UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended September 30, 2015
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 October 30, 2015 was 153,418,988.
 


ITC Holdings Corp.
Form 10-Q for the Quarterly Period Ended September 30, 2015
INDEX

 
Page
Exhibit Index
 
 
 
 
 
 
 
 
 
 
 
 
 



2

DEFINITIONS
Unless otherwise noted or the context requires, all references in this report to:
ITC Holdings Corp. and its subsidiaries
•
“ITC Great Plains” are references to ITC Great Plains, LLC, a wholly-owned subsidiary of ITC Grid Development, LLC;
•
“ITC Grid Development” are references to ITC Grid Development, LLC, a wholly-owned subsidiary of ITC Holdings;
•
“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;
•
“DTE Electric” are references to DTE Electric Company, a wholly-owned subsidiary of DTE Energy Company;
•
“FERC” are references to the Federal Energy Regulatory Commission;
•
“FPA” are references to the Federal Power Act;
•
“IP&L” are references to Interstate Power and Light Company, an Alliant Energy Corporation subsidiary;
•
“ITC Holdings’ annual report on Form 10-K” are references to the annual report on Form 10-K filed on February 26, 2015;
•
“kV” are references to kilovolts (one kilovolt equaling 1,000 volts);
•
“kW” are references to kilowatts (one kilowatt equaling 1,000 watts);
•
“LIBOR” are references to the London Interbank Offered Rate;
•
“MISO” are references to the Midcontinent Independent System Operator, Inc., a FERC-approved RTO which oversees the operation of the bulk power transmission system for a substantial portion of the Midwestern United States and Manitoba, Canada, and of which ITCTransmission, METC and ITC Midwest are members;
•
“NERC” are references to the North American Electric Reliability Corporation;
•
“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)

September 30,

December 31,
(in thousands, except share data)
2015

2014
ASSETS
 


Current assets
 

 
Cash and cash equivalents
$
24,167


$
27,741

Accounts receivable
124,310


100,998

Inventory
29,491


30,892

Deferred income taxes
17,002


14,511

Regulatory assets
12,378


5,393

Prepaid and other current assets
11,598


7,281

Total current assets
218,946


186,816

Property, plant and equipment (net of accumulated depreciation and amortization of $1,466,591 and $1,388,217, respectively)
5,890,138


5,496,875

Other assets
 

 
Goodwill
950,163


950,163

Intangible assets (net of accumulated amortization of $27,411 and $24,917, respectively)
46,325


48,794

Regulatory assets
224,913


223,712

Deferred financing fees (net of accumulated amortization of $16,504 and $15,972, respectively)
30,222


30,311

Other
44,892


37,418

Total other assets
1,296,515


1,290,398

TOTAL ASSETS
$
7,405,599


$
6,974,089

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
Current liabilities
 

 
Accounts payable
$
108,828


$
107,969

Accrued payroll
20,660


23,502

Accrued interest
41,642


50,538

Accrued taxes
26,048


41,614

Regulatory liabilities
43,607


39,972

Refundable deposits from generators for transmission network upgrades
2,657


10,376

Debt maturing within one year
694,327


175,000

Other
11,531


14,043

Total current liabilities
949,300


463,014

Accrued pension and postretirement liabilities
70,833


69,562

Deferred income taxes
746,179


656,562

Regulatory liabilities
210,811


160,070

Refundable deposits from generators for transmission network upgrades
9,039


9,384

Other
27,695


17,354

Long-term debt
3,709,878


3,928,586

Commitments and contingent liabilities (Note 11)





STOCKHOLDERS’ EQUITY
 

 
Common stock, without par value, 300,000,000 shares authorized, 156,177,085 and 155,140,967 shares issued and outstanding at September 30, 2015 and December 31, 2014, respectively
811,037


923,191

Retained earnings
866,900


741,550

Accumulated other comprehensive income
3,927


4,816

Total stockholders’ equity
1,681,864


1,669,557

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
7,405,599


$
6,974,089

See notes to condensed consolidated financial statements (unaudited).


4

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 
 
Three months ended
 
Nine months ended
 
 
September 30,
 
September 30,
(in thousands, except per share data)
 
2015
 
2014
 
2015
 
2014
OPERATING REVENUES
 
$
273,189

 
$
270,134

 
$
820,734

 
$
791,951

OPERATING EXPENSES
 
 
 
 
 
 
 
 
Operation and maintenance
 
32,721

 
29,038

 
88,309

 
79,735

General and administrative
 
33,677

 
28,812

 
107,064

 
87,082

Depreciation and amortization
 
36,890

 
31,936

 
106,903

 
94,609

Taxes other than income taxes
 
20,463

 
19,205

 
61,629

 
57,474

Other operating (income) and expenses — net
 
(206
)
 
(289
)
 
(675
)
 
(750
)
Total operating expenses
 
123,545

 
108,702

 
363,230

 
318,150

OPERATING INCOME
 
149,644

 
161,432

 
457,504

 
473,801

OTHER EXPENSES (INCOME)
 
 
 
 
 

 
 
Interest expense — net
 
51,398

 
47,328

 
150,070

 
138,491

Allowance for equity funds used during construction
 
(6,421
)
 
(4,921
)
 
(21,434
)
 
(14,865
)
Loss on extinguishment of debt
 
—

 
—

 
—

 
29,074

Other income
 
(384
)
 
(244
)
 
(804
)
 
(618
)
Other expense
 
1,372

 
761

 
2,969

 
3,696

Total other expenses (income)
 
45,965

 
42,924

 
130,801

 
155,778

INCOME BEFORE INCOME TAXES
 
103,679

 
118,508

 
326,703

 
318,023

INCOME TAX PROVISION
 
38,106

 
44,635

 
121,662

 
120,678

NET INCOME
 
$
65,573

 
$
73,873

 
$
205,041

 
$
197,345

Basic earnings per common share
 
$
0.42

 
$
0.47

 
$
1.32

 
$
1.26

Diluted earnings per common share
 
$
0.42

 
$
0.47

 
$
1.31

 
$
1.25

Dividends declared per common share
 
$
0.1875

 
$
0.1625

 
$
0.5125

 
$
0.4475

See notes to condensed consolidated financial statements (unaudited).



5

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three months ended
 
Nine months ended
 
 
September 30,
 
September 30,
(in thousands)
 
2015
 
2014
 
2015
 
2014
NET INCOME
 
$
65,573

 
$
73,873

 
$
205,041

 
$
197,345

OTHER COMPREHENSIVE (LOSS) INCOME
 
 
 
 
 
 
 
 
Derivative instruments, net of tax (Note 6)
 
(2,169
)
 
169

 
(910
)
 
(413
)
Available-for-sale securities, net of tax (Note 6)
 
18

 
(86
)
 
21

 
24

TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX
 
(2,151
)
 
83

 
(889
)
 
(389
)
TOTAL COMPREHENSIVE INCOME
 
$
63,422

 
$
73,956

 
$
204,152

 
$
196,956

See notes to condensed consolidated financial statements (unaudited).



6

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
Nine months ended
 
September 30,
(in thousands)
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
205,041

 
$
197,345

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
106,903

 
94,609

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
1,164

 
29,175

Deferred income tax expense
76,103

 
86,935

Allowance for equity funds used during construction
(21,434
)
 
(14,865
)
Loss on extinguishment of debt
—

 
29,074

Other
14,950

 
15,474

Changes in assets and liabilities, exclusive of changes shown separately:
 
 
 
Accounts receivable
(24,523
)
 
(24,057
)
Inventory
1,401

 
1,423

Prepaid and other current assets
(4,317
)
 
3,377

Accounts payable
(1,120
)
 
(16,382
)
Accrued payroll
(1,520
)
 
(1,710
)
Accrued interest
(8,896
)
 
(18,161
)
Accrued taxes
(15,566
)
 
(3,156
)
Other current liabilities
132

 
(13,486
)
Other non-current assets and liabilities, net
57,970

 
(4,694
)
Net cash provided by operating activities
386,288

 
360,901

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Expenditures for property, plant and equipment
(460,110
)
 
(549,599
)
Other
(14,969
)
 
(2,667
)
Net cash used in investing activities
(475,079
)
 
(552,266
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Issuance of long-term debt
225,000

 
498,664

Borrowings under revolving credit agreements
909,400

 
1,397,800

Borrowings under term loan credit agreements
—

 
110,000

Net issuance of commercial paper
218,983

 
—

Retirement of long-term debt — including extinguishment of debt costs
—

 
(248,494
)
Repayments of revolving credit agreements
(1,053,200
)
 
(1,319,500
)
Repayments under term loan credit agreements
—

 
(39,000
)
Issuance of common stock
12,322

 
19,666

Dividends on common and restricted stock
(79,697
)
 
(70,279
)
Refundable deposits from generators for transmission network upgrades
3,458

 
5,833

Repayment of refundable deposits from generators for transmission network upgrades
(11,442
)
 
(22,155
)
Repurchase and retirement of common stock
(21,931
)
 
(108,136
)
Forward contracts of accelerated share repurchase program
(115,000
)
 
(46,000
)
Other
(2,676
)
 
(9,713
)
Net cash provided by financing activities
85,217

 
168,686

NET DECREASE IN CASH AND CASH EQUIVALENTS
(3,574
)
 
(22,679
)
CASH AND CASH EQUIVALENTS — Beginning of period
27,741

 
34,275

CASH AND CASH EQUIVALENTS — End of period
$
24,167

 
$
11,596

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, 2014 included in ITC Holdings’ annual report on Form 10-K for such period.
The accompanying condensed consolidated financial statements have been prepared using accounting principles generally accepted in the United States of America (“GAAP”) and with the instructions to Form 10-Q and Rule 10-01 of Securities and Exchange Commission (“SEC”) Regulation S-X as they apply to interim financial information. Accordingly, they do not include all of the information and notes required by GAAP for complete financial statements. These accounting principles require us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.
The condensed consolidated financial statements are unaudited, but in our opinion include all adjustments (consisting of normal recurring adjustments) necessary for a fair statement of the results for the interim period. The interim financial results are not necessarily indicative of results that may be expected for any other interim period or the fiscal year.
Supplementary Cash Flows Information
 
Nine months ended
 
September 30,
(in thousands)
2015
 
2014
Supplementary cash flows information:
 
 
 
Interest paid (net of interest capitalized)
$
153,350

 
$
154,410

Income taxes paid — net
49,599

 
25,744

Supplementary non-cash investing and financing activities:
 
 
 
Additions to property, plant and equipment and other long-lived assets (a)
$
85,386

 
$
92,557

Allowance for equity funds used during construction
21,434

 
14,865

____________________________
(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 September 30, 2015 or 2014, 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
Revenue Recognition
In May 2014, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance requiring entities to apply a new model for recognizing revenue from contracts with customers. The guidance will supersede the current revenue recognition guidance and require entities to evaluate their revenue recognition arrangements using a five step model to determine when a customer obtains control of a transferred good or service. The guidance is effective for annual reporting periods beginning after December 15, 2017 and may be adopted using a full or modified retrospective application. We do not expect the guidance to have a material impact on our consolidated results of operations, cash flows, or financial position.
Going Concern
In August 2014, the FASB issued authoritative guidance on (1) how to perform a going concern assessment and (2) when going concern disclosures are required under GAAP. The guidance extends the responsibility for performing a going concern assessment to company management; previously this requirement existed only in auditing literature. The standard is expected to enhance the timeliness, clarity, and consistency of going concern disclosures. The guidance is effective for the annual period ending after December 15, 2016, and for interim periods and annual periods thereafter. Early application is permitted. We do not expect the standard to have a material impact on our consolidated financial statements, including our disclosure.
Amendments to the Consolidation Analysis
In February 2015, the FASB issued authoritative guidance that amends the variable interest entity consolidation analysis under GAAP. The new standard was issued to improve targeted areas of consolidation guidance; though the FASB’s


8

deliberations were largely focused on the investment management industry, the standard is applicable for reporting entities across industries. Specifically, the guidance amends the consolidation analysis for limited partnerships, clarifies when fees paid to a decision maker should be a factor in the consolidation analysis and amends how variable interests held by related parties affect consolidation. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early application is permitted. We do not expect the standard to have a material impact on our consolidated financial statements.
Amendment to the Balance Sheet Presentation of Debt Issuance Costs
In April 2015, the FASB issued authoritative guidance that amends the balance sheet presentation of debt issuance costs. This new standard requires debt issuance costs to be shown as a direct deduction from the carrying amount of the related debt, consistent with debt discounts. The guidance is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015 and will be applied retrospectively. Early adoption is permitted. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. We are currently assessing the impact this guidance may have on our consolidated statements of financial position and disclosures. The standard will not impact our consolidated statements of operations or cash flows.
3.    REGULATORY MATTERS
Start-Up, Development and Pre-Construction Regulatory Assets
ITC Great Plains made a filing with the FERC under Section 205 of the FPA in May 2013 to recover start-up, development and pre-construction expenses, including associated debt and equity carrying charges, in future rates. These expenses included certain costs incurred by ITC Great Plains for the Kansas Electric Transmission Authority (“KETA”) Project and the Kansas V-Plan Project prior to construction. On March 26, 2015, FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, subject to refund, as well as set the matter for hearing and settlement judge procedures. During the third quarter of 2015, ITC Great Plains and the settling parties reached an uncontested settlement agreement, which was certified by the presiding administrative law judge but remains subject to acceptance by FERC. As of September 30, 2015, we had a total of $12.9 million (net of accumulated amortization of $0.7 million) of regulatory assets for these expenses, including carrying charges. ITC Great Plains has included the unamortized balance of the regulatory assets in its rate base and commenced amortization over a 10-year period during the second quarter of 2015. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template, subject to acceptance by FERC. We do not expect the final resolution of this matter to have a material impact on our consolidated results of operations, cash flows or financial condition.
MISO Funding Policy for Generator Interconnections
On June 18, 2015, FERC issued an order initiating a proceeding, pursuant to Section 206 of the FPA, to examine MISO’s funding policy for generator interconnections, which allows a transmission owner to unilaterally elect to fund network upgrades and recover such costs from the interconnection customer. In this order, FERC suggested the MISO funding policy be revised to require mutual agreement between the interconnection customer and transmission owner to utilize the election to fund network upgrades. We do not expect the resolution of this proceeding to have a material impact on our consolidated results of operations, cash flows or financial condition.
MISO Formula Rate Template Modification Filing
On October 30, 2015, ITCTransmission, METC and ITC Midwest (collectively, the “joint applicants”) requested modifications, pursuant to Section 205 of the FPA, to certain aspects of the joint applicants’ respective formula rate templates which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. The joint applicants requested an effective date of January 1, 2016 for the proposed template changes. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that result in the joint applicants recovering excess amounts from customers. The recognition of this refund liability in the third quarter of 2015 resulted in a reduction in revenues of $8.6 million, which includes amounts recovered for all historical periods through September 30, 2015, and an increase in interest expense of $0.8 million for the three and nine months ended September 30, 2015. This resulted in an estimated after-tax reduction to net income of $5.5 million for the three and nine months ended September 30, 2015. We do not expect the formula rate modifications, if accepted by FERC, to have a material impact on our consolidated results of operations, cash flows or financial condition.


9

Order on Formula Rate Protocols
In 2012, the FERC issued an order initiating a proceeding, 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. Our MISO Regulated Operating Subsidiaries were named in the order. In May 2013, the FERC issued an order that determined the formula rate protocols are insufficient to ensure just and reasonable rates and directed MISO and its member transmission owners (“TOs”) to file revised formula rate protocols. In September 2013, MISO and its TOs, including our MISO Regulated Operating Subsidiaries, filed revised formula rate protocols which require our MISO Regulated Operating Subsidiaries to provide additional information for certain aspects of the formula rates used to calculate their respective annual revenue requirements. In March 2014, the FERC issued an order conditionally accepting MISO and its TOs’ September 2013 filing and required a further compliance filing, which MISO and its TOs made in May 2014. On January 22, 2015, the FERC conditionally accepted the May 2014 compliance filing, subject to a further compliance filing, which was made on February 13, 2015. On August 21, 2015, the FERC issued an order accepting the February 13, 2015 compliance filing, effective January 2014. We do not expect these revised formula rate protocols to impact our consolidated results of operations, cash flows or financial condition.
Rate of Return on Equity and Capital Structure Complaints
See “Rate of Return on Equity and Capital Structure Complaints” in Note 11 for a discussion of the complaints.
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 use approved return on equity (“ROE”) rates and 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. See “Rate of Return on Equity and Capital Structure Complaints” in Note 11 for detail on ROE matters including incentive adders approved by FERC in 2015.
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. Revenue is recognized for services provided during each reporting period based on actual revenue requirements calculated using the formula rate templates. Our Regulated Operating Subsidiaries accrue or defer revenues to the extent that the actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. The amount of accrued or deferred revenues is reflected in customer bills within two years under the provisions of the formula rate templates.
The net changes in regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals, including accrued interest, were as follows during the nine months ended September 30, 2015:
(in thousands)
 
Total
Balance as of December 31, 2014
 
$
(56,103
)
Net refund of 2013 revenue deferrals and accruals, including accrued interest
 
26,366

Net revenue deferral for the nine months ended September 30, 2015
 
(25,983
)
Net accrued interest payable for the nine months ended September 30, 2015
 
(1,547
)
Balance as of September 30, 2015
 
$
(57,267
)


10

Regulatory assets and liabilities associated with our Regulated Operating Subsidiaries’ formula rate revenue accruals and deferrals and associated accrued interest are recorded in the condensed consolidated statements of financial position at September 30, 2015 as follows:
(in thousands)
 
