UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended March 31, 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 April 24, 2015 was 155,210,615.
 


ITC Holdings Corp.
Form 10-Q for the Quarterly Period Ended March 31, 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)

March 31,

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

2014
ASSETS
 


Current assets
 

 
Cash and cash equivalents
$
9,114


$
27,741

Accounts receivable
102,760


100,998

Inventory
30,964


30,892

Deferred income taxes
18,085


14,511

Regulatory assets
7,183


5,393

Prepaid and other current assets
17,201


7,281

Total current assets
185,307


186,816

Property, plant and equipment (net of accumulated depreciation and amortization of $1,414,073 and $1,388,217, respectively)
5,634,544


5,496,875

Other assets
 

 
Goodwill
950,163


950,163

Intangible assets (net of accumulated amortization of $25,748 and $24,917, respectively)
47,971


48,794

Regulatory assets
231,847


223,712

Deferred financing fees (net of accumulated amortization of $14,535 and $15,972, respectively)
31,516


30,311

Other
42,314


37,418

Total other assets
1,303,811


1,290,398

TOTAL ASSETS
$
7,123,662


$
6,974,089

LIABILITIES AND STOCKHOLDERS’ EQUITY
 

 
Current liabilities
 

 
Accounts payable
$
95,149


$
107,969

Accrued payroll
11,959


23,502

Accrued interest
37,366


50,538

Accrued taxes
30,473


41,614

Regulatory liabilities
38,523


39,972

Refundable deposits from generators for transmission network upgrades
3,104


10,376

Debt maturing within one year
175,000


175,000

Other
4,383


14,043

Total current liabilities
395,957


463,014

Accrued pension and postretirement liabilities
71,876


69,562

Deferred income taxes
690,789


656,562

Regulatory liabilities
166,712


160,070

Refundable deposits from generators for transmission network upgrades
7,622


9,384

Other
19,104


17,354

Long-term debt
4,056,131


3,928,586

Commitments and contingent liabilities (Note 10)





STOCKHOLDERS’ EQUITY
 

 
Common stock, without par value, 300,000,000 shares authorized, 155,197,816 and 155,140,967 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively
927,814


923,191

Retained earnings
783,462


741,550

Accumulated other comprehensive income
4,195


4,816

Total stockholders’ equity
1,715,471


1,669,557

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
7,123,662


$
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
 
March 31,
(in thousands, except per share data)
2015
 
2014
OPERATING REVENUES
$
272,487

 
$
258,603

OPERATING EXPENSES
 
 
 
Operation and maintenance
25,562

 
24,861

General and administrative
40,894

 
27,962

Depreciation and amortization
34,435

 
31,378

Taxes other than income taxes
22,380

 
21,193

Other operating (income) and expenses — net
(236
)
 
(232
)
Total operating expenses
123,035

 
105,162

OPERATING INCOME
149,452

 
153,441

OTHER EXPENSES (INCOME)

 
 
Interest expense — net
48,474

 
45,309

Allowance for equity funds used during construction
(7,549
)
 
(5,012
)
Other income
(253
)
 
(161
)
Other expense
1,188

 
1,333

Total other expenses (income)
41,860

 
41,469

INCOME BEFORE INCOME TAXES
107,592

 
111,972

INCOME TAX PROVISION
40,460

 
42,836

NET INCOME
$
67,132

 
$
69,136

Basic earnings per common share
$
0.43

 
$
0.44

Diluted earnings per common share
$
0.43

 
$
0.43

Dividends declared per common share
$
0.1625

 
$
0.1425

See notes to condensed consolidated financial statements (unaudited).



5

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 
 
Three months ended
 
 
March 31,
(in thousands)
 
2015
 
2014
NET INCOME
 
$
67,132

 
$
69,136

OTHER COMPREHENSIVE INCOME
 
 
 
 
Derivative instruments, net of tax (Note 6)
 
(727
)
 
106

Available-for-sale securities, net of tax (Note 6)
 
106

 
50

TOTAL OTHER COMPREHENSIVE (LOSS) INCOME, NET OF TAX
 
(621
)
 
156

TOTAL COMPREHENSIVE INCOME
 
$
66,511

 
$
69,292

See notes to condensed consolidated financial statements (unaudited).



6

ITC HOLDINGS CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 
Three months ended
 
March 31,
(in thousands)
2015
 
2014
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
67,132

 
$
69,136

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization expense
34,435

 
31,378

Recognition, refund and collection of revenue accruals and deferrals — including accrued interest
(12,484
)
 
(5,139
)
Deferred income tax expense
27,823

 
28,243

Allowance for equity funds used during construction
(7,549
)
 
(5,012
)
Other
6,777

 
3,841

Changes in assets and liabilities, exclusive of changes shown separately:
 
 
 
Accounts receivable
(3,826
)
 
(11,555
)
Inventory
(72
)
 
1,775

Prepaid and other current assets
(9,920
)
 
(4,525
)
Accounts payable
(4,855
)
 
(23,339
)
Accrued payroll
(7,540
)
 
(8,011
)
Accrued interest
(13,172
)
 
(24,079
)
Accrued taxes
(11,140
)
 
(1,653
)
Other current liabilities
(1,676
)
 
(7,299
)
Other non-current assets and liabilities, net
3,000

 
1,954

Net cash provided by operating activities
66,933

 
45,715

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Expenditures for property, plant and equipment
(172,604
)
 
(159,145
)
Other
(5,637
)
 
128

Net cash used in investing activities
(178,241
)
 
(159,017
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Borrowings under revolving credit agreements
349,800

 
488,000

Borrowings under term loan credit agreements
—

 
110,000

Repayments of revolving credit agreements
(222,400
)
 
(464,700
)
Issuance of common stock
1,246

 
2,906

Dividends on common and restricted stock
(25,220
)
 
(22,453
)
Refundable deposits from generators for transmission network upgrades
143

 
4,967

Repayment of refundable deposits from generators for transmission network upgrades
(9,178
)
 
(22,155
)
Other
(1,710
)
 
(3,568
)
Net cash provided by financing activities
92,681

 
92,997

NET DECREASE IN CASH AND CASH EQUIVALENTS
(18,627
)
 
(20,305
)
CASH AND CASH EQUIVALENTS — Beginning of period
27,741

 
34,275

CASH AND CASH EQUIVALENTS — End of period
$
9,114

 
$
13,970

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
 
Three months ended
 
March 31,
(in thousands)
2015
 
2014
Supplementary cash flows information:
 
 
 
Interest paid (net of interest capitalized)
$
61,633

 
$
68,070

Income taxes paid — net
19,817

 
16,101

Supplementary non-cash investing and financing activities:
 
 
 
Additions to property, plant and equipment and other long-lived assets (a)
$
71,219

 
$
96,186

Allowance for equity funds used during construction
7,549

 
5,012

____________________________
(a)
Amounts consist of current liabilities for construction labor and materials that have not been included in investing activities. These amounts have not been paid for as of March 31, 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 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 U.S. 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.


8

Amendments to the Consolidation Analysis
In February 2015, the FASB issued authoritative guidance that amends the variable interest entity consolidation analysis under U.S. GAAP. The new standard was issued to improve targeted areas of consolidation guidance; though the FASB’s 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. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. We do not expect the standard to have a material impact on our consolidated financial statements.
3.    REGULATORY MATTERS
Start-Up, Development and Pre-Construction Regulatory Assets
As of March 31, 2015, we have recorded a total of $14.1 million of regulatory assets for start-up, development and pre-construction expenses, including associated interest carrying charges, incurred by ITC Great Plains, which include certain costs incurred for the Kansas Electric Transmission Authority (“KETA”) Project and the Kansas V-Plan Project prior to construction. ITC Great Plains made a filing with the FERC under Section 205 of the FPA in May 2013 to recover these start-up, development and pre-construction expenses, including associated debt and equity carrying charges, in future rates. On March 26, 2015, FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, effective July 19, 2013, subject to refund, as well as set the matter for hearing and settlement judge procedures. As a result, ITC Great Plains will begin to include the unamortized balance of the regulatory assets in its rate base and commence amortization over a 10-year period. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template, subject to refund. We do not expect the settlement of this proceeding to have a material impact on our results of operations, cash flows or financial condition.
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. On March 20, 2014, 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 on May 19, 2014. On January 22, 2015, the FERC conditionally accepted the May 19, 2014 compliance filing, subject to a further compliance filing, which was made on February 13, 2015. We do not expect the revised formula rate protocols to impact our 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 10 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


9

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 10 for detail on ROE matters including incentive adders recently approved by FERC.
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 three months ended March 31, 2015:
(in thousands)
 
Total
Balance as of December 31, 2014
 
$
(56,103
)
Net refund of 2013 revenue deferrals and accruals, including accrued interest
 
8,789

Net revenue accrual for the three months ended March 31, 2015
 
4,202

Net accrued interest payable for the three months ended March 31, 2015
 
(507
)
Balance as of March 31, 2015
 
$
(43,619
)
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 March 31, 2015 as follows:
(in thousands)
 
Total
Current assets
 
$
7,183

Non-current assets
 
19,897

Current liabilities
 
(38,523
)
Non-current liabilities
 
(32,176
)
Balance as of March 31, 2015
 
$
(43,619
)
4.    GOODWILL AND INTANGIBLE ASSETS
Goodwill
At March 31, 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 $33.5 million and $34.2 million (net of accumulated amortization of $24.9 million and $24.2 million) as of March 31, 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 $14.5 million and $14.6 million (net of accumulated amortization of $0.8 million and $0.7 million) as of March 31, 2015 and December 31, 2014, respectively.


10

During each of the three month periods ended March 31, 2015 and 2014, we recognized $0.8 million of amortization expense of our intangible assets. For each of the next five years, we expect the annual amortization of our intangible assets that have been recorded as of March 31, 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 March 31, 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 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 March 31, 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 March 31, 2015, the fair value of the derivative instruments was an asset of $0.1 million recorded to other non-current assets and a liability of $3.5 million recorded to other non-current liabilities. None of the interest rate swaps contain credit-risk-related contingent features. Refer to Note 9 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.


