinary course of business. These proceedings include certain contract disputes, regulatory matters and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our operations or consolidated financial statements in the period in which they are resolved.
Michigan Sales and Use Tax Audit
The Michigan Department of Treasury conducted a sales and use tax audit of ITCTransmission for the audit period April 1, 2005 through June 30, 2008 and has denied ITCTransmission’s use of the industrial processing exemption from use tax it has taken beginning January 1, 2007. ITCTransmission has certain administrative and judicial appeal rights.
ITCTransmission believes that its utilization of the industrial processing exemption is appropriate and intends to defend itself against the denial of such exemption. However, it is reasonably possible that the assessment of additional use tax could be sustained after all administrative appeals and litigation have been exhausted.
The amount of use tax liability associated with the exemptions taken by ITCTransmission through 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


17


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.


18


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:
 
Three months ended
 
Six months ended
OPERATING REVENUES:
June 30,
 
June 30,
(in thousands)
2012
 
2011
 
2012
 
2011
Regulated Operating Subsidiaries
$
197,396

 
$
185,115

 
$
394,129

 
$
364,518

ITC Holdings and other
152

 
91

 
304

 
192

Intercompany eliminations
(173
)
 
(108
)
 
(345
)
 
(226
)
Total Operating Revenues
$
197,375

 
$
185,098

 
$
394,088

 
$
364,484

 
Three months ended
 
Six months ended
INCOME BEFORE INCOME TAXES:
June 30,
 
June 30,
(in thousands)
2012
 
2011
 
2012
 
2011
Regulated Operating Subsidiaries
$
94,294

 
$
89,424

 
$
195,218

 
$
179,939

ITC Holdings and other
(30,587
)
 
(22,675
)
 
(58,428
)
 
(46,429
)
Total Income Before Income Taxes
$
63,707

 
$
66,749

 
$
136,790

 
$
133,510

 
Three months ended
 
Six months ended
NET INCOME:
June 30,
 
June 30,
(in thousands)
2012
 
2011
 
2012
 
2011
Regulated Operating Subsidiaries (a)
$
58,564

 
$
52,814

 
$
121,039

 
$
108,533

ITC Holdings and other
42,386

 
42,996

 
88,437

 
84,998

Intercompany eliminations
(58,564
)
 
(52,814
)
 
(121,039
)
 
(108,533
)
Total Net Income
$
42,386

 
$
42,996

 
$
88,437

 
$
84,998

TOTAL ASSETS:
June 30,
 
December 31,
(in thousands)
2012
 
2011
Regulated Operating Subsidiaries
$
5,158,935

 
$
4,711,274

ITC Holdings and other
3,054,374

 
2,845,182

Reconciliations / Intercompany Eliminations (b)
(2,959,085
)
 
(2,733,090
)
Total Assets
$
5,254,224

 
$
4,823,366

____________________________
(a)
In December 2011, MTH was converted into a limited liability company which is treated as a corporation for tax purposes. Prior to December 31, 2011, METC was organized as a single-member limited liability company that was a disregarded entity for federal income tax purposes. METC was treated as a branch of MTH, which was taxed as a multiple-partner limited partnership for federal income tax purposes. Since METC and MTH, its immediate parent, filed as a partnership for federal income tax purposes, they were exempt from federal income taxes. As a result, METC did not record a provision for federal income taxes in its statements of operations or record amounts for federal deferred income tax assets or liabilities on its statements of financial position prior to December 31, 2011. METC now records federal and state income taxes since the operating entity is no longer held by a partnership. The Regulated Operating Subsidiaries segment includes the allocation of taxes for METC for all periods presented.
(b)
Reconciliation of total assets results primarily from differences in the netting of deferred tax assets and liabilities at our Regulated Operating Subsidiaries as compared to the classification in our condensed consolidated statements of financial position.


19


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:
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.
Our Regulated Operating Subsidiaries contract with third parties to provide services for certain aspects of their businesses. If any of these agreements are terminated, our Regulated Operating Subsidiaries may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.
Hazards associated with high-voltage electricity transmission may result in suspension of our Regulated Operating Subsidiaries’ operations or the imposition of civil or criminal penalties.
Our Regulated Operating Subsidiaries are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.
Our Regulated Operating Subsidiaries are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our financial condition, results of operations and cash flows.