Total
Current assets
 
$
12,378

Non-current assets
 
8,850

Current liabilities
 
(37,415
)
Non-current liabilities
 
(41,080
)
Balance as of September 30, 2015
 
$
(57,267
)
4.    GOODWILL AND INTANGIBLE ASSETS
Goodwill
At September 30, 2015 and December 31, 2014, we had goodwill balances recorded at ITCTransmission, METC and ITC Midwest of $173.4 million, $453.8 million and $323.0 million, respectively, which resulted from the ITCTransmission acquisition, the METC acquisition and ITC Midwest’s asset acquisition, respectively.
Intangible Assets
We have recorded intangible assets as a result of the METC acquisition in 2006. The carrying value of these assets was $31.9 million and $34.2 million (net of accumulated amortization of $26.5 million and $24.2 million) as of September 30, 2015 and December 31, 2014, respectively.
We have also recorded intangible assets for payments and obligations made by ITC Great Plains to certain TOs to acquire rights which are required under the SPP tariff to designate ITC Great Plains to build, own and operate projects within the SPP region, including the KETA Project and the Kansas V-Plan Project. The carrying amount of these intangible assets was $14.4 million and $14.6 million (net of accumulated amortization of $0.9 million and $0.7 million) as of September 30, 2015 and December 31, 2014, respectively.
During the three months ended September 30, 2015 and 2014, we recognized $0.8 million and $0.9 million, respectively, of amortization expense of our intangible assets and $2.5 million for each of the nine month periods ended September 30, 2015 and 2014. For each of the next five years, we expect the annual amortization of our intangible assets that have been recorded as of September 30, 2015 to be $3.3 million per year.
5.    DEBT
Derivative Instruments and Hedging Activities
We may use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. The interest rate swaps listed below manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 5.875% Senior Notes, due September 30, 2016. As of September 30, 2015, ITC Holdings had $139.3 million outstanding under the 5.875% Senior Notes.
Interest Rate Swaps
 
Notional Amount
 
Fixed Rate
 
Original Term
 
Effective Date
(Amounts in millions)
 
 
 
 
 
 
 
 
August 2014 swap
 
$
25.0

 
3.217
%
 
10 years
 
September 2016
October 2014 swap
 
25.0

 
3.075
%
 
10 years
 
September 2016
January 2015 swap
 
25.0

 
2.301
%
 
10 years
 
September 2016
Total
 
$
75.0

 
 
 
 
 
 
The 10-year term interest rate swaps call for ITC Holdings to receive interest quarterly at a variable rate equal to LIBOR and to pay interest semi-annually at various fixed rates effective for the 10-year period beginning September 30, 2016 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 September 30, 2016. 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


11

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 September 30, 2015, there has been no material ineffectiveness recorded in the condensed consolidated statement of operations. The interest rate swaps qualify for hedge accounting treatment, whereby any gain or loss recognized from the trade date to the effective date for the effective portion of the hedge is recorded net of tax in accumulated other comprehensive income (“AOCI”). This amount will be accumulated and amortized as a component of interest expense over the life of the forecasted debt. As of September 30, 2015, the fair value of the derivative instruments was a liability of $4.1 million recorded to other 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
On April 7, 2015, ITC Midwest issued $225.0 million aggregate principal amount of 3.83% First Mortgage Bonds, Series G, due 2055. The proceeds from the issuance were used for general corporate purposes, including the repayment of borrowings under ITC Midwest’s revolving credit agreement. ITC Midwest’s First Mortgage Bonds are issued under its first mortgage and deed of trust and secured by a first mortgage lien on substantially all of its property.
ITC Holdings
On June 8, 2015, pursuant to the authorization by the Board of Directors, ITC Holdings established an ongoing commercial paper program for the issuance and sale of unsecured commercial paper in an aggregate amount not to exceed $400.0 million outstanding at any one time. As of September 30, 2015, ITC Holdings had approximately $219.0 million of commercial paper issued and outstanding under the program, with a weighted-average interest rate of 0.450% and weighted average remaining days to maturity of 5 days. The proceeds from the issuance were used for general corporate purposes, including the repayment of borrowings under ITC Holdings’ revolving credit agreement. The amount outstanding as of September 30, 2015 was classified as debt maturing within one year in the consolidated statements of financial position.
Revolving Credit Agreements
At September 30, 2015, ITC Holdings and its Regulated Operating Subsidiaries had the following unsecured 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)
ITC Holdings
$
400.0

 
$
21.8

 
$
378.2

(c)
1.4%
(d)
 
0.175
%
ITCTransmission
100.0

 
41.8

 
58.2

 
1.2%
(e)
 
0.10
%
METC
100.0

 
9.3

 
90.7

 
1.2%
(e)
 
0.10
%
ITC Midwest
250.0

 
38.5

 
211.5

 
1.2%
(e)
 
0.10
%
ITC Great Plains
150.0

 
57.6

 
92.4

 
1.2%
(e)
 
0.10
%
Total
$
1,000.0

 
$
169.0

 
$
831.0

 
 
 
 
 
____________________________
(a)
Included within long-term debt.
(b)
Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.
(c)
ITC Holdings’ revolving credit agreement may be used for general corporate purposes, including to repay commercial paper issued pursuant to the commercial paper program described above, if necessary. While outstanding commercial paper does not reduce available capacity under ITC Holdings’ revolving credit agreement, the unused capacity under this agreement adjusted for the commercial paper outstanding was $159.2 million as of September 30, 2015.
(d)
Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.25% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month LIBOR, plus an applicable margin of 0.25%, subject to adjustments based on ITC Holdings’ credit rating.


12

(e)
Loans bear interest at a rate equal to LIBOR plus an applicable margin of 1.00% or at a base rate, which is defined as the higher of the prime rate, 0.50% above the federal funds rate or 1.00% above the one month LIBOR, subject to adjustments based on the borrower’s credit rating.
Covenants
Our debt instruments contain numerous financial and operating covenants that place significant restrictions on certain transactions, such as incurring additional indebtedness, engaging in sale and lease-back transactions, creating liens or other encumbrances, entering into mergers, consolidations, liquidations or dissolutions, creating or acquiring subsidiaries, selling or otherwise disposing of all or substantially all of our assets and paying dividends. In addition, the covenants require us to meet certain financial ratios, such as maintaining certain debt to capitalization ratios and maintaining certain interest coverage ratios. As of September 30, 2015, we were not in violation of any debt covenant.
6.     STOCKHOLDERS’ EQUITY
The changes in stockholders’ equity for the nine months ended September 30, 2015 were as follows:
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
Other
 
Total
 
Common Stock
 
Retained
 
Comprehensive
 
Stockholders’
(in thousands, except share and per share data)
Shares
 
Amount
 
Earnings
 
Income (Loss)
 
Equity
BALANCE, DECEMBER 31, 2014
155,140,967

 
$
923,191

 
$
741,550

 
$
4,816

 
$
1,669,557

Net income
—

 
—

 
205,041

 
—

 
205,041

Repurchase and retirement of common stock
(667,487
)
 
(21,931
)
 
—

 
—

 
(21,931
)
Dividends declared ($0.5125 per share)
—

 
—

 
(79,691
)
 
—

 
(79,691
)
Stock option exercises
1,165,435

 
10,599

 
—

 
—

 
10,599

Shares issued under the Employee Stock Purchase Plan
55,905

 
1,723

 
—

 
—

 
1,723

Issuance of restricted stock
254,711

 
—

 
—

 
—

 
—

Forfeiture of restricted stock
(53,197
)
 
—

 
—

 
—

 
—

Issuance of performance shares
287,464

 
—

 
—

 
—

 
—

Forfeiture of performance shares
(6,713
)
 
—

 
—

 
—

 
—

Share-based compensation, net of forfeitures
—

 
12,461

 
—

 
—

 
12,461

Forward contracts of accelerated share repurchase program
—

 
(115,000
)
 
—

 
—

 
(115,000
)
Other comprehensive loss, net of tax
—

 
—

 
—

 
(889
)
 
(889
)
Other
—

 
(6
)
 
—

 
—

 
(6
)
BALANCE, SEPTEMBER 30, 2015
156,177,085

 
$
811,037

 
$
866,900

 
$
3,927

 
$
1,681,864

The changes in stockholders’ equity for the nine months ended September 30, 2014 were as follows:
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
Other
 
Total
 
Common Stock
 
Retained
 
Comprehensive
 
Stockholders’
(in thousands, except share and per share data)
Shares
 
Amount
 
Earnings
 
Income (Loss)
 
Equity
BALANCE, DECEMBER 31, 2013
157,500,795

 
$
1,014,435

 
$
592,970

 
$
6,327

 
$
1,613,732

Net income
—

 
—

 
197,345

 
—

 
197,345

Repurchase and retirement of common stock
(3,018,225
)
 
(108,136
)
 
—

 
—

 
(108,136
)
Dividends declared on common stock ($0.4475 per share)
—

 
—

 
(70,279
)
 
—

 
(70,279
)
Stock option exercises
977,491

 
18,095

 
—

 
—

 
18,095

Shares issued under the Employee Stock Purchase Plan
53,056

 
1,571

 
—

 
—

 
1,571

Issuance of restricted stock
305,718

 
—

 
—

 
—

 
—

Forfeiture of restricted stock
(87,536
)
 
—

 
—

 
—

 
—

Share-based compensation, net of forfeitures
—

 
11,009

 
—

 
—

 
11,009

Forward contract of accelerated share repurchase program
—

 
(46,000
)
 
—

 
—

 
(46,000
)
Other comprehensive loss, net of tax
—

 
—

 
—

 
(389
)
 
(389
)
BALANCE, SEPTEMBER 30, 2014
155,731,299

 
$
890,974

 
$
720,036

 
$
5,938

 
$
1,616,948



13

Accumulated Other Comprehensive Income
The following table provides the components of changes in AOCI for the three and nine months ended September 30, 2015 and 2014:
 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands)
2015
 
2014
 
2015
 
2014
Balance at the beginning of period
$
6,078

 
$
5,855

 
$
4,816

 
$
6,327

Derivative instruments
 
 
 
 
 
 
 
Reclassification of net loss relating to interest rate cash flow hedges from AOCI to interest expense — net (net of tax of $100 and $88 for the three months ended September 30, 2015 and 2014, respectively, and net of tax of $261 and $243 for the nine months ended September 30, 2015 and 2014, respectively)
111

 
122

 
372

 
340

Reclassification of loss relating to interest rate cash flow hedges from AOCI to loss on extinguishment of debt (net of tax of $83 for the nine months ended September 30, 2014)
—

 
—

 
—

 
117

(Loss) gain on interest rate swaps relating to interest rate cash flow hedges (net of tax of $1,639 and $34 for the three months ended September 30, 2015 and 2014, respectively, and net of tax of $920 and $621 for the nine months ended September 30, 2015 and 2014, respectively)
(2,280
)
 
47

 
(1,282
)
 
(870
)
Derivative instruments, net of tax
(2,169
)
 
169

 
(910
)
 
(413
)
Available-for-sale securities
 
 
 
 
 
 
 
Unrealized net gain (loss) on available-for-sale securities (net of tax of $13 and $63 for the three months ended September 30, 2015 and 2014, respectively, and net of tax of $15 and $16 for the nine months ended September 30, 2015 and 2014, respectively)
18

 
(86
)
 
21

 
24

Available-for-sale securities, net of tax
18

 
(86
)
 
21

 
24

Total other comprehensive (loss) income, net of tax
(2,151
)
 
83

 
(889
)
 
(389
)
Balance at the end of period
$
3,927

 
$
5,938

 
$
3,927

 
$
5,938

Share Repurchase Program
In April 2014, the Board of Directors authorized and ITC Holdings announced a share repurchase program for up to $250.0 million, which expires in December 2015. Pursuant to such authorization, ITC Holdings completed an accelerated share repurchase from June 2014 to December 2014 in which 3.6 million shares were repurchased and retired for a total of $130.0 million.
On September 30, 2015, ITC Holdings entered into an accelerated share repurchase program for $115.0 million with Barclays Bank PLC (“Barclays”) (the “ASR program”), which is part of the share repurchase program described above. Under the ASR program, ITC Holdings paid $115.0 million to Barclays on September 30, 2015 and received an initial delivery of 2.8 million shares on October 1, 2015. The fair market value of the initial delivery of shares was $92.0 million, based on the closing market price of $33.34 per share at the commencement of the ASR program. The final number of shares delivered under the ASR program will be based on the volume-weighted average share price of our common stock during the term of the transaction, less an agreed upon discount and adjusted for the initial share delivery. The ASR program is expected to be completed by the end of 2015. As of September 30, 2015, the $92.0 million pertaining to the initial delivery of shares and the remaining $23.0 million under the ASR program meet the criteria to be accounted for as a physically settled forward contract and a forward contract indexed to our stock, respectively, and qualify as equity instruments. Therefore, ITC Holdings recorded the entire $115.0 million payment as a reduction to common stock as of September 30, 2015.


14

7.    SHARE-BASED COMPENSATION
Long-Term Incentive Plan Grants
On May 19, 2015, pursuant to the Second Amended and Restated 2006 Long-Term Incentive Plan (“LTIP”), we granted 473,200 options to purchase shares of our common stock with an exercise price of $35.91 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 19, 2016. In addition, on May 19, 2015, pursuant to the LTIP, we granted 189,299 shares of restricted stock and 287,464 performance shares. One-half of the payout of the performance shares will be based on an external measure for total shareholder return (“TSR”) relative to a predetermined peer group and the remainder will be based on adjusted diluted earnings per share (“EPS”) growth. Payout of the performance shares will range from 0% to 200% of the target number of shares granted, plus additional dividend equivalent shares as described below. The fair value for performance shares with the relative TSR condition was determined using a Monte Carlo simulation valuation model, whereas the fair value for performance shares with the EPS growth condition was based on the closing price of our common stock on the grant date.
Holders of outstanding restricted stock and performance shares have all the rights of a holder of common stock of ITC Holdings, including dividend and voting rights. However, performance shares earn and accumulate dividend equivalents, which are settled in the form of additional shares upon vesting of the related award. Dividend equivalents paid on performance shares that do not vest will be forfeited. Restricted stock holders receive cash dividends at each dividend payment date. The restricted stock and performance shares generally vest three years after the grant date. Holders of restricted stock and performance shares may not sell, transfer or pledge their respective shares until vesting occurs.
Stock Option Exercises
We issued 1,165,435 and 1,011,750 shares of our common stock during the nine months ended September 30, 2015 and the year ended December 31, 2014, respectively, due to the exercise of stock options.


15

8.    EARNINGS PER SHARE
We report both basic and diluted EPS. Our restricted stock contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing EPS. A reconciliation of both calculations for the three and nine months ended September 30, 2015 and 2014 is presented in the following table:
 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands, except share, per share data and percentages)
2015
 
2014
 
2015
 
2014
Numerator:
 
 
 
 
 
 
 
Net income
$
65,573

 
$
73,873

 
$
205,041

 
$
197,345

Less: dividends declared and paid — common and restricted shares
(29,230
)
 
(25,296
)
 
(79,697
)
 
(70,279
)
Undistributed earnings
36,343

 
48,577

 
125,344

 
127,066

Percentage allocated to common shares (a)
99.3
%
 
99.2
%
 
99.3
%
 
99.2
%
Undistributed earnings — common shares
36,089

 
48,188

 
124,467

 
126,049

Add: dividends declared and paid — common shares
29,036

 
25,100

 
79,136

 
69,708

Numerator for basic and diluted earnings per common share
$
65,125

 
$
73,288

 
$
203,603

 
$
195,757

Denominator:
 
 
 
 
 
 
 
Basic earnings per common share — weighted average common shares outstanding
154,836,673

 
154,386,994

 
154,348,478

 
155,661,516

Incremental shares for stock options and employee stock purchase plan — weighted average assumed conversion
687,035

 
1,364,896

 
1,104,516

 
1,470,041

Diluted earnings per common share — adjusted weighted average shares and assumed conversion
155,523,708

 
155,751,890

 
155,452,994

 
157,131,557

Per common share net income:
 
 
 
 
 
 
 
Basic
$
0.42

 
$
0.47

 
$
1.32

 
$
1.26

Diluted
$
0.42

 
$
0.47

 
$
1.31

 
$
1.25

 
 
 
 
 
 
 
 
____________________________
(a)
Weighted average common shares outstanding
154,836,673

 
154,386,994

 
154,348,478

 
155,661,516

 
Weighted average restricted shares
(participating securities)
1,040,212

 
1,230,250

 
1,127,490

 
1,295,812

 
 Total
155,876,885

 
155,617,244

 
155,475,968

 
156,957,328

 
 Percentage allocated to common shares
99.3
%
 
99.2
%
 
99.3
%
 
99.2
%
The incremental shares for stock options and employee stock purchase plan (“ESPP”) shares are included in the diluted EPS calculation using the treasury stock method, unless the effect of including them would be anti-dilutive. The outstanding stock options and ESPP shares and the anti-dilutive stock options and ESPP shares excluded from the diluted EPS calculations were as follows:
 
2015
 
2014
Outstanding stock options and ESPP shares (as of September 30)
3,857,429

 
4,637,551

Anti-dilutive stock options and ESPP shares (for the three and nine months ended September 30)
1,059,106

 
642,507

In addition, the performance shares discussed in Note 7 are not included in the diluted EPS calculation for the three and nine months ended September 30, 2015 because the performance metric had not been met or was not substantively measurable as of September 30, 2015.
Impacts of the Accelerated Share Repurchase Program
The forward contracts under the ASR program of $115.0 million are excluded from the diluted earnings per share calculation for the three and nine months ended September 30, 2015 due to the anti-dilutive impact on earnings per share. The initial


16

delivery of 2.8 million shares received on October 1, 2015 and the final settlement amount expected by the end of 2015 will reduce the basic shares outstanding as of December 31, 2015. See further discussion on the ASR program in Note 6 to the condensed consolidated financial statements.
9.    RETIREMENT BENEFITS AND ASSETS HELD IN TRUST
Pension Plan Benefits
We have a qualified defined benefit pension plan (“retirement plan”) for eligible employees, comprised of a traditional final average pay plan and a cash balance plan. The traditional final average pay plan is noncontributory, covers select employees, and provides retirement benefits based on years of benefit service, average final compensation and age at retirement. The cash balance plan is also noncontributory, covers substantially all employees, and provides retirement benefits based on eligible compensation and interest credits. Our funding practice for the retirement plan is to contribute amounts necessary to meet the minimum funding requirements of the Employee Retirement Income Security Act of 1974, plus additional amounts as we determine appropriate. During the nine months ended September 30, 2015, we contributed $4.1 million to the retirement plan. We do not expect to make any additional contributions to this plan in 2015.
We also have two supplemental nonqualified, noncontributory, defined benefit pension plans for selected management employees (the “supplemental benefit plans” and collectively with the retirement plan, the “pension plans”). The supplemental benefit plans provide for benefits that supplement those provided by the retirement plan. We contributed $9.4 million to the supplemental benefit plans during the nine months ended September 30, 2015. We do not expect to make any additional contributions to these plans in 2015.
Net periodic benefit cost for the pension plans, by component, was as follows for the three and nine months ended September 30, 2015 and 2014:
 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands)
2015
 
2014
 
2015
 
2014
Service cost
$
1,624

 
$
1,267

 
$
4,872

 
$
3,800

Interest cost
924

 
901

 
2,772

 
2,703

Expected return on plan assets
(960
)
 
(885
)
 
(2,879
)
 
(2,655
)
Amortization of prior service credit
(10
)
 
(11
)
 
(31
)
 
(32
)
Amortization of unrecognized loss
1,061

 
386

 
3,182

 
1,158

Net pension cost
$
2,639

 
$
1,658

 
$
7,916

 
$
4,974

Other Postretirement Benefits
We provide certain postretirement health care, dental, and life insurance benefits for eligible employees. During the nine months ended September 30, 2015, we contributed $6.9 million to the postretirement benefit plan. We expect to make estimated additional contributions of $2.2 million to the postretirement benefit plan in 2015.
Net postretirement benefit plan cost, by component, was as follows for the three and nine months ended September 30, 2015 and 2014:
 
Three months ended
 
Nine months ended
 
September 30,
 
September 30,
(in thousands)
2015
 
2014
 
2015
 
2014
Service cost
$
2,121

 
$
1,462

 
$
6,364

 
$
4,385

Interest cost
620

 
498

 
1,858

 
1,494

Expected return on plan assets
(463
)
 
(341
)
 
(1,389
)
 
(1,022
)
Amortization of unrecognized loss
125

 
—

 
375

 
—

Net postretirement cost
$
2,403

 
$
1,619

 
$
7,208

 
$
4,857

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 $0.8 million and $0.9 million for the three months ended September 30, 2015 and 2014, respectively, and $3.2 million and $3.0 million for the nine months ended September 30, 2015 and 2014, respectively.