11

Revolving Credit Agreements
At March 31, 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

 
$
125.1

 
$
274.9

 
1.4%
(c)
 
0.175
%
ITCTransmission
100.0

 
32.8

 
67.2

 
1.1%
(d)
 
0.10
%
METC
100.0

 
3.7

 
96.3

 
1.1%
(d)
 
0.10
%
ITC Midwest
250.0

 
216.4

 
33.6

 
1.1%
(d)
 
0.10
%
ITC Great Plains
150.0

 
62.2

 
87.8

 
1.1%
(d)
 
0.10
%
Total
$
1,000.0

 
$
440.2

 
$
559.8

 
 
 
 
 
____________________________
(a)
Included within long-term debt.
(b)
Calculation based on the average daily unused commitments, subject to adjustment based on the borrower’s credit rating.
(c)
Loan bears interest at a rate equal to LIBOR plus an applicable margin of 1.25% 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.
(d)
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% 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 March 31, 2015, we were not in violation of any debt covenant.
6.     STOCKHOLDERS’ EQUITY
The changes in stockholders’ equity for the three months ended March 31, 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
—

 
—

 
67,132

 
—

 
67,132

Repurchase and retirement of common stock
(11,917
)
 
(476
)
 
—

 
—

 
(476
)
Dividends declared on common stock ($0.1625 per share)
—

 
—

 
(25,220
)
 
—

 
(25,220
)
Stock option exercises
37,495

 
665

 
—

 
—

 
665

Shares issued under the Employee Stock Purchase Plan
17,267

 
581

 
—

 
—

 
581

Issuance of restricted stock
27,776

 
—

 
—

 
—

 
—

Forfeiture of restricted stock
(13,772
)
 
—

 
—

 
—

 
—

Share-based compensation, net of forfeitures
—

 
3,853

 
—

 
—

 
3,853

Other comprehensive loss, net of tax
—

 
—

 
—

 
(621
)
 
(621
)
BALANCE, MARCH 31, 2015
155,197,816

 
$
927,814

 
$
783,462

 
$
4,195

 
$
1,715,471



12

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

 
$
1,014,435

 
$
592,970

 
$
6,327

 
$
1,613,732

Net income
—

 
—

 
69,136

 
—

 
69,136

Repurchase and retirement of common stock
(9,126
)
 
(312
)
 
—

 
—

 
(312
)
Dividends declared on common stock ($0.1425 per share)
—

 
—

 
(22,453
)
 
—

 
(22,453
)
Stock option exercises
126,769

 
2,384

 
—

 
—

 
2,384

Shares issued under the Employee Stock Purchase Plan
18,150

 
522

 
—

 
—

 
522

Issuance of restricted stock
13,286

 
—

 
—

 
—

 
—

Forfeiture of restricted stock
(18,020
)
 
—

 
—

 
—

 
—

Share-based compensation, net of forfeitures
—

 
4,026

 
—

 
—

 
4,026

Other comprehensive income, net of tax
—

 
—

 
—

 
156

 
156

BALANCE, MARCH 31, 2014
157,631,854

 
$
1,021,055

 
$
639,653

 
$
6,483

 
$
1,667,191

Accumulated Other Comprehensive Income
The following table provides the components of changes in AOCI for the three months ended March 31, 2015 and 2014:
 
Three months ended
 
March 31,
(in thousands)
2015
 
2014
Balance at the beginning of period
$
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 $75 and $76 for the three months ended March 31, 2015 and 2014, respectively)
136

 
106

Net unrealized loss on interest rate swaps relating to interest rate cash flow hedges (net of tax of $614 for the three months ended March 31, 2015)
(863
)
 
—

Derivative instruments, net of tax
(727
)
 
106

Available-for-sale securities
 
 
 
Unrealized net gain on available-for-sale securities (net of tax of $76 and $36 for the three months ended March 31, 2015 and 2014, respectively)
106

 
50

Available-for-sale securities, net of tax
106

 
50

Total other comprehensive (loss) income, net of tax
(621
)
 
156

Balance at the end of period
$
4,195

 
$
6,483

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. No shares were repurchased under the share repurchase program during the three months ended March 31, 2015. Additionally, we had not entered into any agreement for the remaining amount available under the share repurchase program as of March 31, 2015.


13

7.    EARNINGS PER SHARE
We report both basic and diluted earnings per share. Our restricted stock and deferred stock units contain rights to receive nonforfeitable dividends and thus, are participating securities requiring the two-class method of computing earnings per share. A reconciliation of both calculations for the three months ended March 31, 2015 and 2014 is presented in the following table:
 
Three months ended
 
March 31,
(in thousands, except share, per share data and percentages)
2015
 
2014
Numerator:
 
 
 
Net income
$
67,132

 
$
69,136

Less: dividends declared and paid — common and restricted shares
(25,220
)
 
(22,453
)
Undistributed earnings
41,912

 
46,683

Percentage allocated to common shares (a)
99.2
%
 
99.1
%
Undistributed earnings — common shares
41,577

 
46,263

Add: dividends declared and paid — common shares
25,024

 
22,262

Numerator for basic and diluted earnings per common share
$
66,601

 
$
68,525

Denominator:
 
 
 
Basic earnings per common share — weighted average common shares outstanding
153,970,515

 
156,189,874

Incremental shares for stock options and employee stock purchase plan — weighted average assumed conversion
1,444,202

 
1,505,205

Diluted earnings per common share — adjusted weighted average shares and assumed conversion
155,414,717

 
157,695,079

Per common share net income:
 
 
 
Basic
$
0.43

 
$
0.44

Diluted
$
0.43

 
$
0.43

 
 
 
 
____________________________
(a)
Weighted average common shares outstanding
153,970,515

 
156,189,874

 
Weighted average restricted shares
(participating securities)
1,209,468

 
1,361,045

 
 Total
155,179,983

 
157,550,919

 
 Percentage allocated to common shares
99.2
%
 
99.1
%
The incremental shares for stock options and employee stock purchase plan (“ESPP”) shares are included in the diluted earnings per share calculation using the treasury stock method, unless the effect of including them would be anti-dilutive. The outstanding stock options and ESPP shares and the anti-dilutive stock options and ESPP shares excluded from the diluted earnings per share calculations were as follows:
 
2015
 
2014
Outstanding stock options and ESPP shares (as of March 31)
4,553,938

 
5,020,845

Anti-dilutive stock options and ESPP shares (for the three months ended March 31)
542,312

 
765,710

8.    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. We expect to contribute $4.1 million to the retirement plan in 2015.


14

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 expect to contribute $9.4 million to the supplemental benefit plans in 2015.
Net periodic benefit cost for the pension plans, by component, was as follows for the three months ended March 31, 2015:
 
Three months ended
 
March 31,
(in thousands)
2015
 
2014
Service cost
$
1,624

 
$
1,266

Interest cost
924

 
901

Expected return on plan assets
(960
)
 
(885
)
Amortization of prior service credit
(10
)
 
(10
)
Amortization of unrecognized loss
1,061

 
386

Net pension cost
$
2,639

 
$
1,658

Other Postretirement Benefits
We provide certain postretirement health care, dental, and life insurance benefits for eligible employees. We expect to contribute $9.3 million to the postretirement benefit plan in 2015.
Net postretirement benefit plan cost, by component, was as follows for the three months ended March 31, 2015:
 
Three months ended
 
March 31,
(in thousands)
2015
 
2014
Service cost
$
2,122

 
$
1,461

Interest cost
619

 
498

Expected return on plan assets
(463
)
 
(340
)
Amortization of unrecognized loss
125

 
—

Net postretirement cost
$
2,403

 
$
1,619

Defined Contribution Plan
We also sponsor a defined contribution retirement savings plan. Participation in this plan is available to substantially all employees. We match employee contributions up to certain predefined limits based upon eligible compensation and the employee’s contribution rate. The cost of this plan was $1.5 million and $1.3 million for the three months ended March 31, 2015 and 2014, respectively.
9.    FAIR VALUE MEASUREMENTS
The measurement of fair value is based on a three-tier hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. 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 three months ended March 31, 2015 and the year ended December 31, 2014, there were no transfers between levels.


15

Our assets and liabilities measured at fair value subject to the three-tier hierarchy at March 31, 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
26,394

 
—

 
—

Mutual funds — equity securities
802

 
—

 
—

Interest rate swap derivative
—

 
111

 
—

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

 
(3,523
)
 
—

Total
$
27,245

 
$
(3,412
)
 
$
—

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 March 31, 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 asset and 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 March 31, 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 three months ended March 31, 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.
Fair Value of Financial Assets and Liabilities
Fixed Rate Debt
Based on the borrowing rates obtained from third party lending institutions currently available for bank loans with similar terms and average maturities from active markets, the fair value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $4,076.7 million and $3,985.6 million at March 31, 2015 and December 31, 2014, respectively. These fair values represent Level 2 under the three-tier hierarchy described above. The


16

total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $3,629.9 million and $3,629.8 million at March 31, 2015 and December 31, 2014, respectively.
Revolving and Term Loan Credit Agreements
At March 31, 2015 and December 31, 2014, we had a consolidated total of $601.2 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 and special deposits, approximates their fair value due to the short-term nature of these instruments.
10.    COMMITMENTS AND CONTINGENT LIABILITIES
Environmental Matters
Our Regulated Operating Subsidiaries’ operations are subject to federal, state, and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination, such as claims for personal injury or property damage, may arise at many locations, including formerly owned or operated properties and sites where wastes have been treated or disposed of, as well as at properties currently owned or operated by our Regulated Operating Subsidiaries. Such liabilities may arise even where the contamination does not result from noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that a party can be held responsible for more than its share of the liability involved, or even the entire share. Although environmental requirements generally have become more stringent and compliance with those requirements more expensive, we are not aware of any specific developments that would increase our Regulated Operating Subsidiaries’ costs for such compliance in a manner that would be expected to have a material adverse effect on our results of operations, financial position or liquidity.
Our Regulated Operating Subsidiaries’ assets and operations also involve the use of materials classified as hazardous, toxic or otherwise dangerous. Many of the properties our Regulated Operating Subsidiaries own or operate have been used for many years, and include older facilities and equipment that may be more likely than newer ones to contain or be made from such materials. Some of these properties include aboveground or underground storage tanks and associated piping. Some of them also include large electrical equipment filled with mineral oil, which may contain or previously have contained 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.
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.