20


Acts of war, terrorist attacks and threats, including cyber attacks or threats, or the escalation of military activity in response to such attacks or otherwise may negatively affect our business, financial condition and cash flows.
ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to pay dividends and fulfill our other cash obligations.
We are highly leveraged and our dependence on debt may limit our ability to fulfill our debt obligations and/or to obtain additional financing.
Certain provisions in our debt instruments limit our financial flexibility.
Adverse changes in our credit ratings may negatively affect us.
Provisions in our Articles of Incorporation and bylaws, Michigan corporate law and our debt agreements may impede efforts by our shareholders to change the direction or management of our company.
Provisions in our Articles of Incorporation restrict market participants from voting or owning 5% or more of the outstanding shares of our capital stock.
We may be unable to satisfy the conditions or obtain the approvals required to complete the Entergy Transaction or such approvals may contain material restrictions or conditions.
If completed, the Entergy Transaction may not be successful or achieve its anticipated benefits.
The merger agreement contains provisions that may discourage other companies from trying to acquire us.
Failure to complete the Entergy Transaction could adversely affect the market price of ITC Holdings common stock as well as our business, financial condition and results of operations.
Investors holding shares of ITC Holdings common stock immediately prior to the completion of the Entergy Transaction will, in the aggregate, have a significantly reduced ownership and voting interest in us after the Entergy Transaction and will exercise less influence over management.
We are required to abide by potentially significant restrictions which could limit our ability to undertake certain corporate actions (such as the issuance of ITC Holdings common stock or the undertaking of a merger or consolidation) that otherwise could be advantageous.
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. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events, or otherwise.
OVERVIEW
Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, to reduce transmission constraints and to 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.


21


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:
Our capital investment of $429.2 million at our Regulated Operating Subsidiaries ($104.9 million, $84.6 million, $182.2 million and $57.5 million at ITCTransmission, METC, ITC Midwest and ITC Great Plains, respectively) for the six months ended June 30, 2012, resulting primarily from our focus on improving system reliability and interconnecting new generating resources; and
Debt issuances and borrowings under our revolving credit agreements in 2012 and 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”; and
The proposed transaction with Entergy in which Entergy will divest and merge its electric transmission business with a wholly-owned subsidiary of ITC Holdings (“Entergy Transaction”) as discussed below under “Capital Project Updates and Other Recent Developments.” For the three 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 costs of approximately $2.0 million and $3.5 million, respectively, related to the Entergy Transaction recorded within general and administrative expenses. Certain amounts of the external costs are not expected to be deductible for income tax purposes. The external and internal costs related to the Entergy Transaction are not included as components of revenue requirement as they were incurred at ITC Holdings. The transaction fees are expected to continue to be significant until the transaction is consummated. Completion of the transaction is anticipated to occur in 2013; and
Recognition of the estimated refund obligation at our MISO Regulated Operating Subsidiaries for the FERC audit of ITC Midwest, as discussed in Note 12 to the condensed consolidated financial statements under “Commitments and Contingent Liabilities — FERC Audit of ITC Midwest.”
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.


22


ITC Great Plains
KETA Project
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.
Regulatory Assets
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.
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’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


23


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


24


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)
 
2012
 
2011
 
2010
 
                                   ITCTransmission
 
                         METC
 
ITC Midwest
 
                                   ITCTransmission
 
                         METC

 
ITC Midwest
 
                                   ITCTransmission
 
                         METC
 
ITC Midwest
January
7,264

 
6,145
 
2,789
 
7,326

 
6,045

 
2,777

 
7,255

 
5,947

 
2,838

February
6,919

 
5,754
 
2,584
 
7,261

 
6,058

 
2,854

 
6,998

 
5,800

 
2,782

March
6,926

 
5,709
 
2,437
 
6,946

 
5,715

 
2,520

 
6,620

 
5,376

 
2,517

April
6,319

 
5,083
 
2,264
 
6,483

 
5,416

 
2,458

 
6,501

 
5,112

 
2,425

May
8,947

 
6,461
 
2,665
 
10,119

 
7,239

 
2,773

 
9,412

 
7,240

 
3,052

June
11,676

 
8,627
 
3,459
 
11,488

 
8,231

 
3,403

 
9,722

 
7,128

 
3,207

July
 
 
 