17

10.    FAIR VALUE MEASUREMENTS
The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the nine months ended September 30, 2015 and the year ended December 31, 2014, there were no transfers between levels.
Our assets and liabilities measured at fair value subject to the three-tier hierarchy at September 30, 2015, were as follows:
 
Fair Value Measurements at Reporting Date Using
 
Quoted Prices in
Active Markets for
Identical Assets
 
Significant
Other Observable
Inputs
 
Significant
Unobservable
Inputs
(in thousands)
(Level 1)
 
(Level 2)
 
(Level 3)
Financial assets measured on a recurring basis:
 
 
 
 
 
Cash and cash equivalents — cash equivalents
$
49

 
$
—

 
$
—

Mutual funds — fixed income securities
35,928

 
—

 
—

Mutual funds — equity securities
877

 
—

 
—

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

 
(4,136
)
 
—

Total
$
36,854

 
$
(4,136
)
 
$
—

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at December 31, 2014, 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
$
5,452

 
$
—

 
$
—

Mutual funds — fixed income securities
26,715

 
—

 
—

Mutual funds — equity securities
667

 
—

 
—

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

 
(1,934
)
 
—

Total
$
32,834

 
$
(1,934
)
 
$
—

As of September 30, 2015 and December 31, 2014, 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. Our cash and cash equivalents consist of money market mutual funds 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 and are recorded at fair value based on observable trades for identical securities in an active market. Changes in the observed trading prices and liquidity of money market funds are monitored as additional support for determining fair value, and losses are recorded in earnings for investments classified as trading securities and other comprehensive income for investments classified as available for sale if fair value falls below recorded cost.
The liability related to derivatives consist of interest rate swaps as discussed in Note 5. The fair value of our interest rate swap derivatives as of September 30, 2015 is determined based on a discounted cash flow (“DCF”) method using LIBOR swap rates which are observable at commonly quoted intervals.
We also held non-financial assets that are required to be measured at fair value on a non-recurring basis. These consist of goodwill and intangible assets. We did not record any impairment charges on long-lived assets and no other significant events occurred requiring non-financial assets and liabilities to be measured at fair value (subsequent to initial recognition) during the nine months ended September 30, 2015. 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, 2014 included in our Form 10-K for such period and to Note 4 of this Form 10-Q.


18

Fair Value of Financial Assets and Liabilities
Fixed Rate Debt
Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $4,073.8 million and $3,985.6 million at September 30, 2015 and December 31, 2014, respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $3,855.2 million and $3,629.8 million at September 30, 2015 and December 31, 2014, respectively.
Revolving and Term Loan Credit Agreements
At September 30, 2015 and December 31, 2014, we had a consolidated total of $330.0 million and $473.8 million, respectively, outstanding under our revolving and term loan credit agreements, which are variable rate loans. The fair value of these loans approximates book value based on the borrowing rates currently available for variable rate loans obtained from third party lending institutions. These fair values represent Level 2 under the three-tier hierarchy described above.
Other Financial Instruments
The carrying value of other financial instruments included in current assets and current liabilities, including cash and cash equivalents, special deposits and commercial paper, approximates their fair value due to the short-term nature of these instruments.
11.    COMMITMENTS AND CONTINGENT LIABILITIES
Environmental Matters
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 some environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our 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 polychlorinated biphenyls, or 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, others’ property may be affected. For example, aboveground and underground transmission lines sometimes traverse properties that our Regulated Operating Subsidiaries do not own, and, at some of our Regulated Operating Subsidiaries’ transmission stations, transmission assets (owned or operated by our Regulated Operating Subsidiaries) and distribution assets (owned or operated by our Regulated Operating Subsidiaries’ transmission customer) are commingled.


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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.
Michigan Sales and Use Tax Audit
The Michigan Department of Treasury has conducted sales and use tax audits of ITCTransmission for the audit periods April 1, 2005 through June 30, 2008 and October 1, 2009 through September 30, 2013. The Michigan Department of Treasury has denied ITCTransmission’s claims of the industrial processing exemption from use tax that it has taken beginning January 1, 2007. The exemption claim denials resulted in use tax assessments against ITCTransmission. ITCTransmission filed administrative appeals to contest these use tax assessments.
In a separate, but related case involving a Michigan-based public utility that made similar industrial processing exemption claims, the Michigan Supreme Court ruled in July 2015 that the electric system, which involves altering voltage, constitutes an exempt, industrial processing activity. However, the ruling further held the electric system is also used for other functions that would not be exempt, and remanded the case to the Michigan Court of Claims to determine how the exemption applies to assets that are used in electric distribution activities. ITCTransmission is assessing the recent ruling in light of its specific facts, but cannot estimate the amount or timing of any potential tax assessments or refunds. ITCTransmission believes that the industrial processing exemption will apply to a significant portion and potentially all of the equipment purchases for which it claimed exemption, but it is reasonably possible that portions of the use tax assessments could be sustained upon resolution of this matter.
The amount of use tax liability associated with the exemptions taken by ITCTransmission through September 30, 2015 is estimated to be approximately $17.1 million including interest. This amount includes approximately $10.3 million, including interest, assessed for the audit periods noted above. ITCTransmission has not recorded this contingent liability as of September 30, 2015. METC has also taken the industrial processing exemption, estimated to be approximately $10.1 million for periods still subject to audit and METC has also not recorded any contingent liabilities as of September 30, 2015 associated with this matter. In the event it becomes appropriate to record additional use tax liability relating to this matter, ITCTransmission and METC would record the additional use tax primarily as an increase to the cost of property, plant and equipment, which is a component of revenue requirement, as the majority of purchases for which the exemption was taken relate to equipment purchases associated with capital projects.
Rate of Return on Equity and Capital Structure Complaints
On November 12, 2013, the Association of Businesses Advocating Tariff Equity, Coalition of MISO Transmission Customers, Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Inc., Minnesota Large Industrial Group, and Wisconsin Industrial Energy Group (collectively, the “complainants”) filed a complaint with the FERC under Section 206 of the FPA (the “Complaint”), requesting that the FERC find the current 12.38% MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including ITCTransmission, METC and ITC Midwest, to no longer be just and reasonable. The complainants sought a FERC order reducing the base ROE used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 9.15%. The Complaint also alleged that the rates of any MISO TO using a capital structure with greater


20

than 50% for the equity component are likewise not just and reasonable (our MISO Regulated Operating Subsidiaries use their actual capital structures, which target 60% equity, as FERC had previously authorized). The Complaint also alleged the ROE adders currently approved for certain ITC Holdings operating companies, including an adder currently charged by ITCTransmission for being a member of an RTO and adders charged by ITCTransmission and METC for being independent transmission owners, are no longer just and reasonable, and sought to have them eliminated.
On June 19, 2014, in a separate Section 206 complaint against the regional base ROE rate for ISO New England TOs, FERC adopted a new methodology for establishing base ROE rates for electric transmission utilities. The new methodology is based on a two-step discounted cash flow analysis (“two-step DCF”) that uses both short-term and long-term growth projections in calculating ROE rates for a proxy group of electric utilities. The previous methodology used only short-term growth projections. FERC also reiterated that it can apply discretion in determining how ROE rates are established within a zone of reasonableness and reiterated its policy for limiting the overall ROE rate for any company, including the base and all applicable adders, at the high end of the zone of reasonableness set by the two-step DCF methodology. The new method presented in the ISO New England ROE case will be used in resolving the MISO ROE case.
On October 16, 2014, FERC granted the complainants’ request in part by setting the base ROE for hearing and settlement procedures, while denying all other aspects of the Complaint. FERC found that the complainants failed to show that the use of actual or FERC-approved capital structures that include more than 50% equity are unjust and unreasonable. FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives. The order reiterated that any TO’s total ROE rate is limited by the top end of a zone of reasonableness and the TO’s ability to implement the full amount of previously granted ROE adders may be affected by the outcome of the hearing. FERC set the refund effective date as November 12, 2013.
During the fourth quarter of 2014, the MISO TOs engaged in the ordered FERC settlement procedures with the complainants but were not able to reach resolution. On January 5, 2015, the Chief Judge issued an order which terminated settlement procedures and set the matter for hearing, with an initial decision within 47 weeks of the order. On April 6, 2015, the MISO TOs filed expert witness testimony in the Complaint proceeding supporting the existing base ROE as just and reasonable. However, in the event that FERC elects to change the base ROE, the testimony included a recommendation of 11.39% base ROE for the period of November 12, 2013 through February 12, 2015 (the “Initial Refund Period”). In resolving the Complaint, we expect FERC to establish a new base ROE to determine any potential refund liability for the Initial Refund Period. The new base ROE as well as any ROE adders, subject to the limitations of the top end of any zone of reasonableness that is established, are expected to be used to calculate the refund liability for the Initial Refund Period.
On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the “Second Complaint”) by Arkansas Electric Cooperative Corporation, Mississippi Delta Energy Agency, Clarksdale Public Utilities Commission, Public Service Commission of Yazoo City and Hoosier Energy Rural Electric Cooperative, Inc., seeking a FERC order to reduce the base ROE used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 8.67% with an effective date of February 12, 2015. On March 11, 2015, the MISO TOs filed an answer to the Second Complaint with the FERC supporting the current base ROE as just and reasonable. On June 18, 2015, FERC accepted the Second Complaint and set it for hearing and settlement procedures. FERC also set the refund effective date for the Second Complaint as February 12, 2015.
On October 20, 2015, the MISO TOs filed expert witness testimony in the Second Complaint proceeding supporting the existing base ROE as just and reasonable. However, in the event that FERC elects to change the base ROE, the testimony included a recommendation of 10.75% base ROE for the period of February 12, 2015 through May 11, 2016 (the “Second Refund Period”). The data ultimately used to establish any new base ROE will be filed by the parties to the Second Complaint in January 2016 for the period ending December 31, 2015. In resolving the Second Complaint, we expect FERC to establish a new base ROE to determine any potential refund liability for the Second Refund Period. The base ROE established by FERC for the Second Complaint as well as any ROE adders, subject to the limitations of the top end of any zone of reasonableness established, are expected to be used to calculate the refund liability for the Second Refund Period.
We believe it is probable that refunds will be required for these matters and as of September 30, 2015, the estimated range of refunds on a pre-tax basis is expected to be from $88.0 million to $158.9 million for the period from November 12, 2013 through September 30, 2015. As of September 30, 2015 and December 31, 2014, our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $88.0 million and $47.8 million, respectively, representing the low end of the range of potential refunds as of those dates, as there is no best estimate within the range of refunds. The recognition of this estimated liability resulted in a reduction in revenues of $18.0 million, $38.8 million and $46.9 million and an increase in interest expense of $0.5 million, $1.4 million and $0.9 million for the three and nine months ended September 30, 2015 and the year ended December 31, 2014, respectively. This resulted in an estimated after-tax reduction to net income of $11.2


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million, $24.5 million and $28.9 million for the three and nine months ended September 30, 2015 and the year ended December 31, 2014, respectively. No amounts related to these complaints were recorded as of or for the three and nine months ended September 30, 2014.
Based on the estimated range of refunds identified above, we believe that it is reasonably possible that these matters could result in an additional estimated pre-tax refund of up to $70.9 million (or a $43.0 million estimated after-tax reduction of net income) in excess of the amount recorded as of September 30, 2015. It is also possible the outcome of these matters could differ from the estimated range of losses and materially affect our results of operations due to the uncertainty of the calculation of an authorized base ROE along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC. As of September 30, 2015, our MISO Regulated Operating Subsidiaries had a total of approximately $2.8 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point reduction in the authorized ROE would reduce annual consolidated net income by approximately $2.8 million.
In a separate but related matter, in November 2014, METC, ITC Midwest and other MISO TOs filed a request with FERC under FPA Section 205 for authority to include a 50 basis point incentive adder for RTO participation in each of the TOs’ formula rates. On January 5, 2015, FERC approved the use of this incentive adder, effective January 6, 2015. Additionally, ITC Midwest filed a request with FERC under FPA Section 205 in January 2015 for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently authorized for ITCTransmission and METC. On March 31, 2015, FERC approved the use of a 50 basis point incentive adder for independence, effective April 1, 2015. On April 30, 2015, ITC Midwest filed a request with FERC for clarification and rehearing on the approved incentive adder for independence. The RTO participation incentive adder will be applied to METC’s and ITC Midwest’s base ROEs and the independence incentive adder will be applied to ITC Midwest’s base ROE in establishing their total authorized ROE rates, subject to the limitations of the top end of any zone of reasonableness that is established. Collection of these recently approved incentive adders is being deferred pending the outcome of the complaints relating to the base ROE.
12.    SEGMENT INFORMATION
We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise, including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses. The following tables show our financial information by reportable segment:
 
Three months ended
 
Nine months ended
OPERATING REVENUES:
September 30,
 
September 30,
(in thousands)
2015
 
2014
 
2015
 
2014
Regulated Operating Subsidiaries
$
273,012

 
$
270,062

 
$
820,452

 
$
792,058

ITC Holdings and other
334

 
254

 
720

 
438

Intercompany eliminations
(157
)
 
(182
)
 
(438
)
 
(545
)
Total Operating Revenues
$
273,189

 
$
270,134

 
$
820,734

 
$
791,951

 
Three months ended
 
Nine months ended
INCOME BEFORE INCOME TAXES:
September 30,
 
September 30,
(in thousands)
2015
 
2014
 
2015
 
2014
Regulated Operating Subsidiaries
$
138,532

 
$
151,758

 
$
436,990

 
$
440,537

ITC Holdings and other
(34,853
)
 
(33,250
)
 
(110,287
)
 
(122,514
)
Total Income Before Income Taxes
$
103,679

 
$
118,508

 
$
326,703

 
$
318,023

 
Three months ended
 
Nine months ended
NET INCOME:
September 30,
 
September 30,
(in thousands)
2015
 
2014
 
2015
 
2014
Regulated Operating Subsidiaries
$
85,971

 
$
93,015

 
$
269,491

 
$
269,865

ITC Holdings and other
65,573

 
73,873

 
205,041

 
197,345

Intercompany eliminations
(85,971
)
 
(93,015
)
 
(269,491
)
 
(269,865
)
Total Net Income
$
65,573

 
$
73,873

 
$
205,041

 
$
197,345



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TOTAL ASSETS:
September 30,
 
December 31,
(in thousands)
2015
 
2014
Regulated Operating Subsidiaries
$
7,282,357

 
$
6,867,411

ITC Holdings and other
4,128,485

 
3,944,318

Reconciliations / Intercompany eliminations (a)
(4,005,243
)
 
(3,837,640
)
Total Assets
$
7,405,599

 
$
6,974,089

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


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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Our reports, filings and other public announcements contain certain statements that describe our management’s beliefs concerning future business conditions, plans and prospects, growth opportunities and the outlook for our business and the electric transmission industry based upon information currently available. Such statements are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995. Wherever possible, we have identified these forward-looking statements by words such as “will,” “may,” “anticipates,” “believes,” “intends,” “estimates,” “expects,” “projects,” “likely” 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, 2014, and the following:
•
Certain elements of our Regulated Operating Subsidiaries’ formula rates can be and have been challenged, which could result in lowered rates and/or refunds of amounts previously collected and thus have an adverse effect on our business, financial condition, results of operations and cash flows.
•
Our actual capital investment may be lower than planned, which would cause a lower than expected rate base and therefore our revenues and earnings compared to our current expectations. In addition, we expect to invest in strategic development opportunities to improve the efficiency and reliability of the transmission grid, but we cannot assure you that we will be able to initiate or complete any of these investments. In addition, we expect to incur expenses related to the pursuit of development opportunities which may be higher than forecasted.
•
The regulations to which we are subject may limit our ability to raise capital and/or pursue acquisitions, development opportunities or other transactions or may subject us to liabilities.
•
Changes in energy laws, regulations or policies could impact our business, financial condition, results of operations and cash flows.
•
If amounts billed for transmission service for our Regulated Operating Subsidiaries’ transmission systems are lower than expected, or our actual revenue requirements are higher than expected, the timing of collection of our revenues would be delayed.
•
Each of our MISO Regulated Operating Subsidiaries depends on its primary customer for a substantial portion of its revenues, and any material failure by those primary customers to make payments for transmission services could have a material adverse effect on our business, financial condition, results of operations and cash flows.
•
A significant amount of the land on which our assets are located is subject to easements, mineral rights and other similar encumbrances. As a result, we must comply with the provisions of various easements, mineral rights and other similar encumbrances, which may adversely impact their ability to complete construction projects in a timely manner.
•
We contract with third parties to provide services for certain aspects of our business. If any of these agreements are terminated, we may face a shortage of labor or replacement contractors to provide the services formerly provided by these third parties.
•
Hazards associated with high-voltage electricity transmission may result in suspension of our operations or the imposition of civil or criminal penalties.
•
We are subject to environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.
•
We are subject to various regulatory requirements, including reliability standards; contract filing requirements; reporting, recordkeeping and accounting requirements; and transaction approval requirements. Violations of these requirements, whether intentional or unintentional, may result in penalties that, under some circumstances, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
•
Acts of war, terrorist attacks, cyber attacks, natural disasters, severe weather and other catastrophic events may have a material adverse effect on our business, financial condition, results of operations and cash flows.