17

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 use of the industrial processing exemption from use tax it has taken beginning January 1, 2007.
ITCTransmission believes that its utilization of the industrial processing exemption is appropriate and intends to defend itself against the denial of such exemption through certain administrative and judicial appeal rights. However, it is reasonably possible that the assessment of additional use tax could be sustained after all administrative appeals and litigation have been exhausted.
The amount of use tax liability associated with the exemptions taken by ITCTransmission through March 31, 2015 is estimated to be approximately $16.1 million including interest. This amount includes approximately $10.1 million, including interest, assessed for the audit periods noted above. ITCTransmission has not recorded this contingent liability as of March 31, 2015. METC has also taken the industrial processing exemption, estimated to be approximately $10.5 million for periods still subject to audit and METC has also not recorded any contingent liabilities as of March 31, 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 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 reiterates 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.


18

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. The order established a schedule for the proceeding that provides for a hearing within 32 weeks of the order and 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.
We believe it is probable that refunds will be required for these matters, and the estimated range of refunds on a pre-tax basis is expected to be from $55.7 million to $106.4 million for the period from November 12, 2013 through March 31, 2015. The estimated range of refunds on a pre-tax basis as of December 31, 2014 was $47.8 million to $88.1 million for the period from November 12, 2013 through December 31, 2014. As of March 31, 2015 and December 31, 2014, our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $55.7 million and $47.8 million, respectively, for the estimated potential refunds as there is no best estimate within the range of refunds. The recognition of this estimated liability resulted in a reduction in revenues of $7.5 million and $46.9 million and an increase in interest expense of $0.4 million and $0.9 million for the three months ended March 31, 2015 and December 31, 2014, respectively. This resulted in an estimated after-tax reduction to net income of $4.8 million and $28.9 million for the three months ended March 31, 2015 and December 31, 2014, respectively. No amounts related to these complaints were recorded as of or for the three months ended March 31, 2014.
Based on the estimated range of refunds identified above, we believe that it is reasonably possible that this matter could result in an additional estimated pre-tax refund of up to $50.7 million (or a $30.7 million estimated after-tax reduction of net income) in excess of the amount recorded as of March 31, 2015. It is also possible the outcome of this matter 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 March 31, 2015, our MISO Regulated Operating Subsidiaries had a total of approximately $2.7 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 $2.7 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. 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.


19

11.    SEGMENT INFORMATION
We identify reportable segments based on the criteria set forth by the FASB regarding disclosures about segments of an enterprise, including the regulatory environment of our subsidiaries and the business activities performed to earn revenues and incur expenses. The following tables show our financial information by reportable segment:
 
Three months ended
OPERATING REVENUES:
March 31,
(in thousands)
2015
 
2014
Regulated Operating Subsidiaries
$
272,450

 
$
258,693

ITC Holdings and other
177

 
92

Intercompany eliminations
(140
)
 
(182
)
Total Operating Revenues
$
272,487

 
$
258,603

 
Three months ended
INCOME BEFORE INCOME TAXES:
March 31,
(in thousands)
2015
 
2014
Regulated Operating Subsidiaries
$
148,818

 
$
141,592

ITC Holdings and other
(41,226
)
 
(29,620
)
Total Income Before Income Taxes
$
107,592

 
$
111,972

 
Three months ended
NET INCOME:
March 31,
(in thousands)
2015
 
2014
Regulated Operating Subsidiaries
$
91,439

 
$
86,553

ITC Holdings and other
67,132

 
69,136

Intercompany eliminations
(91,439
)
 
(86,553
)
Total Net Income
$
67,132

 
$
69,136

TOTAL ASSETS:
March 31,
 
December 31,
(in thousands)
2015
 
2014
Regulated Operating Subsidiaries
$
7,017,521

 
$
6,867,411

ITC Holdings and other
4,034,365

 
3,944,318

Reconciliations / Intercompany eliminations (a)
(3,928,224
)
 
(3,837,640
)
Total Assets
$
7,123,662

 
$
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.


20

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.


21

•
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 three months ended March 31, 2015 or may affect future results include:
•
Our capital investment of $167.6 million at our Regulated Operating Subsidiaries for the three months ended March 31, 2015, resulting primarily from our focus on improving system reliability, increasing system capacity and upgrading the transmission network to support new generating resources;


22

•
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;
•
Debt maturing within one year of $175.0 million as of March 31, 2015 and the potentially higher interest rates associated with the additional financing required to repay this debt; and
•
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 10 to the condensed consolidated financial statements, which resulted in a total estimated pre-tax reduction of revenue and interest of $7.9 million and an estimated after-tax reduction to net income of $4.8 million for the three months ended March 31, 2015.
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
As of March 31, 2015, we have recorded a total of $14.1 million of regulatory assets for start-up, development and pre-construction expenses, including associated interest carrying charges, incurred by ITC Great Plains, which include certain costs incurred for the Kansas Electric Transmission Authority (“KETA”) and the Kansas V-Plan Projects prior to construction. Based on ITC Great Plains’ FERC application under which authority to recognize these regulatory assets was sought and the related FERC order granting such authority, ITC Great Plains made a filing with the FERC under Section 205 of the FPA in May 2013 to recover these 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. On March 26, 2015, FERC accepted ITC Great Plains’ request to commence amortization of the authorized regulatory assets, effective July 19, 2013, subject to refund, as well as set the matter for hearing and settlement judge procedures. As a result, ITC Great Plains will begin to include the unamortized balance of the regulatory assets in its rate base and commence amortization over a 10-year period. The amortization expense will be recovered through ITC Great Plains’ cost-based formula rate template, subject to refund. We do not expect the settlement of this proceeding to have a material impact on our results of operations, cash flows or financial condition.
Development Bonuses
We recognized general and administrative expenses of $9.5 million and $1.5 million during the three months ended March 31, 2015 and 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.
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 will be constructed by ITC Midwest. We currently estimate we will invest approximately $800 million in our portions of the 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 of the Thumb Loop project, consisting of approximately 62 miles of 345 kV transmission facilities has been placed into service. Phase 2, consisting of approximately 20 miles, was placed into service in May 2014. Through March 31, 2015, ITCTransmission has invested $482.2 million in the Thumb Loop


23

Project. We estimate ITCTransmission will invest a total of approximately $510 million in the project, which is currently anticipated to be completed in 2015.
Rate of Return on Equity and Capital Structure Complaints
In November 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 reiterates 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. The order established a schedule for the proceeding that provides for a hearing within 32 weeks of the order and 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.
We believe it is probable that refunds will be required for these matters, and the estimated range of refunds on a pre-tax basis is expected to be from $55.7 million to $106.4 million for the period from November 12, 2013 through March 31, 2015. The estimated range of refunds on a pre-tax basis as of December 31, 2014 was $47.8 million to $88.1 million for the period from November 12, 2013 through December 31, 2014. As of March 31, 2015 and December 31, 2014, our MISO Regulated Operating Subsidiaries had recorded an aggregate estimated regulatory liability of $55.7 million and $47.8 million, respectively, for the estimated potential refunds as there is no best estimate within the range of refunds. The recognition of this estimated liability resulted in a reduction in revenues of $7.5 million and $46.9 million and an increase in interest expense of $0.4 million and $0.9 million for the three months ended March 31, 2015 and December 31, 2014, respectively. This resulted in an estimated after-tax reduction to net income of $4.8 million and $28.9 million for the three months ended March 31, 2015 and December 31, 2014, respectively. No amounts related to these complaints were recorded as of or for the three months ended March 31, 2014.
Based on the estimated range of refunds identified above, we believe that it is reasonably possible that this matter could result in an additional estimated pre-tax refund of up to $50.7 million (or a $30.7 million estimated after-tax reduction of net income) in excess of the amount recorded as of March 31, 2015. It is also possible the outcome of this matter 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 March 31, 2015, our MISO Regulated Operating Subsidiaries had a


24

total of approximately $2.7 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 $2.7 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. 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.
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 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 a general trend of increases in revenues and earnings for our Regulated Operating Subsidiaries over the long term, excluding any impact resulting from the outcome of the complaints relating to base ROE as described in Note 10 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


25

depreciation, from our Regulated Operating Subsidiaries’ long-term capital investment programs to improve reliability, increase system capacity and upgrade the transmission network to support new generating resources. 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 fines of up to $1.0 million per day. 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
 
three months ended
 
year ending
Source of Investment
 
2014-2018
 
March 31, 2015 (a)
 
December 31, 2015
ITCTransmission
 
$
647

 
$
36.8

 
$170 — 200
METC
 
546

 
30.0

 
150 — 170
ITC Midwest (b)
 
1,991

 
95.0

 
380 — 405
ITC Great Plains
 
194

 
5.8

 
10 — 25
Development and other (c)
 
1,122

 
1.1

 
0 — 10
Total
 
$
4,500

 
$
168.7

 
$710 — 810
____________________________
(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)
Refer to “Item 1 Business — Development of Business — Development Projects” in our Form 10-K for the year ended December 31, 2014 for discussion on our development projects.
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 and variances between estimated and actual costs of construction contracts awarded. In addition, investments in transmission network upgrades for generator interconnection projects could change from prior estimates significantly due to changes in the MISO queue for generation projects and other factors beyond our control.