 
 
 
12,321

 
9,389

 
3,621

 
11,451

 
8,498

 
3,422

August
 
 
 
 
 
 
11,158

 
8,538

 
3,614

 
11,082

 
8,422

 
3,399

September
 
 
 
 
 
 
11,288

 
7,966

 
3,466

 
10,817

 
7,353

 
2,804

October
 
 
 
 
 
 
6,642

 
5,479

 
2,559

 
6,725

 
5,414

 
2,447

November
 
 
 
 
 
 
7,101

 
6,061

 
2,556

 
6,930

 
5,734

 
2,674

December
 
 
 
 
 
 
7,206

 
6,071

 
2,734

 
7,824

 
6,526

 
2,928

Total
 
 
 
 
 
 
105,339

 
82,208

 
35,335

 
101,337

 
78,550

 
34,495

____________________________
(a)
Our MISO Regulated Operating Subsidiaries are each part of a joint rate zone. The load data presented is for all transmission owners in the respective joint rate zone and is used for billing network revenues. Each of our MISO Regulated Operating Subsidiaries makes up the most significant portion of the rates or revenue requirement billed to network load within their respective joint rate zone.
Capital Investment and Operating Results Trends
We expect a general trend of increases in revenues and earnings for our Regulated Operating Subsidiaries over the long term. The primary factor that is expected to continue to increase our actual revenue requirements in future years is our anticipated capital investment in excess of depreciation as a result of our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability 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


25


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:
 
 
 
 
Actual Capital
 
Forecasted Capital
 
 
Five-Year Capital
 
Investment for the
 
Investment for the
(in millions)
 
Investment Program
 
six months ended
 
year ending
Operating Subsidiary
 
2012-2016 (a)
 
June 30, 2012 (b)
 
December 31, 2012
ITCTransmission
 
$
739

 
$
104.9

 
$195 — 215

METC
 
581

 
84.6

 
145 — 160

ITC Midwest
 
1,128

 
182.2

 
315 — 335

ITC Great Plains (c)
 
343

 
57.5

 
95 — 110

Development (d)
 
1,390

 

 

Total
 
$
4,181

 
$
429.2

 
$750 — 820

____________________________
(a)
The current five-year capital investment program does not include anticipated expenditures related to the Entergy Transaction. The investments in property, plant and equipment would be expected to increase significantly upon closing of that transaction.
(b)
Capital investment amounts differ from cash expenditures for property, plant and equipment included in our condensed consolidated statements of cash flows due in part to differences in construction costs incurred compared to cash paid during that period, as well as payments for major equipment inventory that are included in cash expenditures but not included in capital investment until transferred to construction work in progress, among other factors.
(c)
ITC Great Plains' investment program includes the KETA Project, Kansas V-Plan Project and Hugo-to-Valliant Project.
(d)
Includes expenditures to construct various development projects such as our portions of the four MISO MVPs.
Investments in property, plant and equipment could vary due to, among other things, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain financing for such expenditures, if necessary, limitations on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a result of legal proceedings and variances between estimated and actual costs of construction contracts awarded. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects, the generator’s potential failure to meet the various criteria of Attachment FF of the MISO tariff for the project to qualify as a refundable network upgrade, and other factors beyond our control.