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•
ITC Holdings is a holding company with no operations, and unless we receive dividends or other payments from our subsidiaries, we may be unable to pay dividends and fulfill our other cash obligations.
•
We have a considerable amount of debt and our reliance on debt financing may limit our ability to fulfill our debt obligations and/or to obtain additional financing.
•
Certain provisions in our debt instruments limit our financial and operating flexibility.
•
Adverse changes in our credit ratings may negatively affect us.
•
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.
Because our forward-looking statements are based on estimates and assumptions that are subject to significant business, economic and competitive uncertainties, many of which are beyond our control or are subject to change, actual results could be materially different and any or all of our forward-looking statements may turn out to be wrong. Forward-looking statements speak only as of the date made and can be affected by assumptions we might make or by known or unknown risks and uncertainties. Many factors mentioned in our discussion in this report will be important in determining future results. Consequently, we cannot assure you that our expectations or forecasts expressed in such forward-looking statements will be achieved. Except as required by law, we undertake no obligation to publicly update any of our forward-looking or other statements, whether as a result of new information, future events, or otherwise.
OVERVIEW
Through our Regulated Operating Subsidiaries, we operate high-voltage systems in Michigan’s Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to our systems. Our business strategy is to operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, to reduce transmission constraints and to upgrade the transmission networks to support new generating resources interconnecting to our transmission systems. We also are pursuing development projects not within our existing systems, which are likewise intended to improve overall grid reliability, reduce transmission constraints and facilitate interconnections of new generating resources, as well as enhance competitive wholesale electricity markets.
As electric transmission utilities with rates regulated by the FERC, our Regulated Operating Subsidiaries earn revenues through tariff rates charged for the use of their electric transmission systems by our customers, which include investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, our Regulated Operating Subsidiaries are subject to rate regulation only by the FERC. The rates charged by our Regulated Operating Subsidiaries are established using cost-based formula rate templates as discussed in Note 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 DTE Electric, 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 nine months ended September 30, 2015 or that may affect future results include:
•
Our capital investment of $497.3 million at our Regulated Operating Subsidiaries during the nine months ended September 30, 2015, resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;


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•
Debt issuance as described in Note 5 to the condensed consolidated financial statements and borrowings under our revolving and term loan credit agreements in 2015 and 2014 to fund capital investment at our Regulated Operating Subsidiaries and for general corporate purposes, resulting in higher interest expense;
•
Establishment of a commercial paper program as described in Note 5 to the condensed consolidated financial statements, which provides an additional source of liquidity for our working capital needs;
•
Debt maturing within one year of $694.3 million as of September 30, 2015 and the potentially higher interest rates associated with the additional financing required to repay this debt;
•
Recognition of an estimated contingent liability for the potential refunds relating to the rate of return on equity (“ROE”) and capital structure complaints as described in Note 11 to the condensed consolidated financial statements, which resulted in a total estimated pre-tax reduction of revenue and interest of $18.5 million and $40.2 million and an estimated after-tax reduction to net income of $11.2 million and $24.5 million for the three and nine months ended September 30, 2015, respectively;
•
Recognition of refund liability related to the formula rate template modification filing described in Note 3 to the condensed consolidated financial statements, which resulted in a total estimated pre-tax reduction of revenues and interest of $9.4 million and an estimated after-tax reduction to net income of $5.5 million for the three and nine months ended September 30, 2015; and
•
The accelerated share repurchase program (“ASR program”) executed in September 2015 for $115.0 million which is part of the share repurchase program of up to $250.0 million authorized by the Board of Directors in April 2014 and expiring in December 2015 as described in Note 6 to the condensed consolidated financial statements.
These items are discussed in more detail throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Capital Project Updates and Other Recent Developments
ITC Great Plains Regulatory Assets
ITC Great Plains made a filing with the FERC under Section 205 of the FPA in May 2013 to recover start-up, development and pre-construction expenses, including associated debt and equity carrying charges, in future rates as discussed in Note 3 of the condensed consolidated financial statements. These expenses included certain costs incurred by ITC Great Plains for the Kansas Electric Transmission Authority Project and the Kansas V-Plan Project prior to construction. On March 26, 2015, FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, subject to refund, as well as set the matter for hearing and settlement judge procedures. During the third quarter of 2015, ITC Great Plains and the settling parties reached an uncontested settlement agreement, which was certified by the presiding administrative law judge but remains subject to acceptance by FERC. As of September 30, 2015, we had a total of $12.9 million (net of accumulated amortization of $0.7 million) of regulatory assets for these expenses, including carrying charges. ITC Great Plains has included the unamortized balance of the regulatory assets in its rate base and commenced amortization over a 10-year period during the second quarter of 2015. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template, subject to acceptance by FERC. We do not expect the final resolution of this matter to have a material impact on our consolidated results of operations, cash flows or financial condition.
Development Bonuses
We recognized general and administrative expenses of $0.3 million and $10.1 million during the three and nine months ended September 30, 2015, respectively, and $0.3 million and $2.5 million during the three and nine months ended September 30, 2014, respectively, for bonuses for certain development projects, including the successful completion of certain milestones relating to projects at ITC Great Plains. Specifically, the Kansas V-Plan Project was placed in-service in December 2014 and the resulting development bonus was approved and paid during the three months ended March 31, 2015. It is reasonably possible that future development-related bonuses may be authorized and awarded for these or other development projects.


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Multi-Value Projects
2011 MISO Multi-Value Projects
In December 2011, MISO approved a portfolio of Multi-Value Projects (“MVPs”) which includes portions of four MVPs that we will construct, own and operate. The four MVPs are located in south central Minnesota, northern and southeast Iowa, southwest Wisconsin, and northeast Missouri and are in various stages of construction and included in ITC Midwest’s capital investment amounts. We currently estimate ITC Midwest will invest approximately $800 million in the four MVPs from 2014 through 2018.
Thumb Loop Project
The Thumb Loop Project, an additional MVP, is located in ITCTransmission’s region and consists of a 140-mile, double-circuit 345 kV transmission line and related substations that will serve as the backbone of the transmission system needed to accommodate future wind development projects in the Michigan counties of Tuscola, Huron, Sanilac and St. Clair. Construction activities commenced for the Thumb Loop Project in 2012. Phase 1 and Phase 2 of the Thumb Loop Project, which consisted of 62 miles and 20 miles of transmission line, respectively, were placed in-service in September 2013 and May 2014, respectively. The third and final phase, which consisted of 56 miles of transmission line, was placed in-service in May 2015. Through September 30, 2015, ITCTransmission has invested $497.8 million in the Thumb Loop Project and any further investment to complete this project is not expected to be material.
Rate of Return on Equity and Capital Structure Complaints
On November 12, 2013, certain parties filed a joint complaint with the FERC under Section 206 of the FPA (the “Complaint”), requesting that the FERC find the current 12.38% MISO regional base ROE rate (the “base ROE”) for all MISO TOs, including ITCTransmission, METC and ITC Midwest to no longer be just and reasonable. The complainants sought a FERC order reducing the base ROE used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 9.15%, reducing the equity component of our capital structure from the FERC approved 60% to 50% and terminating the ROE adders currently approved for certain ITC Holdings operating companies, including adders currently utilized by ITCTransmission and METC.
We believe that the current ROE encourages transmission investment and offsets the burdens associated with maintaining the independent transmission business model and RTO membership. ITCTransmission, METC and ITC Midwest filed responses during the first quarter of 2014, separately and together with other MISO TOs, that seek dismissal of the Complaint for its failure to satisfy the requirements of FPA Section 206 and the FERC’s accompanying Rules, or denial of the Complaint on the merits, with prejudice.
On October 16, 2014, FERC granted the complainants’ request in part by setting the base ROE for hearing and settlement procedures, while denying all other aspects of the Complaint. FERC found that the complainants failed to show that the use of actual or FERC-approved capital structures that include more than 50% equity are unjust and unreasonable. FERC also denied the request to terminate ITCTransmission’s and METC’s ROE incentives. The order reiterated that any TO’s total ROE rate is limited by the top end of a zone of reasonableness and the TO’s ability to implement the full amount of previously granted ROE adders may be affected by the outcome of the hearing. FERC set the refund effective date as November 12, 2013.
During the fourth quarter of 2014, the MISO TOs engaged in the ordered FERC settlement procedures with the complainants but were not able to reach resolution. On January 5, 2015, the Chief Judge issued an order which terminated settlement procedures and set the matter for hearing, with an initial decision within 47 weeks of the order. On April 6, 2015, the MISO TOs filed expert witness testimony in the Complaint proceeding supporting the existing base ROE as just and reasonable. However, in the event that FERC elects to change the base ROE, the testimony included a recommendation of 11.39% base ROE for the period of November 12, 2013 through February 12, 2015 (the “Initial Refund Period”). In resolving the Complaint, we expect FERC to establish a new base ROE to determine any potential refund liability for the Initial Refund Period. The new base ROE as well as any ROE adders, subject to the limitations of the top end of any zone of reasonableness that is established, are expected to be used to calculate the refund liability for the Initial Refund Period.
On February 12, 2015, an additional complaint was filed with the FERC under Section 206 of the FPA (the “Second Complaint”) by separate complainants, seeking a FERC order to reduce the base ROE used in our MISO Regulated Operating Subsidiaries’ formula transmission rates to 8.67% with an effective date of February 12, 2015. On March 11, 2015, the MISO TOs filed an answer to the Second Complaint with the FERC supporting the current base ROE as just and reasonable. On


27

June 18, 2015, FERC accepted the Second Complaint and set it for hearing and settlement procedures. FERC also set the refund effective date for the Second Complaint as February 12, 2015.
On October 20, 2015, the MISO TOs filed expert witness testimony in the Second Complaint proceeding supporting the existing base ROE as just and reasonable. However, in the event that FERC elects to change the base ROE, the testimony included a recommendation of 10.75% base ROE for the period of February 12, 2015 through May 11, 2016 (the “Second Refund Period”). The data ultimately used to establish any new base ROE will be filed by the parties to the Second Complaint in January 2016 for the period ending December 31, 2015. In resolving the Second Complaint, we expect FERC to establish a new base ROE to determine any potential refund liability for the Second Refund Period. The base ROE established by FERC for the Second Complaint as well as any ROE adders, subject to the limitations of the top end of any zone of reasonableness established, are expected to be used to calculate the refund liability for the Second Refund Period.
We believe it is probable that refunds will be required for these matters and as of September 30, 2015, the estimated range of refunds on a pre-tax basis is expected to be from $88.0 million to $158.9 million for the period from November 12, 2013 through September 30, 2015. As of September 30, 2015 and December 31, 2014, our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $88.0 million and $47.8 million, respectively, representing the low end of the range of potential refunds as of those dates, as there is no best estimate within the range of refunds. The recognition of this estimated liability resulted in a reduction in revenues of $18.0 million, $38.8 million and $46.9 million and an increase in interest expense of $0.5 million, $1.4 million and $0.9 million for the three and nine months ended September 30, 2015 and the year ended December 31, 2014, respectively. This resulted in an estimated after-tax reduction to net income of $11.2 million, $24.5 million and $28.9 million for the three and nine months ended September 30, 2015 and the year ended December 31, 2014, respectively. No amounts related to these complaints were recorded as of or for the three and nine months ended September 30, 2014.
Based on the estimated range of refunds identified above, we believe that it is reasonably possible that these matters could result in an additional estimated pre-tax refund of up to $70.9 million (or a $43.0 million estimated after-tax reduction of net income) in excess of the amount recorded as of September 30, 2015. It is also possible the outcome of these matters could differ from the estimated range of losses and materially affect our results of operations due to the uncertainty of the calculation of an authorized base ROE along with the zone of reasonableness under the newly adopted two-step DCF methodology, which is subject to significant discretion by the FERC. As of September 30, 2015, our MISO Regulated Operating Subsidiaries had a total of approximately $2.8 billion of equity in their collective capital structures for ratemaking purposes. Based on this level of aggregate equity, we estimate that each 10 basis point reduction in the authorized ROE would reduce annual consolidated net income by approximately $2.8 million.
In a separate but related matter, in November 2014, METC, ITC Midwest and other MISO TOs filed a request with FERC under FPA Section 205 for authority to include a 50 basis point incentive adder for RTO participation in each of the TOs’ formula rates. On January 5, 2015, FERC approved the use of this incentive adder, effective January 6, 2015. Additionally, ITC Midwest filed a request with FERC under FPA Section 205 in January 2015 for authority to include a 100 basis point incentive adder for independent transmission ownership, which is currently authorized for ITCTransmission and METC. On March 31, 2015, FERC approved the use of a 50 basis point incentive adder for independence, effective April 1, 2015. On April 30, 2015, ITC Midwest filed a request with FERC for clarification and rehearing on the approved incentive adder for independence. The RTO participation incentive adder will be applied to METC’s and ITC Midwest’s base ROEs and the independence incentive adder will be applied to ITC Midwest’s base ROE in establishing their total authorized ROE rates, subject to the limitations of the top end of any zone of reasonableness that is established. Collection of these recently approved incentive adders is being deferred pending the outcome of the complaints relating to the base ROE.
Accelerated Share Repurchase Program
On September 30, 2015, ITC Holdings entered into an accelerated share repurchase program for $115.0 million with Barclays Bank PLC (“Barclays”), which is part of the share repurchase program described in Note 6 to the condensed consolidated financial statements. Under the ASR program, ITC Holdings paid $115.0 million to Barclays on September 30, 2015 and received an initial delivery of 2.8 million shares on October 1, 2015. The fair market value of the initial share delivery was $92.0 million, based on the closing market price of $33.34 per share at the commencement of the ASR agreement. The final number of shares delivered under the ASR agreement will be based on the volume-weighted average share price of our common stock during the term of the transaction, less an agreed upon discount and adjusted for the initial share delivery. The ASR program is expected to be completed by the end of 2015. See further discussion in Note 6 and Note 8 to the condensed consolidated financial statements.


28

MISO Formula Rate Template Modification Filing
On October 30, 2015, ITCTransmission, METC and ITC Midwest (collectively, the “joint applicants”) requested modifications, pursuant to Section 205 of the FPA, to certain aspects of the joint applicants’ respective formula rate templates which included, among other things, changes to ensure that various income tax items are computed correctly for purposes of determining their revenue requirements. The joint applicants requested an effective date of January 1, 2016 for the proposed template changes. The formula rate templates, prior to any proposed modifications, include certain deferred income taxes on contributions in aid of construction in rate base that result in the joint applicants recovering excess amounts from customers. The recognition of this refund liability in the third quarter of 2015 resulted in a reduction in revenues of $8.6 million, which includes amounts recovered for all historical periods through September 30, 2015, and an increase in interest expense of $0.8 million for the three and nine months ended September 30, 2015. This resulted in an estimated after-tax reduction to net income of $5.5 million for the three and nine months ended September 30, 2015. We do not expect the formula rate modifications, if accepted by FERC, to have a material impact on our consolidated results of operations, cash flows or financial condition.
Cost-Based Formula Rates with True-Up Mechanism
Our Regulated Operating Subsidiaries calculate their revenue requirements using cost-based formula rate templates and are effective without the need to file rate cases with the FERC, although the rates are subject to legal challenge at the FERC. Under these formula rate templates, our Regulated Operating Subsidiaries recover expenses and earn a return on and recover investments in property, plant and equipment on a current rather than a lagging basis. The formula rate templates utilize forecasted expenses, property, plant and equipment, point-to-point revenues, network load at our MISO Regulated Operating Subsidiaries and other items for the upcoming calendar year to establish projected revenue requirements for each of our Regulated Operating Subsidiaries that are used as the basis for billing for service on their systems from January 1 to December 31 of that year. Our cost-based formula rate templates include a true-up mechanism, whereby our Regulated Operating Subsidiaries compare their actual revenue requirements to their billed revenues for each year to determine any over- or under-collection of revenue. The over- or under-collection typically results from differences between the projected revenue requirement used as the basis for billing and actual revenue requirement at each of our Regulated Operating Subsidiaries, or from differences between actual and projected monthly peak loads at our MISO Regulated Operating Subsidiaries. In the event billed revenues in a given year are more or less than actual revenue requirements, which are calculated primarily using information from that year’s FERC Form No. 1, our Regulated Operating Subsidiaries will refund or collect additional revenues, with interest, within a two-year period such that customers pay only the amounts that correspond to actual revenue requirements for that given period. This annual true-up ensures that our Regulated Operating Subsidiaries recover their allowed costs and earn their allowed returns.
Revenue Accruals and Deferrals — Effects of Monthly Peak Loads
For our MISO Regulated Operating Subsidiaries, monthly peak loads are used for billing network revenues, which currently is the largest component of our operating revenues. One of the primary factors that impacts the revenue accruals and deferrals at our MISO Regulated Operating Subsidiaries is actual monthly peak loads experienced as compared to those forecasted in establishing the annual network transmission rate. Under their cost-based formula rates that contain a true-up mechanism, our Regulated Operating Subsidiaries accrue or defer revenues to the extent that their actual revenue requirement for the reporting period is higher or lower, respectively, than the amounts billed relating to that reporting period. Although monthly peak loads do not impact operating revenues recognized, network load affects the timing of our cash flows from transmission service. The monthly peak load of our MISO Regulated Operating Subsidiaries is 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.
ITC Great Plains does not receive revenue based on a peak load or a dollar amount per kW each month and therefore peak load does not have a seasonal effect on its operating cash flows. The SPP tariff applicable to ITC Great Plains is billed ratably each month based on its annual projected revenue requirement posted annually by SPP.
Capital Investment and Operating Results Trends
We expect our actual revenue requirements for our Regulated Operating Subsidiaries to increase over the long term, which should result in a long term upward trend in revenues and earnings subject to the impact of any required refunds as a result of the resolution of the complaints relating to base ROE as described in Note 11 to the condensed consolidated financial statements. The primary factor that is expected to continue to increase our actual revenue requirements in future years is increased rate base that would result from our anticipated capital investment, in excess of depreciation, from our Regulated