26

RESULTS OF OPERATIONS
Results of Operations and Variances
 
Three months ended
 
 
 
Percentage
 
March 31,
 
Increase
 
increase
(in thousands)
2015
 
2014
 
(decrease)
 
(decrease)
OPERATING REVENUES
$
272,487

 
$
258,603

 
$
13,884

 
5.4
 %
OPERATING EXPENSES
 
 
 
 
 
 
 
Operation and maintenance
25,562

 
24,861

 
701

 
2.8
 %
General and administrative
40,894

 
27,962

 
12,932

 
46.2
 %
Depreciation and amortization
34,435

 
31,378

 
3,057

 
9.7
 %
Taxes other than income taxes
22,380

 
21,193

 
1,187

 
5.6
 %
Other operating (income) and expenses — net
(236
)
 
(232
)
 
(4
)
 
1.7
 %
Total operating expenses
123,035

 
105,162

 
17,873

 
17.0
 %
OPERATING INCOME
149,452

 
153,441

 
(3,989
)
 
(2.6
)%
OTHER EXPENSES (INCOME)
 
 
 
 
 
 
 
Interest expense
48,474

 
45,309

 
3,165

 
7.0
 %
Allowance for equity funds used during construction
(7,549
)
 
(5,012
)
 
(2,537
)
 
50.6
 %
Other income
(253
)
 
(161
)
 
(92
)
 
57.1
 %
Other expense
1,188

 
1,333

 
(145
)
 
(10.9
)%
Total other expenses (income)
41,860

 
41,469

 
391

 
0.9
 %
INCOME BEFORE INCOME TAXES
107,592

 
111,972

 
(4,380
)
 
(3.9
)%
INCOME TAX PROVISION
40,460

 
42,836

 
(2,376
)
 
(5.5
)%
NET INCOME
$
67,132

 
$
69,136

 
$
(2,004
)
 
(2.9
)%
Operating Revenues
Three months ended March 31, 2015 compared to three months ended March 31, 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
$
196,976

 
72.3
 %
 
$
188,776

 
73.0
%
 
$
8,200

 
4.3
 %
Regional cost sharing revenues
74,550

 
27.4
 %
 
59,319

 
22.9
%
 
15,231

 
25.7
 %
Point-to-point
4,214

 
1.5
 %
 
5,685

 
2.2
%
 
(1,471
)
 
(25.9
)%
Scheduling, control and dispatch
3,215

 
1.2
 %
 
3,162

 
1.2
%
 
53

 
1.7
 %
Other
1,075

 
0.4
 %
 
1,661

 
0.7
%
 
(586
)
 
(35.3
)%
Recognition of contingent liability for return on equity complaint
(7,543
)
 
(2.8
)%
 
—

 
—
%
 
(7,543
)
 
n/a

Total
$
272,487

 
100.0
 %
 
$
258,603

 
100.0
%
 
$
13,884

 
5.4
 %
Network revenues increased due primarily to higher net revenue requirements at our Regulated Operating Subsidiaries during the three months ended March 31, 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 due primarily 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 Kansas V-Plan Project during the three months ended March 31, 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 estimated contingent liability for potential refunds relating to the return on equity complaint resulted in a reduction to operating revenues of $7.5 million during the three months ended March 31, 2015 as described in Note 10 to the condensed consolidated financial statements. 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.


27

Operating revenues for the three months ended March 31, 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 months ended March 31, 2015 compared to three months ended March 31, 2014
Operation and maintenance expenses were consistent with the prior period.
General and administrative expenses
Three months ended March 31, 2015 compared to three months ended March 31, 2014
General and administrative expenses increased primarily due to higher compensation-related expenses of $10.1 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.”
Depreciation and amortization expenses
Three months ended March 31, 2015 compared to three months ended March 31, 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 months ended March 31, 2015 compared to three months ended March 31, 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 months ended March 31, 2015 compared to three months ended March 31, 2014
Interest Expense
Interest expense increased due primarily to additional interest expense associated with the net issuance of $529.7 million in long-term debt securities subsequent to March 31, 2014 and higher borrowing levels under our revolving credit agreements during the three months ended March 31, 2015 as compared to the same period in 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.
Income Tax Provision
Three months ended March 31, 2015 compared to three months ended March 31, 2014
Our effective tax rates for the three months ended March 31, 2015 and 2014 were 37.6% and 38.3%, 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 $4.0 million (net of federal deductibility) during the three months ended March 31, 2015, compared to a state income tax provision of $4.5 million (net of federal deductibility) for the three months ended March 31, 2014.


28

LIQUIDITY AND CAPITAL RESOURCES
We expect to fund our future capital requirements with cash from operations, our existing cash and cash equivalents and amounts available under our revolving credit agreements (described in Note 5 to the condensed consolidated financial statements). In addition, we may from time to time secure debt and equity funding in the capital markets, although we can provide no assurance that we will be able to obtain financing on favorable terms or at all. 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 Board of Directors authorized share repurchase program as described in Note 6 to the condensed consolidated financial statements.
•
Fund contributions to our retirement benefit plans, as described in Note 8 to the condensed consolidated financial statements. We expect to make an estimated additional contribution of approximately $22.8 million to these plans in 2015. The impact of the growth in the number of participants in our retirement benefit plans and changes in the requirements of the Pension Protection Act may require contributions to our retirement benefit plans to be higher than we have experienced in the past.
In addition to the expected capital requirements above, any adverse determinations relating to the contingencies described in Note 10 to the condensed consolidated financial statements would result in additional capital requirements.
We believe that we have sufficient capital resources to meet our currently anticipated short-term needs. We rely on both internal and external sources of liquidity to provide working capital and to fund capital investments. 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 revolving credit agreements and our cash and cash equivalents as needed to meet our short-term cash requirements. As of March 31, 2015, we had consolidated indebtedness under our revolving and term loan credit agreements of $601.2 million, with unused capacity under the revolving credit agreements of $559.8 million. See Note 5 to the condensed consolidated financial statements for a detailed discussion of these agreements and the debt issuance in 2015.
As of March 31, 2015, we had approximately $175.0 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.


29


Issuer
 

Issuance
 
Standard and Poor’s
Ratings Services (a)
 
Moody’s Investor
Service, Inc. (b)
ITC Holdings
 
Senior Unsecured Notes
 
BBB+
 
Baa2
ITCTransmission
 
First Mortgage Bonds
 
A
 
A1
METC
 
Senior Secured Notes
 
A
 
A1
ITC Midwest
 
First Mortgage Bonds
 
A
 
A1
ITC Great Plains
 
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. All of the ratings have a stable outlook.
(b)
On April 15, 2015, Moody’s Investor Service, Inc. reaffirmed the credit ratings for ITC Holdings and the Regulated Operating Subsidiaries. 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 March 31, 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 $66.9 million and $45.7 million for the three months ended March 31, 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 $21.6 million during the three months ended March 31, 2015 compared to the same period in 2014. The increase was partially offset by higher income taxes paid of $3.7 million.
Cash Flows From Investing Activities
Net cash used in investing activities was $178.2 million and $159.0 million for the three months ended March 31, 2015 and 2014, respectively. The increase in cash used in investing activities was due primarily to the timing of payments for investments in property, plant and equipment during the three months ended March 31, 2015 compared to the same period in 2014.
Cash Flows From Financing Activities
Net cash provided by financing activities was $92.7 million and $93.0 million for the three months ended March 31, 2015 and 2014, respectively. The cash provided by financing activities during the three months ended March 31, 2015 was consistent compared to the same period in 2014.
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; and
•
The issuance of $225.0 million of 3.83% First Mortgage Bonds, Series G, due 2055 by ITC Midwest.
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


30

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 three months ended March 31, 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, was $4,076.7 million at March 31, 2015. The total book value of our consolidated long-term debt and debt maturing within one year, excluding revolving and term loan credit agreements, was $3,629.9 million at March 31, 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, at March 31, 2015. An increase in interest rates of 10% (from 5.0% to 5.5%, for example) at March 31, 2015 would decrease the fair value of debt by $171.7 million, and a decrease in interest rates of 10% at March 31, 2015 would increase the fair value of debt by $184.2 million at that date.
Revolving and Term Loan Credit Agreements
At March 31, 2015, we had a consolidated total of $601.2 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 March 31, 2015 would increase or decrease the total interest expense by $0.7 million, respectively, for an annual period on a constant borrowing level of $601.2 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 March 31, 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 March 31, 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 three months ended March 31, 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


31

“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 March 31, 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 10 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.
ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
The following table sets forth the repurchases of common stock for the quarter ended March 31, 2015:
 
Period
 
Total Number of Shares Purchased (a)
 
 Average Price Paid per Share
 
Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or Programs (b)
 
Maximum Number (or Approximate Dollar
Value) of Shares that May
Yet Be Purchased Under the Plans or Programs (in millions) (b)
 
 
January 2015
 
3,823

 
$
42.26

 
—

 
$
120.0

 
February 2015
 
6,651

 
39.21

 
—

 
120.0

 
March 2015
 
1,443

 
37.42

 
—

 
120.0

 
Total
 
11,917

 
$
39.97

 
—

 

____________________________
(a)
Shares acquired were delivered to us by employees as payment of tax withholding obligations due to us upon the vesting of restricted stock.
(b)
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.


32

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
 
 
 
3.2

 
Fifth Amended and Restated Bylaws of Registrant dated as of February 24, 2015 (filed with Registrant’s 2014 Form 10-K)
 
 
 
4.43

 
Eighth Supplemental Indenture, dated as of March 18, 2015, between ITC Midwest LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York Trust Company, N.A.), as trustee (filed with Registrant’s Form 8-K filed on April 7, 2015)
 
 
 
10.140

 
Summary of Annual Incentive Plan (2015)
 
 
 
10.141

 
Form of Restricted Stock Award Agreement (5 year vesting) (February 2015)
 
 
 
10.142

 
Amendment and Restatement of the Distribution - Transmission Interconnection Agreement by and between Michigan Electric Transmission Company, LLC and Consumers Energy Company, effective January 1, 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



33

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Dated: April 30, 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)
 


34




EXHIBIT 10.140
Summary of Annual Corporate Performance Bonus Plan for Executives
(as of February 2015)

Performance Goals and Targets

The annual bonus plan performance goals are individually weighted as set forth below. If all goals are achieved, executives will receive 200% of their target bonus amount. The annual bonus plan consists of three primary measurement categories relating to Company operations: Safety & Compliance, System Performance, and Financial. Each goal operates independently, such that payout will occur with respect to those goals for which the related numerical targets have been achieved even though the numerical targets relating to one or more other goals may not be achieved. There is no payout on any goal for which the related numerical target is not achieved. The goals, numerical targets relating to each goal, and a description of any adjustments to be made in determining whether the goal has been achieved, are established annually upon approval by the Compensation Committee. Goals and payout weighting approved for 2015 are as follows:


 
 
 
 
Category
Goal
Weight
Safety & Compliance
10% weight/20% Maximum Potential Payout
Safety as measured by lost time
2.5%-5%
 
Safety as measured by recordable incidents
5%
 
Infrastructure protection as measured by cyber security performance
5%
 
Infrastructure protection as measured by physical security performance
5%
System Performance
30% Weight/60% Maximum Potential Payout
ITCTransmission outage frequency
5%
 
METC outage frequency
5%
 
ITC Midwest outage frequency
5%
 
ITC Midwest outage restoration
5%
 
ITCTransmission Field Operation and Maintenance Plan
5%
 
METC Field Operation and Maintenance Plan
5%
 
ITC Midwest Field Operation and Maintenance Plan
5%
 
ITCTransmission, METC, ITC Midwest, and ITC Great Plains Capital Project Plan on a Combined Basis
15%-25%
Financial
60% Weight/120% Maximum Potential Payout
Non-field Operation and Maintenance Expense
10%
 
Net Income (1)
5%-10%
 
Total Shareholder Return (TSR)  (2)  
20%-100%
 
Total
200%

(1)
Net Income is defined as net income at ITC Holdings Corp.’s four operating subsidiaries, which are International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC and ITC Great Plains, LLC; excluding certain items, including, without limitation, changes in accounting standards or tax laws, potential impacts associated with the MISO ROE complaint or potential asset impairments associated with certain assets and the effects of any changes in tax depreciation elections.