26


RESULTS OF OPERATIONS
Results of Operations and Variances
 
Three months ended
 
 
 
Percentage
 
Six months ended
 
 
 
Percentage
 
June 30,
 
Increase
 
increase
 
June 30,
 
Increase
 
increase
(in thousands)
2012
 
2011
 
(decrease)
 
(decrease)
 
2012
 
2011
 
(decrease)
 
(decrease)
OPERATING REVENUES
$
197,375

 
$
185,098

 
$
12,277

 
6.6
 %
 
$
394,088

 
$
364,484

 
$
29,604

 
8.1
 %
OPERATING EXPENSES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance
30,058

 
28,837

 
1,221

 
4.2
 %
 
58,770

 
55,121

 
3,649

 
6.6
 %
General and administrative
27,876

 
19,289

 
8,587

 
44.5
 %
 
50,885

 
35,869

 
15,016

 
41.9
 %
Depreciation and amortization
25,976

 
23,352

 
2,624

 
11.2
 %
 
50,987

 
46,440

 
4,547

 
9.8
 %
Taxes other than income taxes
15,185

 
13,556

 
1,629

 
12.0
 %
 
29,465

 
27,164

 
2,301

 
8.5
 %
Other operating (income) and expenses — net
(203
)
 
(167
)
 
(36
)
 
21.6
 %
 
(396
)
 
(316
)
 
(80
)
 
25.3
 %
Total operating expenses
98,892

 
84,867

 
14,025

 
16.5
 %
 
189,711

 
164,278

 
25,433

 
15.5
 %
OPERATING INCOME
98,483

 
100,231

 
(1,748
)
 
(1.7
)%
 
204,377

 
200,206

 
4,171

 
2.1
 %
OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense
40,084

 
36,484

 
3,600

 
9.9
 %
 
77,994

 
72,754

 
5,240

 
7.2
 %
Allowance for equity funds used during construction
(4,554
)
 
(4,099
)
 
(455
)
 
11.1
 %
 
(10,178
)
 
(7,609
)
 
(2,569
)
 
33.8
 %
Other income
(1,226
)
 
(497
)
 
(729
)
 
146.7
 %
 
(1,287
)
 
(718
)
 
(569
)
 
79.2
 %
Other expense
472

 
1,594

 
(1,122
)
 
(70.4
)%
 
1,058

 
2,269

 
(1,211
)
 
(53.4
)%
Total other expenses (income)
34,776

 
33,482

 
1,294

 
3.9
 %
 
67,587

 
66,696

 
891

 
1.3
 %
INCOME BEFORE INCOME TAXES
63,707

 
66,749

 
(3,042
)
 
(4.6
)%
 
136,790

 
133,510

 
3,280

 
2.5
 %
INCOME TAX PROVISION
21,321

 
23,753

 
(2,432
)
 
(10.2
)%
 
48,353

 
48,512

 
(159
)
 
(0.3
)%
NET INCOME
$
42,386

 
$
42,996

 
$
(610
)
 
(1.4
)%
 
$
88,437

 
$
84,998

 
$
3,439

 
4.0
 %
Operating Revenues
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:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2012
 
2011
 
Increase
 
increase
(in thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(decrease)
 
(decrease)
Network revenues
$
156,453

 
79.3
%
 
$
153,947

 
83.2
%
 
$
2,506

 
1.6
 %
Regional cost sharing revenues
29,240

 
14.8
%
 
20,433

 
11.0
%
 
8,807

 
43.1
 %
Point-to-point
4,462

 
2.3
%
 
3,990

 
2.1
%
 
472

 
11.8
 %
Scheduling, control and dispatch
3,704

 
1.9
%
 
3,838

 
2.1
%
 
(134
)
 
(3.5
)%
Other
3,516

 
1.7
%
 
2,890

 
1.6
%
 
626

 
21.7
 %
Total
$
197,375

 
100.0
%
 
$
185,098

 
100.0
%
 
$
12,277

 
6.6
 %
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.


27


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:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2012
 
2011
 
Increase
 
increase
(in thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(decrease)
 
(decrease)
Network revenues
$
319,609

 
81.1
%
 
$
306,427

 
84.1
%
 
$
13,182

 
4.3
%
Regional cost sharing revenues
54,716

 
13.9
%
 
40,039

 
11.0
%
 
14,677

 
36.7
%
Point-to-point
8,587

 
2.2
%
 
7,711

 
2.1
%
 
876

 
11.4
%
Scheduling, control and dispatch
7,079

 
1.8
%
 
6,828

 
1.9
%
 
251

 
3.7