29

Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. In addition, our capital investment efforts relating to development initiatives are based on establishing an ongoing pipeline of projects that would position us for long-term growth. Investments in property, plant and equipment, when placed in service upon completion of a capital project, are added to the rate base of our Regulated Operating Subsidiaries.
Our Regulated Operating Subsidiaries strive for high reliability of their systems and to improve system accessibility for all generation resources. The FERC requires compliance with certain reliability standards and may take enforcement actions against violators, including the imposition of substantial fines. NERC is responsible for developing and enforcing these mandatory reliability standards. We continually assess our transmission systems against standards established by NERC, as well as the standards of applicable regional entities under NERC that have been delegated certain authority for the purpose of proposing and enforcing reliability standards. We believe we meet the applicable standards in all material respects, although further investment in our transmission systems and an increase in maintenance activities will likely be needed to maintain compliance, improve reliability and address any new standards that may be promulgated.
We also assess our transmission systems against our own planning criteria that are filed annually with the FERC. Based on our planning studies, we see needs to make capital investments to (1) rebuild existing property, plant and equipment; (2) upgrade the system to address demographic changes that have impacted transmission load and the changing role that transmission plays in meeting the needs of the wholesale market, including accommodating the siting of new generation or to increase import capacity to meet changes in peak electrical demand; (3) relieve congestion in the transmission systems; and (4) achieve state and federal policy goals, such as renewable generation portfolio standards. The following table shows our expected and actual capital investment for each of the Regulated Operating Subsidiaries and our development initiatives:
 
 
 
 
Actual Capital
 
Forecasted Capital
 
 
Long-term Capital
 
Investment for the
 
Investment for the
(in millions)
 
Investment Program
 
nine months ended
 
year ending
Source of Investment
 
2014-2018
 
September 30, 2015 (a)
 
December 31, 2015
ITCTransmission
 
$
647

 
$
120.2

 
$180 — 190
METC
 
546

 
91.6

 
155 — 170
ITC Midwest (b)
 
1,991

 
273.9

 
370 — 385
ITC Great Plains
 
194

 
11.6

 
10 — 15
Development and other (c)
 
1,122

 
4.1

 
0 — 5
Total
 
$
4,500

 
$
501.4

 
$715 — 765
____________________________
(a)
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.
(b)
ITC Midwest’s investment program includes the 2011 MISO MVPs as discussed above under “Capital Project Updates and Other Recent Developments.”
(c)
Development and other includes initiatives to upgrade the existing transmission grid and regional transmission facilities, primarily to improve overall grid reliability, reduce transmission constraints, enhance competitive markets and facilitate interconnections of new generating resources, including wind generation and other renewable resources necessary to achieve state and federal policy goals. Additionally, we may pursue other non-traditional transmission investment opportunities not described above.
Investments in property, plant and equipment could vary due to, among other things, the impact of actual loads, forecasted loads, regional economic conditions, weather conditions, union strikes, labor shortages, material and equipment prices and availability, our ability to obtain any necessary financing for such expenditures, limitations on the amount of construction that can be undertaken on our systems at any one time, regulatory approvals for reasons relating to rate construct, environmental, siting, regional planning, cost recovery or other issues or as a result of legal proceedings, variances between estimated and actual costs of construction contracts awarded and the potential for greater competition. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects and other factors beyond our control.


30

RESULTS OF OPERATIONS
Results of Operations and Variances
 
Three months ended
 
 
 
Percentage
 
Nine months ended
 
 
 
Percentage
 
September 30,
 
Increase
 
increase
 
September 30,
 
Increase
 
increase
(in thousands)
2015
 
2014
 
(decrease)
 
(decrease)
 
2015
 
2014
 
(decrease)
 
(decrease)
OPERATING REVENUES
$
273,189

 
$
270,134

 
$
3,055

 
1.1
 %
 
$
820,734

 
$
791,951

 
$
28,783

 
3.6
 %
OPERATING EXPENSES
 
 
 
 
 
 

 
 
 
 
 
 
 
 
Operation and maintenance
32,721

 
29,038

 
3,683

 
12.7
 %
 
88,309

 
79,735

 
8,574

 
10.8
 %
General and administrative
33,677

 
28,812

 
4,865

 
16.9
 %
 
107,064

 
87,082

 
19,982

 
22.9
 %
Depreciation and amortization
36,890

 
31,936

 
4,954

 
15.5
 %
 
106,903

 
94,609

 
12,294

 
13.0
 %
Taxes other than income taxes
20,463

 
19,205

 
1,258

 
6.6
 %
 
61,629

 
57,474

 
4,155

 
7.2
 %
Other operating (income) and expenses — net
(206
)
 
(289
)
 
83

 
(28.7
)%
 
(675
)
 
(750
)
 
75

 
(10.0
)%
Total operating expenses
123,545

 
108,702

 
14,843

 
13.7
 %
 
363,230

 
318,150

 
45,080

 
14.2
 %
OPERATING INCOME
149,644

 
161,432

 
(11,788
)
 
(7.3
)%
 
457,504

 
473,801

 
(16,297
)
 
(3.4
)%
OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense
51,398

 
47,328

 
4,070

 
8.6
 %
 
150,070

 
138,491

 
11,579

 
8.4
 %
Allowance for equity funds used during construction
(6,421
)
 
(4,921
)
 
(1,500
)
 
30.5
 %
 
(21,434
)
 
(14,865
)
 
(6,569
)
 
44.2
 %
Loss on extinguishment of debt
—

 
—

 
—

 
n/a

 
—

 
29,074

 
(29,074
)
 
n/a

Other income
(384
)
 
(244
)
 
(140
)
 
57.4
 %
 
(804
)
 
(618
)
 
(186
)
 
30.1
 %
Other expense
1,372

 
761

 
611

 
80.3
 %
 
2,969

 
3,696

 
(727
)
 
(19.7
)%
Total other expenses (income)
45,965

 
42,924

 
3,041

 
7.1
 %
 
130,801

 
155,778

 
(24,977
)
 
(16.0
)%
INCOME BEFORE INCOME TAXES
103,679

 
118,508

 
(14,829
)
 
(12.5
)%
 
326,703

 
318,023

 
8,680

 
2.7
 %
INCOME TAX PROVISION
38,106

 
44,635

 
(6,529
)
 
(14.6
)%
 
121,662

 
120,678

 
984

 
0.8
 %
NET INCOME
$
65,573

 
$
73,873

 
$
(8,300
)
 
(11.2
)%
 
$
205,041

 
$
197,345

 
$
7,696

 
3.9
 %
Operating Revenues
Three months ended September 30, 2015 compared to three months ended September 30, 2014
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2015
 
2014
 
Increase
 
increase
(in thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(decrease)
 
(decrease)
Network revenues
$
205,527

 
75.2
 %
 
$
191,112

 
70.7
%
 
$
14,415

 
7.5
 %
Regional cost sharing revenues
85,616

 
31.3
 %
 
70,198

 
26.0
%
 
15,418

 
22.0
 %
Point-to-point
3,922

 
1.4
 %
 
4,192

 
1.6
%
 
(270
)
 
(6.4
)%
Scheduling, control and dispatch
3,328

 
1.2
 %
 
3,146

 
1.2
%
 
182

 
5.8
 %
Other
1,383

 
0.5
 %
 
1,486

 
0.5
%
 
(103
)
 
(6.9
)%
Recognition of rate refund liabilities
(26,587
)
 
(9.6
)%
 
—

 
—
%
 
(26,587
)
 
n/a

Total
$
273,189

 
100.0
 %
 
$
270,134

 
100.0
%
 
$
3,055

 
1.1
 %
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the three months ended September 30, 2015 as compared to the same period in 2014. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service.
Regional cost sharing revenues increased primarily due to additional capital projects identified by MISO as eligible for regional cost sharing and these projects being placed in-service in addition to higher accumulated investment for the Thumb Loop Project and Kansas V-Plan Project during the three months ended September 30, 2015 as compared to the same period in 2014. We expect to continue to receive regional cost sharing revenues and the amounts could increase in the near future, including revenues associated with projects that have been or are expected to be approved for regional cost sharing.


31

The recognition of the rate refund liabilities for potential refunds relating to the ROE complaints and refunds relating to the formula rate template modification described in Notes 3 and 11 to the condensed consolidated financial statements, respectively, resulted in a reduction to operating revenues totaling $26.6 million during the three months ended September 30, 2015. We are not able to estimate whether any required refunds would be applied to all components of revenues listed in the table above or only certain components.
Operating revenues for the three months ended September 30, 2015 include the revenue accruals and deferrals as described in Note 3 to the condensed consolidated financial statements.
Nine months ended September 30, 2015 compared to nine months ended September 30, 2014
The following table sets forth the components of and changes in operating revenues:
 
 
 
 
 
 
 
 
 
 
 
Percentage
 
2015
 
2014
 
Increase
 
increase
(in thousands)
Amount
 
Percentage
 
Amount
 
Percentage
 
(decrease)
 
(decrease)
Network revenues
$
595,782

 
72.6
 %
 
$
566,188

 
71.5
%
 
$
29,594

 
5.2
 %
Regional cost sharing revenues
240,949

 
29.4
 %
 
193,451

 
24.4
%
 
47,498

 
24.6
 %
Point-to-point
11,972

 
1.5
 %
 
13,829

 
1.7
%
 
(1,857
)
 
(13.4
)%
Scheduling, control and dispatch
9,691

 
1.2
 %
 
9,539

 
1.2
%
 
152

 
1.6
 %
Other
9,763

 
1.2
 %
 
8,944

 
1.2
%
 
819

 
9.2
 %
Recognition of rate refund liabilities
(47,423
)
 
(5.9
)%
 
—

 
—
%
 
(47,423
)
 
n/a

Total
$
820,734

 
100.0
 %
 
$
791,951

 
100.0
%
 
$
28,783

 
3.6
 %
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the nine months ended September 30, 2015 as compared to the same period in 2014. Higher net revenue requirements were due primarily to higher rate bases associated with higher balances of property, plant and equipment in-service.
Regional cost sharing revenues increased primarily due to additional capital projects identified by MISO as eligible for regional cost sharing and these projects being placed in-service in addition to higher accumulated investment for the Thumb Loop Project and Kansas V-Plan Project during the nine months ended September 30, 2015 as compared to the same period in 2014. We expect to continue to receive regional cost sharing revenues and the amounts could increase in the near future, including revenues associated with projects that have been or are expected to be approved for regional cost sharing.
The recognition of the rate refund liabilities for potential refunds relating to the ROE complaints and refunds relating to the formula rate template modification described in Notes 3 and 11 to the condensed consolidated financial statements, respectively, resulted in a reduction to operating revenues of $47.4 million during the nine months ended September 30, 2015. We are not able to estimate whether any required refunds would be applied to all components of revenues listed in the table above or only certain components.
Operating revenues for the nine months ended September 30, 2015 include the revenue accruals and deferrals as described in Note 3 to the condensed consolidated financial statements.
Operating Expenses
Operation and maintenance expenses
Three and nine months ended September 30, 2015 compared to three and nine months ended September 30, 2014
Operation and maintenance expenses increased primarily due to higher vegetation management requirements and higher expenses associated with substation and overhead line maintenance activities.
General and administrative expenses
Three months ended September 30, 2015 compared to three months ended September 30, 2014
General and administrative expenses increased primarily due to higher professional services such as legal and advisory services fees primarily for various development initiatives of $3.0 million and higher compensation expenses of $1.7 million mainly due to personnel additions.


32

Nine months ended September 30, 2015 compared to nine months ended September 30, 2014
General and administrative expenses increased primarily due to higher compensation-related expenses of $13.6 million, mainly due to development bonuses paid during the three months ended March 31, 2015 as described in detail above under “Capital Project Updates and Other Recent Developments — Development Bonuses,” and higher professional services such as legal and advisory services fees primarily for various development initiatives of $5.6 million.
Depreciation and amortization expenses
Three and nine months ended September 30, 2015 compared to three and nine months ended September 30, 2014
Depreciation and amortization expenses increased due primarily to a higher depreciable base resulting from property, plant and equipment in-service additions.
Taxes other than income taxes
Three and nine months ended September 30, 2015 compared to three and nine months ended September 30, 2014
Taxes other than income taxes increased due to higher property tax expenses due primarily to our Regulated Operating Subsidiaries’ 2014 capital additions, which are included in the assessments for 2015 personal property taxes.
Other Expenses (Income)
Three and nine months ended September 30, 2015 compared to three and nine months ended September 30, 2014
Interest Expense
Interest expense increased due primarily to additional interest expense associated with the net issuance of $475.0 million in long-term debt securities subsequent to September 30, 2014.
Allowance for Equity Funds Used During Construction
Allowance for Equity Funds Used During Construction (“AFUDC equity”) increased due primarily to higher balances of construction work in progress eligible for AFUDC equity during the period.
Loss on Extinguishment of Debt
The loss on extinguishment of debt related to the partial tender of the 5.875% ITC Holdings Senior Notes and the 6.375% ITC Holdings Senior Notes during the second quarter of 2014. See Note 8 to the consolidated financial statements as of and for the year ended December 31, 2014 included in our Form 10-K for such period for a detailed discussion on the cash tender offer.
Income Tax Provision
Three months ended September 30, 2015 compared to three months ended September 30, 2014
Our effective tax rates for the three months ended September 30, 2015 and 2014 were 36.8% and 37.7%, respectively. Our effective tax rate in both periods exceeded our 35% statutory federal income tax rate due primarily to state income taxes, partially offset by the tax effects of AFUDC equity which reduced the effective tax rate. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision. We recorded a state income tax provision of $3.8 million (net of federal deductibility) during the three months ended September 30, 2015 compared to a state income tax provision of $4.3 million (net of federal deductibility) for the three months ended September 30, 2014.
Nine months ended September 30, 2015 compared to nine months ended September 30, 2014
Our effective tax rates for the nine months ended September 30, 2015 and 2014 were 37.2% and 37.9%, respectively. Our effective tax rate in both periods exceeded our 35% statutory federal income tax rate due primarily to state income taxes, partially offset by the tax effects of AFUDC equity which reduced the effective tax rate. The amount of income tax expense relating to AFUDC equity was recognized as a regulatory asset and not included in the income tax provision. We recorded a state income tax provision of $11.9 million (net of federal deductibility) during the nine months ended September 30, 2015, compared to a state income tax provision of $12.2 million (net of federal deductibility) for the nine months ended September 30, 2014.


33

LIQUIDITY AND CAPITAL RESOURCES
We expect to fund our future capital requirements with cash from operations, our existing cash and cash equivalents, issuances under our commercial paper program and amounts available under our revolving credit agreements (described in Note 5 to the condensed consolidated financial statements). In addition, we may from time to time secure debt and equity funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. As market conditions warrant, we may also from time to time repurchase debt or equity securities issued by us, in the open market, in privately negotiated transactions, by tender offer or otherwise. We expect that our capital requirements will arise principally from our need to:
•
Fund capital expenditures at our Regulated Operating Subsidiaries. Our plans with regard to property, plant and equipment investments are described in detail above under “— Capital Investment and Operating Results Trends.”
•
Fund business development expenses and related capital expenditures. We are pursuing development activities for transmission projects which will continue to result in the incurrence of development expenses and could result in significant capital expenditures.
•
Fund working capital requirements.
•
Fund our debt service requirements, including principal repayments and periodic interest payments. We expect our interest payments to increase each year as a result of additional debt we expect to incur to fund our capital expenditures and for general corporate purposes.
•
Fund any potential share repurchases available under the ASR program as described in Note 6 to the condensed consolidated financial statements.
•
Fund contributions to our retirement benefit plans, as described in Note 9 to the condensed consolidated financial statements. We expect to make an estimated additional contribution of approximately $2.2 million to these plans in 2015.
In addition to the expected capital requirements above, any adverse determinations relating to the contingencies described in Notes 3 and 11 to the condensed consolidated financial statements would result in additional capital requirements.
We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and to fund capital investments. ITC Holdings’ sources of cash are dividends and other payments received by us from our Regulated Operating Subsidiaries and any other subsidiaries we may have in addition to the proceeds raised from the sale of our debt and equity securities. Each of our Regulated Operating Subsidiaries, while wholly owned by ITC Holdings, is legally distinct from ITC Holdings and has no obligation, contingent or otherwise, to make funds available to us.
We expect to continue to utilize our commercial paper program and revolving credit agreements as well as our cash and cash equivalents as needed to meet our short-term cash requirements. As of September 30, 2015, we had consolidated indebtedness under our revolving and term loan credit agreements of $330.0 million, with unused capacity under our revolving credit agreements of $831.0 million. Additionally, ITC Holdings had $219.0 million of commercial paper issued and outstanding as of September 30, 2015 with the ability to issue an additional $181.0 million under the commercial paper program. See Note 5 to the condensed consolidated financial statements for a detailed discussion of the commercial paper program and our revolving credit agreements as well as the debt issuance in 2015.
As of September 30, 2015, we had approximately $694.3 million of debt maturing within one year, which we expect to refinance with long-term debt. To address our long-term capital requirements and to repay debt maturing within one year, we expect that we will need to obtain additional debt financing. Certain of our capital projects could be delayed in the event we experience difficulties in accessing capital. We expect to be able to obtain such additional financing for both our short and long-term requirements as needed, in amounts and upon terms that will be reasonably satisfactory to us due to our strong credit ratings and our historical ability to obtain financing.
Credit Ratings
Credit ratings by nationally recognized statistical rating agencies are an important component of our liquidity profile. Credit ratings relate to our ability to issue debt securities and the cost to borrow money, and should not be viewed as an indication of future stock performance or a recommendation to buy, sell, or hold securities. Ratings are subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating. Our current credit ratings are displayed in the following table. An explanation of these ratings may be obtained from the respective rating agency.