(2)
TSR is compared to the Dow Jones Utility Average Index companies. TSR must be positive for the year and must exceed the 50 th percentile of the Dow Jones Utility Average Companies before there will be any payout for meeting this goal, as illustrated below:


Total Return to Shareholders Relative to Each of the Dow Jones Utility Average Companies
Performance Factor
1st to 50th percentile
1.0
51st to 60th percentile
1.2
61st to 70th percentile
1.4
71st to 80th percentile
1.6
81st to 90th percentile
1.8
91st to 100th percentile
2.0

Total return to shareholders for the calendar year shall be computed as follows:

A: Calculate the average of the closing prices 30 business days leading up to and including December 31, 2014
B: Calculate the average of the closing prices 30 business days leading up to and including December 31, 2015
C: Calculate total dividends paid per share during the calendar year
Total Return to Shareholders: (B - A + C)/A




Calculation of Bonus Award

Bonuses are based on target bonus amounts, which for each executive is a percentage of his or her base salary, as determined from time to time by the Compensation Committee. The amount of the bonus for each executive for any calendar year is determined in accordance with the following formula:

Base Salary x
Target Bonus (% of base salary) x
% Achievement of Corporate Goals
= Annual Bonus Amount

Timing of Payment of Bonus Award

In order to comply with Section 409A of the Internal Revenue Code, all amounts paid pursuant to the bonus program described in this Summary shall be paid out in cash within two and half months after the end of the calendar year.











EXHIBIT 10.141

RESTRICTED STOCK AWARD AGREEMENT


THIS AGREEMENT (the “Agreement”) is made effective as of _________ (as defined herein) (the “Grant Date”), between ITC Holdings Corp., a Michigan corporation (hereinafter called the “Company”), and the individual whose name is set forth on the signature page hereof, who is an employee of the Company or a Subsidiary of the Company, hereinafter referred to as the “Employee”. Capitalized terms not otherwise defined herein shall have the same meanings as in the Second Amended and Restated 2006 Long Term Incentive Plan, as may be further amended from time to time (the “Plan”).
WHEREAS, Employee is employed by the Company or one of its Subsidiaries and the Company desires to grant the Employee shares of Common Stock, pursuant to the terms and conditions of this Agreement (the “Restricted Stock Award”) and the Plan (the terms of which are hereby incorporated by reference and made a part of this Agreement); and
WHEREAS, this Agreement and the grants made pursuant to this Agreement are not otherwise subject to and shall not be governed by any Management Stockholder’s Agreement between Company and Employee; and
WHEREAS, the Committee has determined that it would be in the best interest of the Company and its shareholders to grant the shares of Common Stock provided for herein to the Employee as an incentive for increased efforts during his or her employment, has approved the grant of the Restricted Stock Award on the Grant Date and has advised the Company thereof and instructed the undersigned officer to grant said Restricted Stock Award.
NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows:
1.
Grant of the Restricted Stock. Subject to the terms and conditions of the Plan and the additional terms and conditions set forth in this Agreement, the Company hereby grants to the Employee ___________shares of Common Stock (hereinafter called the “Restricted Stock”). The Restricted Stock shall vest and become nonforfeitable in accordance with Section 2 hereof. In the event of any conflict between the Plan and this Agreement, the terms of the Plan shall control, it being understood that variations in this Agreement from terms set forth in the Plan shall not be considered to be in conflict if the Plan permits such variations.    
2.
Vesting and Forfeiture.
a.So long as the Employee continues to be employed by the Company or its Subsidiaries, the Restricted Stock shall become 100% vested and non-forfeitable upon the earliest to occur of (i) the fifth anniversary of the Grant Date (the “Vesting Date”), (ii) the Employee ceasing to be employed due to Employee’s death or Disability, or (iii) the occurrence of a Change in Control Termination (as defined below). The Committee has irrevocably determined not to, and shall not (and shall not permit the Board to), exercise any right it may have under the Plan, including without limitation under Section 9.2(c) of the Plan, to determine that the Restricted Stock shall not become immediately 100% vested upon a Change in Control.

b.If Employee’s employment is terminated for any reason other than Employee’s death, Disability or Retirement prior to the Vesting Date or a Change in Control, Employee’s right




to shares of Common Stock subject to the Restricted Stock Award that are not yet vested automatically shall terminate and be forfeited by Employee unless the Committee, in the exercise of its authority under the Plan, modifies the Vesting Date in connection with such termination.

c.The foregoing provisions of this Section 2 notwithstanding, if Employee attains or has attained “Normal Retirement Age” (as defined in the International Transmission Company Retirement Plan) prior to the Vesting Date while continuing to be employed by the Company or its Subsidiaries, the Restricted Stock shall become vested (i) as of the date Employee attains such Normal Retirement Age, in increments of 20% of such shares in respect of each one year anniversary (if any) of the date of this Agreement that has occurred prior to Employee’s attaining such Normal Retirement Age, and (ii) in increments of 20% of such shares as of each one year anniversary of the date of this Agreement that occurs after Employee attains such Normal Retirement Age until all shares have fully vested (provided that Employee continues to be employed by the Company or its Subsidiaries as of each such anniversary).

d.A “Change in Control Termination” shall mean a termination of Employee’s employment (i) by the Company without “Cause” or (ii) if the Employee is a party to a written employment agreement with the Company, by Employee for “Good Reason” (as defined in such agreement), which termination in the case of (i) or (ii) occurs after the execution of an agreement to which the Company is a party pursuant to which a Change in Control will occur or has occurred upon consummation of the transactions contemplated by such agreement but, if a Change in Control has occurred pursuant thereto, not more than two years after such Change in Control, and if a Change in Control has not yet occurred pursuant thereto, while such agreement remains executory.

e.“Cause” shall mean (i) if the Employee is a party to a written employment agreement with the Company, “Cause” as defined in such agreement, and (ii) in all other cases, (A) Employee’s continued failure substantially to perform Employee’s duties to the Company or affiliates (other than as a result of total or partial incapacity due to physical or mental illness) for a period of 10 days following written notice by the Company to Employee of such failure, (B) dishonesty in the performance of Employee’s duties hereunder, (C) Employee conviction of, or plea of nolo contendere to a crime constituting (x) a felony under the laws of the United States or any state thereof or (y) a misdemeanor involving moral turpitude, (D) Employee’s willful malfeasance or willful misconduct in connection with Employee’s duties hereunder or any act or omission which is injurious to the financial condition or business reputation of the Company or affiliates or (E) Employee’s breach of any non-compete or confidentiality obligations to the Company or affiliates.

3.
Certificates.

a.Certificates evidencing the Restricted Stock shall be issued by the Company and shall be registered in the Employee’s name on the stock transfer books of the Company promptly after the date hereof, but shall remain in the physical custody of the Company or its designee at all times prior to the vesting of such Restricted Stock pursuant to Section 2. The Employee hereby acknowledges and agrees that the Company shall retain custody of such certificate or certificates until the restrictions imposed by Section 2 on the Common Stock granted hereunder lapse. As a condition to the receipt of this Restricted Stock Award, the Employee shall deliver to the Company a stock power, duly endorsed in blank, relating to the Restricted Stock.




Alternatively, instead of issuing a stock certificate, the shares may be issued in book entry form. No certificates shall be issued for fractional shares.

b.As soon as practicable following the vesting of the Restricted Stock pursuant to Section 2, certificates for the Restricted Stock which shall have vested shall be delivered to the Employee or to the Employee’s legal guardian or representative along with the stock powers relating thereto. If the shares have been issued in book entry form, the restrictive notation made pursuant to Section 5 of this Agreement shall be removed.

4.Rights as a Stockholder.
The Employee shall have no rights as a stockholder of the Company until certificates are issued. Once issued, the Employee shall be the record owner of the Restricted Stock unless or until such Restricted Stock is forfeited pursuant to Section 2 hereof or is otherwise sold, and as record owner shall be entitled to all rights of a common stockholder of the Company (including, without limitation, the right to vote and to receive dividends and other distributions on the shares of Restricted Stock).

5.Legend on Certificates.
The certificates representing the vested Restricted Stock delivered to the Employee as contemplated by Section 3(b) above shall bear the following legend:
The sale or other transfer of the shares of stock represented by this certificate, whether voluntary, involuntary or by operation of law, is subject to certain restrictions on transfer set forth in the ITC Holdings Corp. Second Amended and Restated 2006 Long Term Incentive Plan (“Plan”), rules and administrative guidelines adopted pursuant to such Plan and an Agreement dated May 22, 2012. A copy of the Plan, such rules and such Agreement may be obtained from the Secretary of ITC Holdings Corp.
Such certificates shall also be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations, and other requirements of the Securities and Exchange Commission or any stock exchange upon which such Common Stock is listed, any applicable Federal or state laws and the Company’s Articles of Incorporation and Bylaws, and the Committee may cause a legend or legends to be put on any such certificates to make appropriate reference to such restrictions. If issued in book entry form, a notation shall be made therewith to the same restrictive effect as set forth above.
6. Transferability. The Restricted Stock may not, at any time prior to becoming vested pursuant to Section 2 or thereafter, be transferred, sold, assigned, pledged, hypothecated or otherwise alienated.
7. Employee’s Employment by the Company. Nothing contained in this Agreement or in any other agreement entered into by the Company or any of its Subsidiaries and the Employee, other than the applicable provisions of any offer letter from the Company or any of its Subsidiaries to the Employee or any employment agreement entered into by and between the Employee and the Company or any of its Subsidiaries, as applicable, (i) obligates the Company or any Subsidiary to employ the Employee in any capacity whatsoever or (ii) prohibits or restricts the Company or any Subsidiary from terminating the employment, if any, of the Employee at any time or for any reason whatsoever, with or without cause, and the Employee hereby acknowledges and agrees that neither the Company nor any other person or entity has made any representations or promises whatsoever to the Employee concerning the Employee’s employment or continued employment by the Company or any Subsidiary thereof.