34


Issuer
 

Issuance
 
Standard and Poor’s
Ratings Services (a)
 
Moody’s Investor
Service, Inc. (b)
ITC Holdings
 
Senior Unsecured Notes
 
BBB+
 
Baa2
ITC Holdings
 
Commercial Paper
 
A-2
 
Prime-2
ITCTransmission
 
First Mortgage Bonds
 
A
 
A1
METC
 
Senior Secured Notes
 
A
 
A1
ITC Midwest
 
First Mortgage Bonds
 
A
 
A1
ITC Great Plains
 
First Mortgage Bonds
 
A
 
A1
____________________________
(a)
On December 6, 2013, Standard and Poor’s Ratings Services (“Standard and Poor’s”) upgraded the senior unsecured credit rating of ITC Holdings and reaffirmed the secured credit ratings of ITCTransmission, METC and ITC Midwest. On October 7, 2014, Standard and Poor’s issued a secured credit rating for ITC Great Plains. Additionally, on June 8, 2015, Standard and Poor’s assigned a short-term issuer credit rating to ITC Holdings, which applies to the recently established commercial paper program discussed in Note 5 to the condensed consolidated financial statements. All of the ratings have a stable outlook.
(b)
On April 15, 2015, Moody’s Investor Service, Inc. (“Moody’s”) reaffirmed the credit ratings for ITC Holdings and the Regulated Operating Subsidiaries. Additionally, on June 9, 2015, Moody’s assigned a short-term commercial paper rating to ITC Holdings, which applies to the recently established commercial paper program discussed in Note 5 to the condensed consolidated financial statements. All of the ratings have a stable outlook.
Covenants
Our debt instruments include senior notes, secured notes, first mortgage bonds and unsecured revolving and term loan credit agreements containing numerous financial and operating covenants that place significant restrictions, which are described in Note 5 to the condensed consolidated financial statements and in our Form 10-K for the fiscal year ended December 31, 2014. As of September 30, 2015, we were not in violation of any debt covenant. In the event of a downgrade in our credit ratings, none of the covenants would be directly impacted, although the borrowing costs under our revolving and term loan credit agreements would increase.
Cash Flows From Operating Activities
Net cash provided by operating activities was $386.3 million and $360.9 million for the nine months ended September 30, 2015 and 2014, respectively. The increase in cash provided by operating activities was due primarily to an increase in cash received from operating revenues of $55.8 million during the nine months ended September 30, 2015 compared to the same period in 2014. The increase was partially offset by higher income taxes paid of $23.9 million and an increase of $10.3 million in contributions to our retirement benefit plans.
Cash Flows From Investing Activities
Net cash used in investing activities was $475.1 million and $552.3 million for the nine months ended September 30, 2015 and 2014, respectively. The decrease in cash used in investing activities was due primarily to the timing of payments for investments in property, plant and equipment during the nine months ended September 30, 2015 compared to the same period in 2014.
Cash Flows From Financing Activities
Net cash provided by financing activities was $85.2 million and $168.7 million for the nine months ended September 30, 2015 and 2014, respectively. The decrease in cash provided by financing activities was due primarily to a net decrease of $293.1 million in amounts outstanding under our revolving and term loan credit agreements and a decrease in long-term debt issuances of $273.7 million during the nine months ended September 30, 2015 compared to the same period in 2014. These decreases were partially offset by a decrease of $248.5 million in payments to retire long-term debt and the $219.0 million in net proceeds from the issuance of commercial paper under our commercial paper program during the nine months ended September 30, 2015. See Note 5 to the condensed consolidated financial statements for details on the commercial paper program. Additionally, there was a payment of $115.0 million for the accelerated share repurchase program during the nine months ended September 30, 2015 as compared to the $150.0 million during the same period in 2014.


35

CONTRACTUAL OBLIGATIONS
Our contractual obligations are described in our Form 10-K for the year ended December 31, 2014. There have been no material changes to that information since December 31, 2014, other than the items listed below and described in Note 5 to the condensed consolidated financial statements:
•
Amounts borrowed under our unsecured, unguaranteed revolving credit agreements;
•
The issuance of $225.0 million of 3.83% First Mortgage Bonds, Series G, due 2055 by ITC Midwest; and
•
The $219.0 million of commercial paper issued and outstanding under the recently established commercial paper program for ITC Holdings.
CRITICAL ACCOUNTING POLICIES
Our condensed consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of these condensed consolidated financial statements requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events. These estimates and judgments, in and of themselves, could materially impact the condensed consolidated financial statements and disclosures based on varying assumptions, as future events rarely develop exactly as forecasted, and even the best estimates routinely require adjustment. The accounting policies discussed in “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies” in our Form 10-K for the fiscal year ended December 31, 2014 are considered by management to be the most important to an understanding of the consolidated financial statements because of their significance to the portrayal of our financial condition and results of operations or because their application places the most significant demands on management’s judgment and estimates about the effect of matters that are inherently uncertain. There have been no material changes to that information during the nine months ended September 30, 2015.
RECENT ACCOUNTING PRONOUNCEMENTS
See Note 2 to the condensed consolidated financial statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Fixed Rate Debt
Based on the borrowing rates currently available for bank loans with similar terms and average maturities, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $4,073.8 million at September 30, 2015. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, was $3,855.2 million at September 30, 2015. We performed an analysis calculating the impact of changes in interest rates on the fair value of long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements and commercial paper, at September 30, 2015. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at September 30, 2015 would decrease the fair value of debt by $161.2 million, and a decrease in interest rates of 10% at September 30, 2015 would increase the fair value of debt by $175.8 million at that date.
Revolving and Term Loan Credit Agreements
At September 30, 2015, we had a consolidated total of $330.0 million outstanding under our revolving and term loan credit agreements, which are variable rate loans and fair value approximates book value. A 10% increase or decrease in borrowing rates under the revolving and term loan credit agreements compared to the weighted average rates in effect at September 30, 2015 would increase or decrease interest expense by $0.4 million, respectively, for an annual period with a constant borrowing level of $330.0 million.
Commercial Paper
At September 30, 2015, ITC Holdings had $219.0 million of commercial paper issued and outstanding under the commercial paper program. Due to the short-term nature of these financial instruments, the carrying value approximates fair value. A 10%


36

increase or decrease in interest rates for commercial paper would increase or decrease interest expense by $0.1 million for an annual period with a continuous level of commercial paper outstanding of $219.0 million.
Derivative Instruments and Hedging Activities
We use derivative financial instruments, including interest rate swap contracts, to manage our exposure to fluctuations in interest rates. The use of these financial instruments mitigates exposure to these risks and the variability of our operating results. We are not a party to leveraged derivatives and do not enter into derivative financial instruments for trading or speculative purposes. The interest rate swap contracts held as of September 30, 2015 manage interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the expected refinancing of the maturing ITC Holdings 5.875% Senior Notes, due September 30, 2016. As of September 30, 2015, ITC Holdings had $139.3 million outstanding under the 5.875% Senior Notes.
Other
As described in our Form 10-K for the fiscal year ended December 31, 2014, we are subject to commodity price risk from market price fluctuations, and to credit risk primarily with DTE Electric, Consumers Energy and IP&L, our primary customers. There have been no material changes in these risks during the nine months ended September 30, 2015.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to provide reasonable assurance that material information required to be disclosed in our reports that we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure. In designing and evaluating the disclosure controls and procedures, management recognized that a control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, with a company have been detected.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting during the three months ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Note 11 to the condensed consolidated financial statements for a description of recent developments in the rate of return on equity and capital structure complaints filed against all MISO TOs, including our MISO Regulated Operating Subsidiaries.
ITEM 1A. RISK FACTORS
For information regarding risk factors affecting us, see “Item 1A Risk Factors” of our Form 10-K for the fiscal year ended December 31, 2014. There have been no material changes to the risk factors set forth therein.


37

ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth the repurchases of common stock for the quarter ended September 30, 2015:
 
Period
 
Total Number of Shares Purchased
 
 Average Price Paid per Share
 
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or Programs (a)
 
Maximum Number (or Approximate Dollar
Value) of Shares that May
Yet Be Purchased Under the Plans or Programs (in millions) (a)
 
 
July 2015 (b)
 
1,181

 
$
33.09

 
—

 
$
120.0

 
August 2015 (b)
 
1,043

 
33.97

 
—

 
120.0

 
September 2015 (c)
 
2,759,992

 
33.34

 
2,759,448

 
28.0

 
Total
 
2,762,216

 
$
33.34

 
2,759,448

 

____________________________
(a)
In April 2014, the Board of Directors authorized and ITC Holdings announced a share repurchase program for up to $250.0 million, which expires in December 2015. On September 30, 2015, ITC Holdings entered into an accelerated share repurchase agreement with Barclays for $115.0 million, under which ITC Holdings paid $115.0 million to Barclays on September 30, 2015 and received an initial delivery of 2.8 million shares on October 1, 2015 with a fair market value of $92.0 million. We do not expect to repurchase shares prior to year end under the share repurchase program authorized by the Board of Directors except for shares that may be delivered at the conclusion of the ASR program. See Note 6 to the condensed consolidated financial statements for further discussion on the ASR program.
(b)
Shares acquired were delivered to us by employees as payment of tax withholding obligations due to us upon the vesting of restricted stock.
(c)
Shares acquired were delivered to us by employees as payment of tax withholding obligations due to us upon the vesting of restricted stock in addition to shares delivered under the ASR program noted above.





38

ITEM 6. EXHIBITS
The following exhibits are filed as part of this report (unless otherwise noted to be previously filed, and therefore incorporated herein by reference). Our SEC file number is 001-32576.
Exhibit No.
 
Description of Document
 
 
 
10.151

 
Amended and Restated Generator Interconnection Agreement by and among Michigan Electric Transmission Company, LLC, Consumers Energy Company and the Midcontinent Independent System Operator, Inc., dated as of September 30, 2015
 
 
 
31.1

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

 
Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
32

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

 
XBRL Instance Document
 
 
 
101.SCH

 
XBRL Taxonomy Extension Schema
 
 
 
101.CAL

 
XBRL Taxonomy Extension Calculation Linkbase
 
 
 
101.DEF

 
XBRL Taxonomy Extension Definition Database
 
 
 
101.LAB

 
XBRL Taxonomy Extension Label Linkbase
 
 
 
101.PRE

 
XBRL Taxonomy Extension Presentation Linkbase



39

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Dated: November 5, 2015
ITC HOLDINGS CORP.
 
 
By:
/s/ Joseph L. Welch
 
 
Joseph L. Welch
 
 
President and Chief Executive Officer
(duly authorized officer) 
 
 
 
 
By:
/s/ Rejji P. Hayes
 
 
Rejji P. Hayes
 
 
Senior Vice President, Chief Financial Officer and Treasurer (principal financial and accounting officer)
 


40




EXHIBIT 10.151

Original Sheet No. 58

 


SA 1756 METC-CONSUMERS GIA VERSION 32.0.0
EFFECTIVE 10/01/2015
NINTH REVISED SERVICE AGREEMENT NO. 1756
PUBLIC VERSION




Project G479B
AMENDED AND RESTATED
GENERATOR INTERCONNECTION AGREEMENT

entered into by and between

Michigan Electric Transmission Company, LLC

and

Consumers Energy Company

and

Midcontinent Independent System Operator, Inc.










Amended and Restated


GENERATOR INTERCONNECTION AGREEMENT






by and among


Michigan Electric Transmission Company, LLC


and


Consumers Energy Company


and the


Midcontinent Independent System Operator, Inc.
Amended and Restated
GENERATOR INTERCONNECTION AGREEMENT


THIS Amended AND RESTATED GENERATOR INTERCONNECTION AGREEMENT(the "Agreement") is made and entered into as of September 30, 2015, by and among Michigan Electric Transmission Company, LLC, a limited liability company with offices at 27175 Energy Way Novi, Michigan (herein referred to as “METC” or "Transmission Owner”), Consumers Energy Company, a Michigan corporation with offices at One Energy Plaza, Jackson, Michigan (herein referred to as “Consumers” or “Interconnection Customer”), and the Midcontinent Independent System Operator, Inc., formerly known as Midwest Independent Transmission System Operator, Inc., a non-profit, non-stock corporation organized and existing under the laws of the State of Delaware (herein referred to as “MISO” or “Transmission Provider”). Transmission Provider, Consumers and Transmission Owner each may be referred to individually as a "Party," or collectively as the "Parties." This Agreement amends, restates and replaces the May 2, 2014 Amendment and Restatement of the Generator Interconnection Agreement between the Transmission Owner, Transmission Provider and Consumers, effective on the Effective Date provided for below in Section 2.1.


WITNESSETH:

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

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

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

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





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

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

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

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

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


ARTICLE 1
DEFINITIONS

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

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

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

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

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

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

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





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

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

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

"Emergency" shall mean any system condition that requires automatic or immediate manual action to prevent or limit the loss of transmission assets or generation supply that could adversely affect the reliability of Transmission System or Consumers’ System or the systems to which either Party is directly or indirectly connected.

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

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

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

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

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

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

“Jointly Owned Assets” shall mean those assets in which Consumers and Transmission Owner have undivided ownership interests. Due to the nature of substation designs, many of the supporting




substation assets (e.g., station batteries, fencing, control houses, ground grid, yard stone, steel structures and some protective relay assets) cannot be separated by ownership and the Parties share in the ownership of such assets. The respective ownership of such assets by substation is shown in Exhibit B hereto.

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

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

“MISO Tariff” shall mean the Open Access Transmission, Energy and Operating Reserve Markets Tariff on file with the Commission as it may be amended or superseded from time to time.
    
“Monitoring Assets” shall mean the assets required to determine (a) the sequence of events for the operation of protective assets during an electrical fault, (b) the location and characteristics of an electrical fault and (c) the quality of power provided at the Point of Receipt.

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

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

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

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

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

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

"System Protection Assets" shall mean the assets required to protect (a) the Transmission System, the systems of others connected to the Transmission System, and Transmission Owner’s customers from faults occurring at the Unit, and (b) the Unit from faults occurring on the Transmission System or on the systems of others to which the Transmission System is directly or indirectly connected.
    
“Telemetry Equipment” shall mean the assets, identified by Transmission Owner, that are required to provide the necessary, real-time telemetry of Unit operations and status, as required by Transmission




Owner, for remote monitoring and control purposes. This typically includes but is not limited to, remote terminal units, distributed terminal units, telemetry signal inputs, fiber optic communication connections, transducers, pulse multipliers, isolation amplifiers, analog inputs, digital inputs, metering pulsed accumulator inputs, power supply, dedicated telephone data line to remote terminal units, telephone modem, telephone switching, interface terminal strips for landing signal inputs/outputs. Telemetry Equipment may be located at Consumers’ Unit and or at Transmission Owner’s assets.

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

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

“Transmission Provider” shall mean MISO.

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

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

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


ARTICLE 2
TERM OF AGREEMENT
2.1    Effective Date
This Agreement shall become effective on the date designated by the Commission in its order accepting this Agreement for filing (the “Effective Date”).

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

2.3    Termination
In the event that Transmission Owner joins a Regional Transmission Organization (“RTO”) which requires use of its own FERC-approved interconnection and operating agreement, this Agreement shall terminate on the effective date of such new interconnection and operating agreement between Consumers




and the RTO, except to the extent necessary to resolve billing and other outstanding matters related to service rendered under this Agreement as specified in Section 2.5.

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

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


ARTICLE 3
INTERCONNECTION SERVICE
3.1    Scope of Service

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

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

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

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





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

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

3.2    Third-Party Actions

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


ARTICLE 4
INTERCONNECTION ASSETS

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

4.2    Modifications
Either Party may undertake modifications to its assets. In the event a Party plans to undertake a modification that may be expected to impact the other Party's assets, that Party shall provide the other Party with sufficient information regarding such modification, including, without limitation, the notice required in accordance with Article 11 of this Agreement so that the other Party can evaluate the potential impact of such modification prior to commencement of the work. The Party desiring to perform such work shall provide the relevant drawings, plans, and specifications to the other Party at least ninety (90) days in advance of commencement of the work or such shorter period upon which the Parties may agree, which agreement will not unreasonably be withheld or delayed.

4.3    As-Built Drawings
Upon execution of this Agreement, Consumers shall provide to Transmission Provider and Transmission Owner current interconnection drawings and system diagrams for each of its Units, unless




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


ARTICLE 5
OPERATIONS
5.1    General
The Parties agree that they shall comply with the Operating Agreement, then-existing (or amended) applicable manuals, standards, and guidelines of Transmission Provider, NERC, ECAR, or any successor agency assuming or charged with similar responsibilities related to the operation and reliability of the North American electric interconnected transmission grid. To the extent that this Agreement does not specifically address or provide the mechanisms necessary to comply with such Operating Agreement, Transmission Provider, NERC or ECAR manuals, standards, or guidelines, the Parties hereby agree that each Party shall provide to the other Parties all such information as may reasonably be required to comply with such Operating Agreement, manuals, standards, or guidelines and shall operate, or cause to be operated, their respective assets in accordance with such Operating Agreement, manuals, standards, or guidelines.

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

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

5.4    Jointly Owned Assets
Operation of Jointly Owned Assets at the electric substations where Interconnection Facilities are located will be under the direction and control of the Party with more than fifty percent (50%) of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said Party shall operate the Jointly Owned Assets in a manner consistent with Good Utility Practice and the provisions of Sections 5.2 and 5.3 above, as appropriate. Each Party’s respective share of responsibility for the costs of operation of Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum’s. The respective ownership of substation facilities is shown in the Wiring Diagrams for each of the electrical substations at which Consumers’ Generation Resources are connected to the Transmission System (see Exhibit B), reflecting ownership changes through July 24, 2008. The Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties. For current ownership (reflecting ownership changes since July 24, 2008), see the WDs in the




DMS. For purposes of this Agreement, major equipment is defined as (a) main power transformers, (b) 23 kV, 46 kV, 138 kV and 345 kV circuit breakers, (c) power system regulators and reclosers and (d) 46 kV and 138 kV capacitor banks (any three-phase installation of such equipment shall count as one unit of equipment). Exhibit B shall be updated with an addendum at least annually by the Transmission Owner, and approved in writing by all Parties at least annually, to show all changes in equipment and the effects of such changes on the determination of Jointly Owned Asset percentages. For purposes of this Section 5.4, such submission and approval of changes shall be in writing consistent with Section 21.1. In the case where each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume the responsibility for direction and control of the operation activities as such location. In those substations where each Party hereto owns assets, each Party shall be responsible for its appropriate share, as set forth in Exhibit B hereto, of station power energy usage and expense.

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

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

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

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

5.9    System Security
During an Emergency on the Transmission System or on an adjacent transmission system, the System Operator has the authority to direct Consumers to increase or decrease real power production (measured in MW) and/or reactive power production (measured in MVAR), within the design and operational limitations of any of Consumers’ Generation Resources in service at the time, in order to maintain security on the Transmission System. In the event of such a declaration of an Emergency, determinations: (a) that the Transmission System security is in jeopardy, and/or (b) that there is a need to increase or decrease reactive power production, even if real power production is adversely affected, will be made solely by the System Operator or his designated representative. Each Unit operator will honor System Operator's orders and directives concerning said Unit’s real power and/or reactive power output within design and operational limitations of the Unit's equipment in service at the time, such that the security of the Transmission System is maintained. Transmission Provider and Transmission Owner shall restore the Transmission System conditions to normal to alleviate any such Emergency, in accordance with Good Utility Practice. Consumers will be compensated by Transmission Provider or Transmission Owner for increasing or decreasing the real power output of any of its Units as directed by the System Operator to support the Transmission System during an Emergency by the payment of (a) Consumers’ Incremental Cost associated with such increase or decrease in real power output or (b) at such other rate




filed by a Party and approved by the Commission including any existing tariff or rate schedule which has been filed by the Transmission Provider, Transmission Owner or Consumers. Similarly, if the Transmission Provider or Transmission Owner requests any of Consumers’ Units to provide or absorb reactive power that would be outside of the Unit’s Reactive Design Limitations, requiring the Unit’s real power output to be reduced to obtain the desired reactive power, the Transmission Provider or Transmission Owner shall compensate Consumers at the real power rate discussed in the preceding sentence, to the extent that the Unit had to reduce real power output to operate within its Reactive Design Limitations, unless otherwise provided in another agreement or tariff on file with the Commission.

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

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

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

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

5.11.3    Inspection. Subject to the confidentiality provisions set forth in Article 17, Transmission Provider and Transmission Owner shall have the right, but shall have no obligation or responsibility to (a) observe Consumers’ tests and/or inspection of any of Consumers’ protective assets directly connected to




the Transmission System or interfacing with Transmission Owner’s protective assets, (b) review the settings of any of Consumers’ protective assets; and (c) review Consumers’ maintenance records relative to Consumers’ protective assets. Transmission Provider and Transmission Owner may exercise the foregoing rights from time to time as deemed necessary by Transmission Provider or Transmission Owner upon reasonable notice to Consumers. However, the exercise or non-exercise by Transmission Provider or Transmission Owner of any of the foregoing rights of observation, review or inspection shall be construed neither as an endorsement or confirmation of any aspect, feature, element, or condition of the Unit or Consumers’ protective assets or the operation thereof, nor as a warranty as to the fitness, safety, desirability, or reliability of same.

5.12    Outages, Interruptions, and Disconnection

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

5.12.2    Outage Restoration.

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

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

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

5.12.4    Disconnection.





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

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

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

5.12.5    Continuity of Service. Notwithstanding any other provision of this Agreement, Transmission Provider shall not be obligated to accept, and Transmission Provider may require Consumers to curtail, interrupt or reduce deliveries of energy if such delivery of energy impairs Transmission Provider’s or Transmission Owner’s ability to construct, install, repair, replace or remove any of its equipment or any part to its system or if Transmission Provider or Transmission Owner determines that curtailment, interruption or reduction is necessary because of Emergencies, forced outages, operating conditions on its system, or any reason otherwise permitted by applicable rules or regulations promulgated by a regulatory agency having jurisdiction over such matters. The Parties shall coordinate, and if necessary negotiate in good faith, the timing of such curtailments, interruptions, reductions or deliveries with respect to maintenance, investigation or inspection of Transmission Owner’s assets or system. Consumers reserves all rights under the Federal Power Act and applicable other federal and state laws and regulations to commence a complaint proceeding or other action with the Commission or other Governmental Authority with appropriate jurisdiction over the Parties to enforce the provisions of this Subsection 5.12.5.

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





5.13    Operating Expenses

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


ARTICLE 6
MAINTENANCE

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

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

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

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




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

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

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

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

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

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

6.10    Observation of Deficiencies
If a Party observes any deficiencies or defects on, or becomes aware of a lack of scheduled maintenance and testing with respect to, the other Party's assets that might reasonably be expected to adversely affect the observing Party's assets, the observing Party shall either (a) provide notice to the other Party that is prompt under the circumstance or (b) deem such observation an Emergency to life or property and immediately disconnect the Unit pursuant to Subsection 5.12.4.2 of this Agreement, and the other Party shall make any corrections required in accordance with Good Utility Practice.
ARTICLE 7
EMERGENCIES

7.1    Obligations





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

7.2    Notice

Transmission Provider or Transmission Owner shall provide Consumers with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect Consumers’ operation of any or all of its Generation Resources, to the extent Transmission Provider or Transmission Owner is aware of the Emergency. Consumers shall provide Transmission Provider and Transmission Owner with oral notification that is prompt under the circumstances of an Emergency that may reasonably be expected to affect the Transmission System, to the extent Consumers is aware of the Emergency. In lieu of oral notification described in the preceding two sentences, the Parties may agree in advance to use other electronic notification means. To the extent the Party becoming aware of an Emergency is aware of the facts of the Emergency, such notification shall describe the Emergency, the extent of the damage or deficiency, its anticipated duration, and the corrective action taken and/or to be taken. Any such notification given pursuant to this Section 7.2 shall be followed as soon as practicable with written notice.

7.3    Immediate Action

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

7.4    Transmission Provider’s and Transmission Owner’s Authority

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

7.5    Consumers’ Authority

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

7.6    Audit Rights

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


ARTICLE 8
SAFETY
8.1    General





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

8.2    Environmental Releases

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


ARTICLE 9
METERING

9.1    General

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

9.2    Costs of Administering Metering Assets

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

9.3    Testing of Metering Assets

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




all measurements made by the inaccurate Metering Assets for (a) the actual period during which inaccurate measurements were made, if the period can be determined, or (b) a period equal to one-half of the elapsed time since the last test of the Metering Assets.

9.4    Metering Data

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

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

9.5    Communications

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

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

    
ARTICLE 10
FORCE MAJEURE

10.1    An event of Force Majeure means any act of God, labor disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or assets, any curtailment, order, regulation or restriction imposed by governmental military or lawfully established




civilian authorities, or any other cause beyond a Party's reasonable control. A Force Majeure event does not include an act of negligence or intentional wrongdoing.

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

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

ARTICLE 11
INFORMATION REPORTING

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


ARTICLE 12
PAYMENTS AND BILLING PROCEDURES

12.1    Invoices

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

12.2    Payments

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

Michigan Electric Transmission Company, LLC
P.O. Box 673971
Detroit, MI 48267-3971
Attn: Accounting Department

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





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

Consumers Energy Company
One Energy Plaza
Jackson, Michigan 49201
Attn: Treasurer

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

12.3    Interest Charges

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

12.4    Disputes

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


ARTICLE 13
ASSIGNMENT

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

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





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


ARTICLE 14
INDEMNITY AND INSURANCE

14.1    Indemnity

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

14.2    Insurance

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

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

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

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

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

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

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

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

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





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


ARTICLE 15
LIMITATION ON LIABILITY

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

    

ARTICLE 16
BREACH, CURE AND DEFAULT

16.1    General

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

16.2    Events of Breach

A Breach of this Agreement shall include:

16.2.1    The failure to pay any amount when due;

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

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

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

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

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





16.3    Continued Operation

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

16.4    Cure and Default

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


16.5    Right to Compel Performance

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


ARTICLE 17
CONFIDENTIALITY

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

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

17.1.2    Recipient may disclose the Confidential Information to its affiliates and its affiliates’ respective directors, officers, employees, consultants, advisors, and agents who need to know the




Confidential Information for the purpose of assisting Recipient with respect to its obligations under this Agreement. Recipient shall inform all such parties, in advance, of the confidential nature of the Confidential Information. Recipient shall cause such parties to comply with the requirements of this Agreement and shall be responsible for the actions, uses, and disclosures of all such parties.

17.1.3    If Recipient becomes legally compelled or required to disclose any of the Confidential Information (including, without limitation, pursuant to the policies, methods, and procedures of the FERC, including the OASIS Standards of Conduct, or other Regulatory Authority), Recipient will provide the Disclosing Party with prompt written notice thereof so that the Disclosing Party may seek a protective order or other appropriate remedy. Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required, and Recipient will cooperate, at the Disclosing Party’s expense, with the Disclosing Party’s counsel to enable the Disclosing Party to obtain a protective order or other reliable assurance that confidential treatment will be accorded the Confidential Information. It is further agreed that, if, in the absence of a protective order, Recipient is nonetheless required to disclose any Confidential Information, Recipient will furnish only that portion of the Confidential Information which its counsel considers legally required.


ARTICLE 18
AUDIT RIGHTS

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

ARTICLE 19
DISPUTES

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

ARTICLE 20
NOTICES

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

To Transmission Owner:
Michigan Electric Transmission Company, LLC
27175 Energy Way
Novi, MI 48377
Attn: Legal Department - Contracts

To Consumers:
Consumers Energy Company




1945 W. Parnall Road
Jackson, Michigan 49201
Attn: Director of Staff - Energy Resources Business Services

To Transmission Provider:
Midcontinent Independent System Operator, Inc.
Attn: Manager, Interconnection Planning
701 City Center Drive
Carmel, IN 46032
20.2    The Parties shall use standard telephone circuits as the primary communication link for generation dispatch communications, including with respect to dispatching energy in the event of an Emergency and declaring unit capability. The Parties shall provide the names and telephone numbers of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing of names and telephone numbers up to date.


ARTICLE 21
MISCELLANEOUS

21.1    Amendments

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

21.2    Binding Effect

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

21.3    Counterparts

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

21.4    Entire Agreement

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





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

21.6    Headings Not To Affect Meaning

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

21.7    Waivers

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

21.8    Termination of Predecessor Interconnection Agreement

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

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


MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC, a Michigan limited liability company
By: ITC Holdings Corp., its manager

By:    /s/ Linda H. Blair                        

Title:    Executive Vice President & Chief Business Officer        



CONSUMERS ENERGY COMPANY

By:        /s/ David B. Kehoe                    

Title:    Director of Staff - Energy Resources Business Services    



MIDCONTINENT INDEPENDENT SYSTEM OPERATOR, INC.

By:    /s/ Jennifer Curran                        

Title:    Vice President, System Planning & Seams Coordination    

EXHIBIT A - CONSUMERS GENERATION RESOURCES




 
 
Summer
Winter
 
 
 
 
 
 
 
 
 
Nameplate
Net
Net
 
 
 
 
AGC
Black
 
 
 
Rated
Demonstrated
Demonstrated
 
 
 
AGC
Ramp
Start
Synch
 
Generating Unit
MVA (1)
MW Capability
MW Capability
Kilovolts
RPM
Cooling
Capable
MW/Min
Capable
Breaker(s)
Comments
Campbell 1
          312.0
                 260.0
                  260.0
       16.0
      3,600
Hydrogen
Yes
3
No
199
 
Campbell 2
          492.0
                 355.0
                  360.0
       20.0
      3,600
Water/Hydrogen
Yes
3
No
299
 
Campbell A
           21.9
                  13.0
                    17.0
       13.8
      3,600
Air
No
0
No
C16
 Returned to Service in February of 2015.
Cobb 4
          184.0
                 158.0
                  160.0
       18.0
      3,600
Hydrogen
Yes
1
No
499
 Tentatively retiring April 2016
Cobb 5
          184.0
                 158.0
                  160.0
       18.0
      3,600
Hydrogen
Yes
1
No
599
 Tentatively retiring April 2016
Gaylord 1
           18.8
                  14.0
                    17.0
       13.8
      3,600
Air
No
0
No
116
 Mothballed until February 2016.
Gaylord 2
           18.8
                  14.0
                    17.0
       13.8
      3,600
Air
No
0
No
216
 Mothballed until February 2016.
Gaylord 3
           18.8
                  14.0
                    17.0
       13.8
      3,600
Air
No
0
No
316
 Mothballed until February 2016.
Karn 1
          336.0
                 255.0
                  255.0
       16.0
      3,600
Hydrogen
Yes
3
No
199
 
Karn 2
          320.0
                 260.0
                  260.0
       16.0
      3,600
Hydrogen
Yes
3
No
299
 
Karn 3
          814.7
                 638.0
                  638.0
       26.0
      3,600
Water/Hydrogen
Yes
6
No
28R8/28H9
 AGC Ramp Rate: 6 is avg. 9 Mw/min 60 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Karn 4
          835.0
                 638.0
                  638.0
       26.0
      3,600
Water/Hydrogen
Yes
6
No
32F7/32H9
 AGC Ramp Rate: 6 is avg. 9 Mw/min 70 thr. 500 Mw, 3 Mw/min 500 thr. 580 Mw
Straits 1
           25.0
                    5.0
                    10.0
       13.8
      3,600
Air
No
0
No
S16
 Mothballed until February 2016.
 
 
 
 
 
 
 
 
 
 
 
 
Thetford 2
           39.5
                  29.0
                    37.0
       13.8
      3,600
Air
No
0
No
216
 Blackstart Resource until September 2015.
Thetford 3
           39.5
                  30.0
                    37.0
       13.8
      3,600
Air
No
0
Yes
316
 Blackstart Resource until May 2015.
Thetford 4
           39.5
                  30.0
                    37.0
       13.8
      3,600
Air
No
0
Yes
416
 Blackstart Resource until May 2015.
Weadock 7
          202.0
                 155.0
                  155.0
       18.0
      3,600
Hydrogen
Yes
1
No
799
 Tentatively retiring April 2016
Weadock 8
          184.0
                 155.0
                  155.0
       18.0
      3,600
Hydrogen
Yes
1
No
899
 Tentatively retiring April 2016
 
 
 
 
 
 
 
 
 
 
 
 
Whiting 1
          125.0
                 102.0
                  102.0
       14.4
      3,600
Hydrogen
Yes
1
No
199
 Tentatively retiring April 2016
Whiting 2
          125.0
                 102.0
                  102.0
       14.4
      3,600
Hydrogen
Yes
1
No
299
 Tentatively retiring April 2016
Whiting 3
          156.3
                 122.0
                  124.0
       15.5
      3,600
Hydrogen
Yes
1
No
399
 Tentatively retiring April 2016
 
 
 
 
 
 
 
 
 
 
 
 
Alcona Hydro 1
             4.4
                    4.0
                     4.0
         5.0
           90
 Air
 NA
 NA
 No
 116/166
 
Alcona Hydro 2
             4.4
                    4.0
                     4.0
         5.0
           90
 Air
 NA
 NA
 No
 216/166
 
Calkins Bridge Hydro 1
             0.6
                    0.4
                     0.4
         4.8
         180
 Air
 NA
 NA
 No
 116/166
 Also known as Allegan Hydro
Calkins Bridge Hydro 2
             1.1
                    0.9
                     0.9
         4.8
         120
 Air
 NA
 NA
 No
 216/166
 Also known as Allegan Hydro
Calkins Bridge Hydro 3
             1.5
                    1.2
                     1.2
         4.8
         113
 Air
 NA
 NA
 No
 316/166
 Also known as Allegan Hydro
Cooke Hydro 1
             3.3
                    1.5
                     1.5
         2.5
         180
 Air
 NA
 NA
 No
 116/166
 
Cooke Hydro 2
             3.3
                    3.0
                     3.0
         2.5
         180
 Air
 NA
 NA
 No
 216/166
 
Cooke Hydro 3
             3.3
                    3.0
                     3.0
         2.5
         180
 Air
 NA
 NA
 No
 316/166
 
Croton Hydro 1
             3.8
                    2.9
                     2.9
         7.2
         225
 Air
 NA
 NA
 No
 116/246
 
Croton Hydro 2
             3.8
                    2.9
                     2.9
         7.2
         225
 Air
 NA
 NA
 No
 216/246
 
Croton Hydro 3
             1.4
                    1.3
                     1.3
         7.2
         150
 Air
 NA
 NA
No
 316/246
 
Croton Hydro 4
             1.6
                    1.3
                     1.3
         7.2
         150
 Air
 NA
 NA
 No
 416/246
 
Five Channels 1
             3.3
                    3.2
                     3.2
         2.5
         150
 Air
 NA
 NA
 No
 116/166
 
Five Channels 2
             3.3
                    3.2
                     3.2
         2.5
         150
 Air
 NA
 NA
 No
 216/166
 
Foote Hydro 1
             3.3
                    3.3
                     3.3
         5.0
           90
 Air
 NA
 NA
 No
 116/366
 




Foote Hydro 2
             3.3
                    3.3
                     3.3
         5.0
           90
 Air
 NA
 NA
 No
 216/366
 
Foote Hydro 3
             3.3
                    3.3
                     3.3
         5.0
           90
 Air
 NA
 NA
 No
 316/366
 
Hodenpyl Hydro 1
             8.9
                    9.2
                     9.2
         7.5
         120
 Air
 NA
 NA
 No
 116/266
 
Hodenpyl Hydro 2
             8.9
                    9.2
                     9.2
         7.5
         120
 Air
 NA
 NA
No
 216/266
 
Loud Hydro 1
             2.2
                    2.2
                     2.2
         2.5
         120
 Air
 NA
 NA
 No
 116/266
 
Loud Hydro 2
             2.2
                    2.2
                     2.2
         2.5
         120
 Air
 NA
 NA
 No
 216/266
 
Mio Hydro 1
             2.7
                    2.2
                     2.2
         2.5
           80
 Air
 NA
 NA
 No
 116/166
 
Mio Hydro 2
             2.7
                    2.2
                     2.2
         2.5
           80
 Air
 NA
 NA
No
 216/166
 
Rogers Hydro 1
             1.9
                    1.5
                     1.5
         7.5
         150
 Air
 NA
 NA
 No
 116/166
 
Rogers Hydro 2
             1.9
                    1.5
                     1.5
         7.5
         150
 Air
 NA
 NA
 No
 216/166
 
Rogers Hydro 3
             1.9
                    1.5
                     1.5
         7.5
         150
 Air
 NA
 NA
 No
 316/166
 
Rogers Hydro 4
             1.9
                    1.5
                     1.5
         7.5
         150
 Air
 NA
 NA
 No
 416/166
 
Tippy Hydro 1
             7.1
                    7.0
                     7.0
         7.5
         109
 Air
 NA
 NA
 No
 116/266/126
 
Tippy Hydro 2
             7.1
                    7.0
                     7.0
         7.5
         109
 Air
 NA
 NA
 No
 216/266/126
 
Tippy Hydro 3
             7.1
                    7.0
                     7.0
         7.5
         109
 Air
 NA
 NA
 No
 316/266/126
 
Webber Hydro 1
             3.3
                    2.3
                     2.3
         7.2
         164
 Air
 NA
 NA
 No
 116/166
 
Webber Hydro 2
             1.3
                    1.0
                     1.0
         2.5
         200
 Air
 NA
 NA
 No
 216
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes:
(1) Rated MVA represents generator machine capability limits. Turbine or main transformer limits may be more restrictive.
 