8.     Change in Capitalization. In the event of a merger, reorganization, consolidation, recapitalization, dividend or distribution (whether in cash, shares or other property), stock split, reverse stock split, spin-off or similar transaction or other change in corporate structure affecting the Common Stock or the value thereof, prior to the time the restrictions imposed by Section 2 on the Restricted Stock granted hereunder lapse, such adjustments and other substitutions shall be made to the Restricted Stock Awards as the Committee, in its sole discretion, deems equitable or appropriate. Any stock, securities or other property exchangeable for Restricted Stock pursuant to such transaction shall be deposited with the Company and shall become subject to the restrictions and conditions of this Agreement to the same extent as if it had been the original property granted hereby, all pursuant to the Plan.
9.    Withholding. The Company shall have the right to withhold from Employee’s compensation or to require Employee to remit sufficient funds to satisfy applicable withholding for income and employment taxes upon the vesting of Restricted Stock pursuant to Section 2. Subject to limitations in the Plan, Employee may, in order to fulfill the withholding obligation, tender previously-acquired shares of Common Stock that have been held at least six months, provided that the shares have an aggregate Fair Market Value sufficient to satisfy in whole or in part the applicable withholding taxes. The Company shall be authorized to take such action as may be necessary, in the opinion of the Company’s counsel (including, without limitation, withholding vested Common Stock otherwise deliverable to the Employee and/or withholding amounts from any compensation or other amount owing from the Company to the Employee), to satisfy the obligations for payment of the minimum amount of any such taxes.

10. Limitation on Obligations. The Company’s obligation with respect to the Restricted Stock granted hereunder is limited solely to the delivery to the Employee of shares of Common Stock on the date when such shares are due to be delivered hereunder, and in no way shall the Company become obligated to pay cash in respect of such obligation. This Restricted Stock Award shall not be secured by any specific assets of the Company or any of its Subsidiaries, nor shall any assets of the Company or any of its subsidiaries be designated as attributable or allocated to the satisfaction of the Company’s obligations under this Agreement. In addition, the Company shall not be liable to the Employee for damages relating to any delay in issuing the share certificates, any loss of the certificates, or any mistakes or errors in the issuance of the certificates or in the certificates themselves.

11.     Securities Laws. Upon the vesting of any Restricted Stock, the Company may require the Employee to make or enter into such written representations, warranties and agreements as the Committee may reasonably request in order to comply with applicable securities laws or with this Agreement. The granting of the Restricted Stock hereunder shall be subject to all applicable laws, rules and regulations and to such approvals of any governmental agencies as may be required.

12.     Notices. Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Employee shall be addressed to him or her at the address stated in the Company’s employee records. By a notice given pursuant to this Section 12, either party may hereafter designate a different address for notices to be given to the party. Any notice that is required to be given to the Employee shall, if the Employee is then deceased, be given to the Employee’s personal representative if such representative has previously informed the Company of his status and address by written notice under this Section 12. Any notice shall have been deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid, deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service.





13.     Governing Law. The laws of the State of Michigan shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.

14.     Amendment. Subject to Section 2(b) of this Agreement and Sections 9.1 and 10.6 of the Plan, this Agreement may be amended only by a writing executed by the parties hereto if such amendment would adversely affect Employee. Any such amendment shall specifically state that it is amending this Agreement.

15.     Recoupment Policy. This Agreement, the Restricted Stock Award and any economic benefits recognized by Employee in connection with the Restricted Stock Award (including, without limitation, the proceeds from the sale of shares subject to the Restricted Stock Award) are subject to forfeiture and/or recoupment pursuant to the Company’s Recoupment Policy adopted November 26, 2013, as amended from to time.

16.     Signature in Counterparts. This Agreement may be signed in counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.    
 
[Signatures on next page]

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the Grant Date.

EMPLOYEE

                                                                                                 
ITC HOLDINGS CORP.


By:     
Name:
Title:









EXHIBIT 10.142

Midcontinent ISO                    Fifth Revised Service Agreement No.1926
FERC Electric Tariff, Superseding Fourth Revised Service Agreement No.1926
Seventh Revised Volume No. 1
Amendment and Restatement of the
April 1, 2001
DISTRIBUTION-TRANSMISSION
INTERCONNECTION AGREEMENT
by and between
Michigan Electric Transmission Company, LLC
as Transmission Provider
and
Consumers Energy Company
as Local Distribution Company




Issued by: Stephen G. Kozey, Issuing Officer    Effective: (FERC determination)
Issued on: (FERC determination)










TABLE OF CONTENTS

ARTICLE 1.        Definitions
ARTICLE 2.        Operational Requirements
ARTICLE 3:        Operation and Maintenance
ARTICLE 4.        Supervisory Control and Data Acquisition, SCADA
ARTICLE 5.        Revenue Metering
ARTICLE 6.        Protective Relaying and Control
ARTICLE 7.        Planning and Obligation to Serve
ARTICLE 8.        Transmission Service Level
ARTICLE 9.        New Construction and Modification
ARTICLE 10.        Access to Facilities
ARTICLE 11.        Notifications and Reporting
ARTICLE 12.        Safety
ARTICLE 13.        Environmental Compliance and Procedures
ARTICLE 14.        Billings and Payment
ARTICLE 15.        Applicable Regulations and Interpretation
ARTICLE 16.        Force Majeure
ARTICLE 17.        Indemnification
ARTICLE 18.        Insurance
ARTICLE 19.        Several Obligations
ARTICLE 20.        Confidentiality






ARTICLE 21.        Breach, Default and Remedies
ARTICLE 22.        Term
ARTICLE 23.        Assignment/Change in Corporate Identity
ARTICLE 24.        Subcontractors
ARTICLE 25.        Dispute Resolution
ARTICLE 26.        Miscellaneous Provisions
EXHIBIT 1.        Interconnection Points (Substations) Addendum 8, Final
10/02/14
EXHIBIT 2.        Contact Information for Local Distribution Company’s
Representatives and Transmission Provider’s Representatives
EXHIBIT 3.        Special Manufacturing Contracts Influenced by Transmission
System
EXHIBIT 4.        Metering Specifications
EXHIBIT 5.        Respective Ownership of Substation Facilities Since August 7,
2007 - Addendum 6, Final 10/02/14
EXHIBIT 6.        Jointly Owned Assets - Ownership by Percent of Major Equipment
Addendum 8, Final 10/02/14






















Amendment and Restatement of the
DISTRIBUTION TRANSMISSION INTERCONNECTION AGREEMENT
This Amendment and Restatement of the April 1, 2001 Distribution Transmission Interconnection Agreement (“Agreement”) is entered into December 3, 2014 by and between the Michigan Electric Transmission Company, LLC, a Michigan corporation (“Transmission Provider”), having a place of business at 27175 Energy Way, Novi, Michigan 48377, and Consumers Energy Company (“Local Distribution Company”), a Michigan company, doing business in Michigan and having a place of business at One Energy Plaza, Jackson, Michigan, 49201. Transmission Provider and Local Distribution Company are individually referred to herein as a "Party” and collectively as “Parties.” This Agreement amends, restates and completely replaces the April 1, 2001 Distribution Transmission Interconnection Agreement between the Parties, effective on the date indicated above.
WHEREAS, Transmission Provider requires access to parts of Local Distribution Company’s assets, and Local Distribution Company requires access to parts of Transmission Provider’s assets; and
WHEREAS, the Parties have agreed to execute this mutually acceptable Agreement in order to provide interconnection of the Local Distribution Company with the Transmission Provider and to define the continuing rights, responsibilities, and obligations of the Parties with respect to the use of certain of their own and the other Party’s property, assets, and facilities.
NOW, THEREFORE, in consideration of their respective commitments set forth herein, and intending to be legally bound hereby, the Parties covenant and agree as follows:
ARTICLE 1. Definitions
Wherever used in this Agreement with initial capitalization, the following terms shall have the meanings specified or referred to in this Article 1.
1.1    Administrative Committee means the committee established pursuant to
Article 6 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.
1.2
Agreement means this Interconnection Agreement between Local Distribution Company and Transmission Provider, including all attachments hereto, as the same may be amended, supplemented, or modified in accordance with its terms

1.3    Black Start Capability shall mean a generating unit that is capable of
starting without an outside electrical supply.
1.4    Black Start Plan shall mean a plan utilizing Black Start Capability designed
and implemented by the Transmission Provider in conjunction with its interconnected generation and distribution customers, Distribution System Control, other electric




systems, its Security Coordinator and ECAR, to energize portions of the Transmission System which are de-energized as a result of a widespread system disturbance.
1.5    Commission shall mean the Michigan Public Service Commission
(MPSC), or its successor.
1.6    Confidential Information shall have the meaning set forth in Section 20.1
hereof.
1.7    Control Area shall mean an electric system, bounded by interconnection
metering and telemetry. Generation within the Control Area is directed to operate in a manner prescribed by guidelines established by ECAR and NERC and in accordance with Good Utility Practice to (a) maintain scheduled interchange with other Control Areas, (b) maintain the operating frequency and (c) provide sufficient generating capacity to maintain operating reserves.
1.8    Distribution System shall mean the equipment and facilities and the
Interconnection Equipment owned by the Local Distribution Company and used to deliver power and energy to end users including transformers, switches, and feeders rated at Nominal Voltage of 138 kilovolts (kV) or less.
1.9    Distribution System Control shall mean the entity that has the ability and
the obligation to operate the Distribution System Control Area to ensure that the aggregate electrical demand and energy requirements of the load is met at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.
1.10
Distribution System Control Area shall mean a Control Area whose load and generation, and other bulk power supply points are integrated by the Transmission System.
1.11     Distribution System Control Center shall mean the electric Distribution
System Control Center(s) that is/are responsible for monitoring and controlling the Distribution System in real time.
1.12
Distribution Transformer shall mean an electrical transformer which, generally, has its secondary low-side windings rated at Nominal Voltage of less than 138 kV.
1.13
Due Diligence shall mean the exercise of good faith efforts to perform a required act on a timely basis and in accordance with Good Utility Practice using the necessary technical and personnel resources.
1.14
ECAR is an acronym, which stands for the East Central Area Reliability coordination agreement. This is the Agreement under which Transmission Providers, who are signatories of the agreement, establish regional coordination practices and guides to govern the electric coordinated operation and reliability of the East Central Region of North America.
1.15
Effective Date shall mean the closing date as defined in the Membership Interests Purchase Agreement between the Parties.




1.16
Eligible Customer shall have the same meaning as that term is defined under the Transmission Provider’s OATT on file with the FERC.
1.17
Emergency means a condition or situation that in the reasonable good faith determination of the affected Party in accordance with Good Utility Practice contributes to an existing or imminent physical threat of danger to life or a significant threat to health, property or the environment.
1.18
Extended Outage shall mean an Unplanned Outage, in which facilities are automatically removed from service (typically by relay-action operating circuit breakers), with a duration of more than two (2) minutes.
1.19
FERC shall mean the Federal Energy Regulatory Commission or its successor federal agency.
1.20     Force Majeure shall have the meaning set forth under Article 16 hereof.
1.21
Forced Outage shall mean an Unplanned Outage, in which facilities are removed from service by operator intervention and not automatically such as by relay-action operating circuit breakers.
1.22
Good Utility Practice shall mean any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice
is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather includes all acceptable practices, methods, or acts generally accepted in the region.
1.23
Governmental Authority shall mean any foreign, federal, state, local or other governmental regulatory or administrative agency, court, commission, department, board, or other governmental subdivision, legislature, rulemaking board, tribunal, arbitrating body, or other governmental authority; provided such entity possesses valid jurisdictional authority to regulate the Parties and the terms and conditions of this Agreement.
1.24     ISO means Independent System Operator.
1.25
Interconnection Equipment shall mean all the equipment that is necessary for the interconnection of the Distribution System to the Transmission System which is located at the substations listed in Exhibit 1 hereto as it may be revised from time to time.
1.26
Interconnection Point(s) shall mean the point(s) at which the Distribution System is connected to the Transmission System, as set forth in Exhibit 1 hereto as it may be revised from time to time.
1.27
Interconnection Service shall mean the services provided by the Transmission Provider




for the interconnection of the Distribution System with the Transmission System. Interconnection Service does not include the right to transmission service on the Transmission System, which service shall be obtained in accordance with the provisions of the Transmission Provider’s OATT.
1.28
Interconnection Standards shall be those standards provided by the Transmission Provider to the Local Distribution Company to establish and maintain interconnection operation in compliance with standards of NERC, ECAR, applicable state or federal regulations or by mutual agreement of the Parties.
1.29
Interest Rate shall mean an annual percentage rate of interest equal to the lesser of (a) the prime rate published by the Wall Street Journal (which represents the base rate on corporate loans posted by at least 75% of the nation’s banks) on the date due, plus 2%, or (b) the highest rate permitted by law.
1.30
Jointly Owned Assets shall mean those assets in which the Transmission Provider and Local Distribution Company have undivided ownership interests. Due to the nature of substation designs, many of the supporting substation assets (e.g., station batteries, fence, control houses, ground
grid, yard stone, steel structures, and some protective relay equipment) cannot be separated by ownership and the Parties share in the ownership of such assets. The respective ownership of such assets by substation is shown in Exhibit 6.
1.31
Knowledge shall mean actual knowledge of the corporate officers or managers of the specified Person charged with responsibility for the particular function as of the Effective Date of this Agreement, or, with respect to any certificate delivered pursuant to the Agreement, the date of delivery of the certificate.
1.32
Least-Cost shall mean the lowest Transmission System and Distribution System facility costs, over the life of the facility, to accommodate an improvement need while adequately providing for reliability, operating, and maintenance requirements.
1.33
Local Distribution Company shall mean Consumers Energy Company and its successors and assigns.
1.34
Local Distribution Company Provided Services shall mean those services provided by the Local Distribution Company for the Transmission Provider by mutual agreement or contract.
1.35
Local Distribution Company’s Representative shall be that person(s) identified as the point of contact for day-to-day operations of the Distribution System, identified in Section 2.3.
1.36
Momentary Outage shall mean a Distribution or Transmission System (in whole or in part) interruption in service with a duration of two (2) minutes or less.
1.37
Momentary Outage Event shall mean one or more Momentary Outages within any 60-minute period that are attributable to the same root cause.




1.38
NERC shall mean the North American Electric Reliability Council or its successor.
1.39
Network Security shall mean the ability of the Transmission System to withstand sudden disturbances such as unforeseen conditions, electric short circuits or unanticipated loss of system elements consistent with reliability principles used to design, plan, operate, and assess the actual or projected reliability of an electric system that are established by any Governmental Authority, NERC or ECAR and which are implemented by Transmission Provider or required of Transmission Provider in compliance with Security Coordinator directives.
1.40
Network Security Condition shall mean a condition or situation in which, in the reasonable good faith determination of Transmission Provider, Network Security is not satisfied or is threatened.
1.41
Nominal Voltage shall mean an accepted standard voltage level offered by the Transmission Provider, at various points on the Transmission System, including but not limited to 120 kV, 138 kV and 345 kV.
1.42     Normal System Condition shall mean any operating conditions of the
Transmission System other than an Emergency or Network Security Condition.
1.43
Open Access Transmission Tariff or OATT shall mean the Open Access Transmission Tariff of the Transmission Provider on file with the FERC.
1.44
Operating Committee means the committee established pursuant to Section 6.4.3 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.
1.45
Party or Parties shall have the meaning set forth in the introductory paragraph of this Agreement.
1.46
Person shall mean any individual, partnership, limited liability company, joint venture, corporation, trust, unincorporated organization, or governmental entity or any department or agency thereof.
1.47
Planned Outage shall mean action by (i) Local Distribution Company or Transmission Provider to take its equipment, facilities or systems out of service, partially or completely, to perform work on specific components that is scheduled in advance and has a predetermined start date and duration pursuant to the procedures set forth in Sections 3.10.1, 3.10.2, and 3.10.4. Planned Outage shall not include the construction of new facilities or system elements, the modification of existing facilities or system elements addressed in Article 9, which includes, but is not limited to, activities associated with the construction of third party facilities or with the modifications required to accommodate third party facilities.
1.48
Planning Committee means the committee established pursuant to Section 6.4.3 of the Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution Company and Transmission Provider.




1.49
Protective Relay is a device which detects abnormal power system conditions and, in response, initiates automatic control action
1.50
Protective Relay System is a group of Protective Relays and associated sensing devices and communications equipment that detects system abnormalities and performs automatic control action to mitigate or reduce adverse effects of such abnormalities.
1.51
Qualified Personnel shall mean individuals trained for their positions in accordance with Good Utility Practice.
1.52     RTO means Regional Transmission Organization.
1.53
Regulated Substance means any contaminant, hazardous waste, hazardous substance, hazardous constituent, or toxic substance, as defined in the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), 42 USC 9601 et seq, Resource Conservation and Recovery Act (RCRA), 42 USC 6901 et seq, Toxic Substances Control Act (TSCA), 15 USC 2601 et seq, The Michigan Natural Resources and Environmental Protection Act (MCLA 324.101 et seq); or any other similar statutes now or hereafter in effect.
1.54
Release shall mean, spill, leak, discharge, dispose of, pump, pour, emit, empty, inject, leach, dump, or allow to escape into or through the environment.
1.55
Revenue Quality Metering System shall mean a system which includes current and voltage instrument transformers, secondary wiring, test switches, meter transducer(s), meter and loss compensation as set forth in Article 5.
1.56
RTU - Remote Terminal Units shall mean a device connected by a communication system to one or more master computers with appropriate software placed at various locations to collect data and perform remote control. It may also perform intelligent autonomous control of electrical systems and report the results back to the master computer(s).
1.57
Security Coordinator shall mean a NERC-approved entity that provides the security assessment and emergency operations coordination for one or more Control Areas or transmission providers and which has operational authority under NERC standards over the Transmission Provider.
1.58
Steady-State Voltage shall mean the value of a voltage after all transients have decayed to a negligible value. The root-mean-square value in the steady-state does not vary with time.
1.59
Supervisory Control and Data Acquisition (SCADA) shall mean a system that provides data acquisition, supervisory control and alarm display and control from remote field locations to control centers.
1.60
Transmission Provider shall mean the Michigan Electric Transmission Company, LLC and its successors and assigns.
1.61
Transmission Provider’s Representative(s) shall be that person(s) identified as




the point for contact for day-to-day operations of the Transmission System, identified in Section 2.3.
1.62
Transmission System shall mean all the facilities of the Transmission Provider that perform a "Transmission" function, as defined in Section 1.1 of the Easement Agreement between the Parties, dated April 29, 2002, as modified by Section 3.4 of this Agreement.
1.63
Transmission System Operations Center(s) shall mean the electric Transmission System control center(s) that is/are responsible for monitoring and controlling the Transmission System in real time.
1.64
Unplanned Outage shall mean action by Local Distribution Company or Transmission Provider to take its equipment, facilities or systems out of service, partially or completely, due to an unanticipated failure, when such removal from service was not scheduled in accordance with Sections 3.10.1, 3.10.2, and 3.10.4. Such removal from service may be automatic such as by relay-action operating circuit breakers or by operator intervention. Momentary interruptions are excluded from the definition of Unplanned Outages. Unplanned Outages include Forced Outages as well as Extended Outages.
ARTICLE 2. Operational Requirements
2.1    Subject to the terms and conditions of this Agreement, Transmission
Provider shall provide Local Distribution Company Interconnection Service for each Interconnection Point identified in Exhibit 1, from the Effective Date for the term of this Agreement.
2.2
The Interconnection Points between the Transmission System and Distribution System are listed in Exhibit 1. It shall be the Transmission Provider’s responsibility to annually prepare an addendum to this exhibit that shows all new or modified interconnections. The original Exhibit 1 and all addendums shall be retained for future reference.
2.3    Local Distribution Company’s Representatives and Transmission
Provider’s Representatives are listed in Exhibit 2, as may be modified from time to time by either Party, giving written notice of changes regarding its
Representative(s) to the other Party.
2.4    Interconnection Standards
2.4.1
The Interconnection Point(s) shall be established and maintained in accordance with Good Utility Practice and the applicable NERC, Federal, State, OATT and ECAR standards and policies for Transmission Provider service to Local Distribution Company.
2.4.2
Reactive Power. Transmission Provider and Local Distribution Company recognize and agree that they have a mutual responsibility for maintaining voltage at the Interconnection Points. Transmission Provider is responsible for maintaining Transmission System voltage as listed in Sections 8.1, 8.2 and 8.3 and reasonably compensating for reactive power losses resulting from transmission service. The Local Distribution Company is responsible for controlling Distribution System voltage and compensating for Distribution