 
 
 
 
 
 
 
 
 
 
 
EXHIBIT B - INTERCONNECTION ASSETS

General

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

Foundations
All foundations not identified as belonging to a specific piece of assets in the Plant Accounting Records.
Structures
All steel support structures.
Station wiring
All buswork, control cables, batteries, battery chargers and ground grids.
Fencing
All chain-link fencing surrounding or used within the specific electrical Substation.
Control house
Any building located within the Substation used to house relaying, controls or telemetry equipment beneficial to and used by both Parties.
Stone
All stone used in the Substation yards, driveways and drains.





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

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

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

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

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





Exhibit B - Table 1
Jointly Owned Asset Ownership by Percent of Major Equipment
Addendum 5 - Final 09/08/15

Substations
Jointly Owned Assets
Percentage Split by Major Equipment Count
(Substations with 100% ownership by Major Equipment Count Not Included)


Substation Name
Distribution
Transmission
Generation Owned by Local Distribution Company
Third-Party Assets
Last Revision Date
Campbell 138 kV 1
0.00
64.28
35.24
0.48
08/16/12
Cobb Plant
47.22
25.00
27.78
 
04/29/02
Gaylord
44.44
44.44
11.12
 
01/01/10
Karn Plant
0.00
63.64
36.36
 
01/01/10
Morrow 
63.33
30.00
6.67
 
08/16/12
Thetford
0.00
92.00
8.00
 
04/29/02
Weadock
35.14
24.32
40.54
 
01/01/10
Whiting
28.57
28.57
42.86
 
08/16/12



















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

Changes, relative to previous revisions (addendums), are shown in bold type.
Major equipment is defined in Section 5.4 of the GIA.Generator Connections located at Substations in the Transmission System

Campbell 1&2 Plant


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

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

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

Consumers’ Interconnection Assets

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

Transformer Bank    No. A (located outside of substation; not included in JOA calc)
Circuit Breakers
Nos. 199, 299, 799, 899*, 999 and 16A (16A is rated < 23kV and not considered major equipment per GIA definition).
Switches
Nos. 99A, 195, 196, 295, 296, 709, 793, 795, 796, 809*, 893*, 895*, 896*, 909, 993, 995 and 996

Circuit Connections
All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations        All foundations supporting the Circuit Breakers identified above

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


Transmission Owner Interconnection Assets





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

Transformer Bank    No. 5
Circuit Breakers    Nos. 148, 188, 288, 388, 488, 500, 566 and 588
Switches
Nos. 108, 144, 145, 146, 184, 185, 186, 208, 284, 285, 286, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 509, 545, 546, 564, 584, 585, 586, 1020 and 1121
Circuit Connections
All wire, cable or bus work electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer bus work
Relay and Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Circuit Breakers identified above


Jointly Owned Assets - Percentage Split by Major Equipment Count

Campbell 138 kV Substation - See Exhibit B - Table 1













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Cobb Generating Plant Complex

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

The Connection Points for Units 1 through 5 are in the BC Cobb Plant Substation (see Wiring Diagram #240, Sheet 31 attached).

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

Consumers’ Interconnection Assets

Consumers owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240, Sheet 31):

Transformer Banks    Nos. 1, 2, 3, 4, 5, 7 and 8




Capacitor Banks     Nos. 1 and 2
Circuit Breakers
Nos. 100, 188, 199, 288, 299, 399, 499, 599, 766, 799, 866, 899, 1177, 1188, 1288, 1388, 1488 and 1688
Switches
Nos. 102, 104, 152, 156, 184, 185, 186, 193, 195, 196, 200, 252, 256, 284, 285, 286, 293, 295, 296, 393, 395, 396, 493, 495, 496, 593, 595, and 596, 709, 762, 764, 765, 793, 795, 796, 809, 862, 864, 865, 893, 895, 896, 1171, 1173, 1175, 1182, 1184, 1185, 1282, 1284, 1285, 1323, 1382, 1384, 1385, 1482, 1484, 1485, 1588, 1682, 1684, 1685, 1788, 1888, 2333, 7732-1, 7736-1, 8826-2, 8832-2 and 8836-2
Circuit Connections
All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main buswork.
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformers and Circuit Breakers identified above
Auxiliary Power
All 2400 Volt station power assets shown in the attached Wiring Diagram #240

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240, Sheet 31):

Circuit Breakers
Nos. 148, 377, 488, 500, 588, 688, 788, 888 and 988
Switches
Nos. 144, 145, 146, 307, 373, 375, 376, 408, 484, 485, 486, 505, 506, 508, 584, 585, 586, 608, 684, 685, 686, 708, 784, 785, 786, 808, 884, 885, 886, 908, 984, 985, 986, 1020, 1121, 2030 and 2131
Circuit Connections
All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main buswork.
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Circuit Breakers identified above


Jointly Owned Assets - Percentage Split by Major Equipment Count

Cobb Plant Substation -See Exhibit B - Table 1














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Gaylord Generating Plant Complex

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

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

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

Consumers’ Interconnection Assets

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

Transformer Banks    Nos. 1, 2* and 3* (*located outside of substation; not included in JOA calc)
Circuit Breakers
Nos. A16*, 116*, 146, 166, 199, 216*, 316*, 416* and 1288 (*located outside of substation; not included in JOA calc)
Switches
Nos. 3,142, 144, 145, 162, 164, 165, 191, 193, 195, 299, 399, 1282 and 1284
Circuit Connections
All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformers and Circuit Breakers identified above
Auxiliary Power
All station power assets shown in the attached Wiring Diagram #495, Sheet 31

Transmission Owner Interconnection Assets

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

Capacitor Bank
No. 3
Circuit Breakers
Nos. 356, 377 and 477
Switches
Nos. 352, 371, 373, 382, 384, 471and 473
Circuit Connections
All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Circuit Breakers identified above
Jointly Owned Assets - Percentage Split by Major Equipment Count

Gaylord Generating Substation - See Exhibit B - Table 1











CEII MATERIAL











Karn Generating Plant Complex

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

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

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

Consumers’ Interconnection Assets

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

Transformer Banks
Nos. 1 and 2 (located outside the substation; not included in JOA calc)
Circuit Breakers    Nos. 199, 299, 799 and 899
Switches
Nos. 136A, 136B, 195, 196, 236A, 236B, 295, 296, 793, 795, 796, 893, 895, and 896
Circuit Connections
All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations        All foundations supporting the Circuit Breakers identified above
Auxiliary Power
All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #695, Sheet 31

Transmission Owner’s Interconnection Assets

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

Circuit Breakers    Nos. 148, 188, 388, 488, 500, 588 and 988
Switches
Nos. 108, 144, 145, 146, 184, 185, 186, 308, 384, 385, 386, 408, 484, 485, 486, 505, 506, 508, 584, 585, 586, 709, 809, 908, 984, 985, 986, 2030 and 2131
Circuit Connections
All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to adjacent buswork
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations        All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count
Karn Plant Substation - See Exhibit B - Table 1














CEII MATERIAL



















CEII MATERIAL







Morrow Generating Plant Complex

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

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

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

Consumers’ Interconnection Assets

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

Transformer Banks
No. 1, 2, 4 and 5
Circuit Breakers
Nos. 100, 156, 166, 199, 256, 266, 299, 566, 499, 16A,16B, 599, 1077, 1188, 1388, 1488, 1588, 1688 and 1788
Switches
Nos. 102, 104, 109, 162, 164, 165, 191, 193, 195, 196, 209, 252, 262, 264, 265, 291, 293, 295, 296, 300, 509, 562, 564, 565, 591, 593, 595, 596, 1071, 1073, 1075, 1182, 1184, 1185, 1323, 1382, 1384, 1385, 1482, 1484, 1485, 1582, 1584, 1585, 1682, 1684, 1685, 1782, 1784, 1785 and 2333
Capacitors        Nos. 1 and 2
Circuit Connections
All wire, cable or buswork electrically connecting the Transformers, Circuit Breakers and Switches identified above




Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformers and Circuit Breakers identified above
Auxiliary Power
All 480 Volt station power assets shown in the attached Wiring Diagram #190, Sheet 31

Transmission Owner Interconnection Assets

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

Circuit Breakers    Nos. 177, 288, 377, 388, 500, 588, 677, 888 and 988
Switches
Nos. 107, 171, 173, 175, 176, 208, 282, 284, 285, 286, 307, 308, 371, 373, 375, 376, 382, 384, 385, 386, 501, 502, 503, 504, 505, 506, 508, 582, 584, 585, 586, 607, 671, 673, 675, 676, 882, 884, 885, 886, 982, 984, 985 and 986
Circuit Connections
All wire, cable or buswork electrically connecting the Circuit Breakers and Switches identified above
Relay and Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Circuit Breakers identified above

Third Party Owned Assets

None


Jointly Owned Assets - Percentage Split by Major Equipment Count

Morrow Substation - See Exhibit B - Table 1











CEII MATERIAL







Thetford Generating Plant Complex

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

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

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





Consumers’ Interconnection Assets

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

Transformer Banks
Nos. 5, 6-1, 6-2 and 7
Circuit Breakers    Nos. 13B7, 13W8, 116, 216, 316, 416, 516, 616, 716, 816 and 916
Switches        Nos. 13B1, 13B3, 13M5, 13W2, 13W4, 591, 691-1, 691-2 and 791
Circuit Connections
All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformers and Circuit Breakers identified above

Transmission Owner Interconnection Assets

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

Transformer Banks
Nos. 3 and 4
Circuit Breakers
Nos. 6B7, 6M9, 6W8, 7B7, 7M9, 7W8, 9B7, 9M9, 9W8, 11B7, 11M9, 11W8, 27F7, 27H9, 27R8, 31F7, 31H9, 31R8, 33F7, 33H9 and 33R8
Switches
Nos. 6B1, 6B3, 6M5, 6M6, 6W2, 6W4, 7B1, 7B3, 7M5, 7M6, 7W2, 7W4, 9B1, 9B3, 9M5, 9M6, 9W2, 9W4, 11B1, 11B3, 11M5, 11M6, 11W2, 399, 499, 11W4, 27F1, 27F3, 27H5, 27H6, 27R2, 27R4, 31F1, 31F3, 31H5, 31H6, 31R2, 31R4, 33F1, 33F3, 33H5, 33H6, 33R2, 33R4 and 35R2
Circuit Connections
All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above
Relay and Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformers and Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Thetford Substation - See Exhibit B - Table 1










CEII MATERIAL







Weadock Generating Plant Complex

The Weadock Generating Plant Complex consists of three generating Units, known as Units 7, 8 and A.





The Connection Points for Units 7, 8 and A1 are in the John C Weadock Substation (see Wiring Diagram #195, Sheet 31 attached). These Units are currently in service. In addition, there are six other units, known as Units 1 through 6, which have been retired from service, but are still in place. Those assets are also described below, should the Units be restored to service in the future.

The Points of Receipt for all the Units currently in service at the Weadock Generating Plant Complex are deemed to be the respective Connection Points.

Consumers’ Interconnection Assets (for Units In Service)

Consumers owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheets 2 and 31):

Transformer Banks
Nos. 1, 2, 7, 8, 9 and 10
Circuit Breakers
Nos. 66A, 100, 136, 166, 199, 236, 266, 299, 300, 736C, 799, 899, 966, 999, 1066, 1088, 1099, 1188, 1288 and 1388
Switches
Nos. 62A, 64A, 102, 104, 105, 106, 132, 134, 135, 152, 156, 162, 164, 165, 195, 196, 200, 232, 234, 235, 252, 256, 262, 264, 265, 295, 296, 302, 304, 306, 400, 732C, 734C, 735C, 736A, 736B, 795, 796, 836A, 836B, 895, 896, 962, 964, 965, 991, 993, 995, 996, 1062, 1064, 1065, 1082, 1084, 1085, 1091, 1093, 1095, 1096, 1182, 1184, 1185, 1282, 1284, 1285, 1382, 1384 and 1385
Capacitors        1 and 2
Circuit Connections
All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork.
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformer Banks and Circuit Breakers identified above
Auxiliary Power
All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #195, Sheet 31

Consumers’ Interconnection Assets (for Units Retired in Place)

Consumers owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheet 31):

Transformer Banks    Nos. 5 and 6
Circuit Breakers    Nos. 99A, 116, 216, 316, 336, 416 and 436
Switches
Nos. 93A, 112, 114, 212, 214, 312, 314, 332, 412, 414, 432, 516, 536 and 616
Circuit Connections
All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork.
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformer Banks and Circuit Breakers identified above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the John C Weadock Substation (Wiring Diagram #195, Sheet 31):

Circuit Breakers    Nos. 148, 188, 288, 388, 488, 500, 588, 688 and 788
Switches
Nos. 108, 142, 144, 145, 146, 182, 184, 185, 186, 208, 282, 284, 285, 286, 308, 382, 284, 385, 386, 408, 482, 484, 485, 486, 505, 506, 508, 582, 584, 585, 586, 608, 682, 684, 685, 686, 708, 782, 784, 785, 786, 900, 1020,1121, 2030, 2131, 3040, 3141, 4050 and 4151




Circuit Connections
All wire, cable or buswork electrically connecting the Switches identified above to the Circuit Breakers identified above and to the main buswork
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Circuit Breakers identified above
  

Jointly Owned Assets - Percentage Split by Major Equipment Count

John C Weadock Substation - See Exhibit B - Table 1











CEII MATERIAL








Whiting Generating Plant Complex

The Whiting Generating Plant Complex consists of four generating Units, known as Units 1, 2, 3 and A.

The Connection Points for Units 1, 2, 3 and A are in the Whiting Substation (see Wiring Diagram #400, Sheet 31attached). Units 1, 2 and 3 are connected to the 138 kV buswork and Unit A is connected to the 46 kV buswork

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

Consumers’ Interconnection Assets

Consumers owns the following assets at the Whiting Substation (Wiring Diagram #400, Sheet 31):

Transformer Banks
Nos. 1, 2, 3, 5, 7 and A (TB # A located outside of substation; not included in JOA calc)
Circuit Breakers
Nos. 16A (located outside switchyard; not included in JOA calc), 46A, 199, 299, 399, 599, 766, 799, 1188 and 1288
Switches
Nos. 42A, 44A, 45A, 99A, 105, 156, 191, 193, 195, 196, 291, 293, 295, 296, 391, 393, 395, 396, 591, 593, 79T1, 762, 764, 765, 795, 796, 1182, 1184, 1185, 1282, 1284, 1285
Capacitor Bank
No 1
Circuit Connections
All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above to each other, as appropriate, to the main buswork and to the Auxiliary Power assets




Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformer Banks and Circuit Breakers identified above
Auxiliary Power
All 480 Volt and 2400 Volt station power assets shown in the attached Wiring Diagram #400, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Whiting Substation (Wiring Diagram #400, Sheet 31):

Transformer Bank     No. 8
Circuit Breakers    Nos. 500, 688, 788,899 and 988
Switches
Nos. 501, 502, 503, 504, 505, 506, 608, 682, 684, 685, 686, 785, 786, 866, 895, 896, 908, 982, 984, 985 and 986
Circuit Connections
All wire, cable or buswork electrically connecting the Transformer Banks, Circuit Breakers and Switches identified above to each other, as appropriate, to the main buswork
Relay & Controls
All relays and controls associated with the Circuit Breakers identified above
Foundations
All foundations supporting the Transformer Bank and Circuit Breakers identified above

Jointly Owned Assets - Percentage Split by Major Equipment Count

Whiting Substation - See Exhibit B - Table 1











CEII MATERIAL







EXHIBIT C

Generator Connections located in Consumers’ Distribution System

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

Alcona Hydro Generating Plant, Units 1 and 2
Calkins Bridge “Allegan” Hydro Generating Plant, Units 1, 2 and 3
Cooke Hydro Generating Plant, Units 1. 2 and 3
Croton Hydro Generating Plant, Units 1, 2, 3 and 4




Five Channels Generating Plant, Units 1 and 2
Foote Hydro Generating Plant, Units 1, 2 and 3
Hodenpyl Hydro Generating Plant, Units 1 and 2
Loud Hydro Generating Plant, Units 1 and 2
Mio Hydro Generating Plant, Units 1 and 2
Rogers Hydro Generating Plant, Units 1, 2, 3 and 4
Straits Combustion Turbine Generating Unit 1
Tippy Hydro Generating Plant, Units 1, 2 and 3
Webber Hydro Generating Plant, Units 1 and 2





Consumers Energy Generator Connections Covered under Other Interconnection Agreements

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

Campbell Generating Plant, Unit 3.

Hardy Hydro Generating Plant, Units 1, 2 and 3.

Zeeland Power Plant

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








EXHIBIT 31.1
CERTIFICATION PURSUANT TO SECTION 13a-14 OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Joseph L. Welch, certify that:
1.
I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2015 of ITC Holdings Corp.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Dated: November 5, 2015

/s/ Joseph L. Welch
 
Joseph L. Welch
President and Chief Executive Officer







EXHIBIT 31.2
CERTIFICATION PURSUANT TO SECTION 13a-14 OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Rejji P. Hayes, certify that:
1.
I have reviewed this report on Form 10-Q for the quarterly period ended September 30, 2015 of ITC Holdings Corp.;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b.
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Dated: November 5, 2015

/s/ Rejji P. Hayes
 
Rejji P. Hayes
Senior Vice President, Chief Financial Officer and Treasurer








EXHIBIT 32
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of ITC Holdings Corp. (the “Registrant”) on Form 10-Q for the quarterly period ended September 30, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Joseph L. Welch, President and Chief Executive Officer of the Registrant, and Rejji P. Hayes, Senior Vice President, Chief Financial Officer and Treasurer of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Dated: November 5, 2015

/s/ Joseph L. Welch
 
Joseph L. Welch
President and Chief Executive Officer
 
/s/ Rejji P. Hayes
 
 
Rejji P. Hayes
Senior Vice President, Chief Financial Officer and Treasurer



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