System reactive power losses and reactive power consumed by retail customers. The Local Distribution Company may use a combination of static and dynamic reactive resources at various locations around the Transmission Provider's system. The Local Distribution Company's and the Transmission Provider’s SCADA systems shall be used to determine the net exchange of reactive power on a total interconnections basis. For those distribution substations where there are no SCADA facilities in place the reactive flows shall be determined from SCADA data on the connecting lines in conjunction with computer load flow simulations. At load levels below 90% of peak the system should be designed such that the average power factor for the sum of all Interconnection Points is between 90% lagging and 90% leading (“peak” as used here shall refer to a current year’s maximum MW load for the Local Distribution Company). For load levels above 90% of peak the power factor should be at 98% (lagging or leading), or better. If the power factor falls below this minimum the Planning Committee shall review available options and determine the best method of addressing any resulting system problems.
2.5(a) The Local Distribution Company shall comply with Transmission Provider’s reasonable operating requirements or switching procedures. The Local Distribution Company shall verbally notify the Transmission Provider if the Local Distribution Company is unable to comply with this Section at any time during the term of the Agreement.
(b) The Transmission Provider shall comply with Local Distribution Company's reasonable operating requirements or switching procedures. The Transmission Provider shall verbally notify the Local Distribution Company if the Transmission Provider is unable to comply with this Section at any time during the term of the Agreement.
2.6    Local Distribution Company shall comply with the requests, orders,
directives and requirements of Transmission Provider in its role of implementing the directives of the Security Coordinator. Any such requests, orders, directives or requirements of Transmission Provider must be (a) issued in accordance with Good Utility Practice, (b) not unduly discriminatory, (c) otherwise in accordance with applicable tariffs or applicable federal, state or local laws, (d) in conformance with NERC operating procedures, and (e) reasonably necessary to maintain the integrity of the Transmission System.
2.7     Load Shedding
2.7.1     Local Distribution Company shall comply, as part of a Control Area program, with                 installation of automatic underfrequency load shedding equipment and maintain                 compliance with the standards set forth in NERC and ECAR operating standards and             policies at Transmission Provider’s expense.
2.7.2     The Transmission Provider may direct the Local Distribution Company to shed load to             maintain the reliability and integrity of the Transmission System, in accordance with the             OATT. The Transmission Provider and the Local Distribution Company will comply with             MPSC directives and will endeavor to minimize the impact on the Local Distribution             Company customers.
2.8    Not a Reservation for Transmission Service




2.8.1     Local Distribution Company, or an Eligible Customer under the OATT, shall be            responsible for making arrangements under the OATT for transmission and any            ancillary services associated with the delivery of capacity and/or energy purchased or        produced by the Local Distribution Company, which services shall not be provided        under this Agreement.
2.8.2     Local Distribution Company and Transmission Provider make no guarantees to the other        under this Agreement with respect to transmission service that is available under the            Transmission Provider’s OATT or any other tariff under which transmission service may            be available in the region. Nothing in this Agreement shall constitute an express or            implied representation or warranty with respect to the current or future availability of            transmission service. Should the Parties enter into an arrangement under the OATT or            another tariff, any terms in this Interconnection Agreement that may be in conflict with that        tariff shall be subordinate to the terms of that tariff.

ARTICLE 3. Operation and Maintenance
3.1    The Operating Committee shall develop specific methods and procedures
with respect to Local Distribution Company’s and Transmission Provider’s systems covering at least, but not limited to, the following areas: safety, voltage control, outage planning and implementation, service restoration, emergency operations procedures, frequency controls, environmental matters, and maintenance planning and execution.
3.2    Exhibit 5 reflects ownership changes since August 7, 2007. Exhibit 5
Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared between the Parties and approved by both Parties at least annually when Exhibit 6 is updated to show changes in ownership. For purpose of this Section 3.2, such submission and approval of changes shall be in writing consistent with Section 11.1. For current ownership (reflecting ownership changes since August 7, 2007), see the WDs in the DMS. The original Exhibit 5 WDs and all updates will be retained for future reference.
3.3    All operation and maintenance activities will be the financial responsibility
of the owning Party. All operation and maintenance activities on Jointly Owned Assets will be under the direction and control of the Party that
owns the greater percentage of the major equipment at that location. In
the case where both Parties own an equal share the Local Distribution Company shall have such direction and control. The Parties’ respective share of responsibility for the costs of all operation and maintenance activities on Jointly Owned Assets shall be the same percentage as the percentage of major equipment owned by the Party in that substation as set forth in Exhibit 6 and its subsequent addendums. All generation-
related assets owned by the Local Distribution Company in a substation
will be included as a part of the Local Distribution Company’s assets in making this calculation. Responsibilities related to third-party owned generation-related assets will be split according to the nominal operating voltage at the point of connection of the generation circuit. At 120kV and above the third-party generation-related assets will be included as a part of the Transmission Provider’s assets for purposes of making this calculation. Below 120 kV the third-party generation-related assets will be included as a part of the Local Distribution Company’s assets for purposes of making this calculation.




Major equipment shall be defined as main power transformers, 23 kV, 46 kV, 138 kV, and 345 kV circuit breakers, power system regulators and reclosers, and 46 kV and 138 kV capacitor banks. (Any three-phase installation of such equipment shall count as a single unit). Exhibit 6 will be updated with an addendum at least annually by the Transmission Provider and approved in writing by the Local Distribution Company to show all changes in equipment ownership in the joint substations. The original Exhibit 6 and all addendums will be retained for future reference. In those substations where each Party owns assets each Party shall be financially responsible for its appropriate share of station power energy usage.
3.4    The Parties agree that the principles upon which the initial identification
was made of facilities as being either Transmission or Distribution (See the definitions of "Transmission" and "Distribution" in Section 1.1 of the Amended and Restated Easement Agreement dated April 29, 2002 between the Parties) shall continue to be applied for the future unless modification is agreed to by both Parties. Should future system modifications result in the reclassification of assets, the Parties agree to convey ownership of those assets to the appropriate Party. However, no such reclassification shall affect how the other Sections of this Agreement are applied until there is a change in ownership of the facilities involved and until any related changes are made to this Agreement and its exhibits. Upon such a change in ownership, the Planning Committee shall revise Exhibits 6 and/or 7 when needed to reflect the change in ownership. The conveyed facilities shall be priced at 1.18 times the seller’s net plant value but in any case shall not be less than zero dollars (i.e. no payment from seller to purchaser will occur as a result of net plant value being less than zero). As used herein, ”net plant value” shall mean the asset’s original cost depreciated according to the seller’s accepted accounting method. In addition, should either Party plan to abandon or otherwise take out of service any facilities which could be of use as part of the other Party’s system, it shall offer to convey to the other Party such facilities before they are taken out of service under the same pricing formula outlined above.
All types of conveyances discussed in this paragraph shall be subject to the following conditions:
(a)
The Planning Committee shall within 12 months of the Effective Date of this Agreement develop appropriate timeframes and procedures for accomplishing such conveyances.

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


Party proposing to do the modification shall consider the alternative and shall not unreasonably refuse to pursue the alternative instead of the original proposal.
(c)
Possible impediments to timely conveying the property in question (e.g. difficulty in getting release from the conveyor’s indenture) shall be referred to the Administrative




Committee. The Administrative Committee is authorized to modify the requirements of this Section with regard to such a specific proposed modification however it deems appropriate in light of the possible impediment and other circumstances.
3.5    Each Party shall operate any equipment that might reasonably be
expected to have impact on the operations of the other Party in a safe and efficient manner and in accordance with all applicable federal, state, and local laws, NERC operating practices, and Good Utility Practice, and otherwise in accordance with the terms of this Agreement. Each Party shall comply with the reasonable requests, orders, directives and requirements of the other Party, which are authorized under this Agreement.
3.6(a)
Without limiting the generality of Section 3.5, Local Distribution Company shall own, operate and maintain its Distribution System in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services of the Transmission System. The Local Distribution Company shall be responsible for the costs to repair or replace the Distribution System and Local Distribution Company’s Interconnection Equipment.
3.6(b)
Without limiting the generality of Section 3.5, Transmission Provider shall own, operate and maintain its Transmission System in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services of Local Distribution Company’s Distribution System. The Transmission Provider shall be responsible for the costs to repair or replace the Transmission System and Transmission Provider’s Interconnection Equipment.
3.6(c)
Without limiting the generality of Section 3.5, Local Distribution Company or Transmission Provider, as appropriate pursuant to Section 3.3 hereof, shall operate and maintain Jointly Owned Assets in a manner in accordance with Good Utility Practice to prevent degradation of voltage or services to either Party.
3.7(a)
Except during an Emergency, Local Distribution Company shall not, without prior Transmission Provider authorization, operate any Transmission Provider circuit, including transformer, line or bus elements.
Local Distribution Company shall retain the right to operate Transmission Provider equipment during an Emergency for imminent personnel safety threat, to prevent damage to equipment or to maintain the integrity of the Distribution System. When practical, prior to operation of such equipment, Local Distribution Company shall provide notice to the Transmission Provider. The Local Distribution Company shall not operate any Transmission System circuit if upon notice the Transmission Provider expressly refuses to grant permission to the Local Distribution Company. Within five (5) working days of such Emergency, Local Distribution Company shall provide written explanation of such Emergency to Transmission Provider.
3.7(b) Except during an Emergency, Transmission Provider shall not, without prior Local Distribution Company authorization, operate any Local Distribution Company circuit, including transformer, line or bus elements. Transmission Provider shall retain the right to operate Local Distribution Company equipment, during an Emergency for imminent personnel safety threat, to prevent damage to equipment or to maintain the integrity of the Transmission System. When practical, prior to operation of such equipment,




Transmission Provider shall provide notice to Local Distribution Company. Transmission Provider shall not operate any Distribution System circuit. If upon notice the Local Distribution Company expressly refuses to grant permission to the Transmission Provider. Within five (5) working days of such Emergency, Transmission Provider shall provide written explanation of such Emergency to Local Distribution Company.
3.7(c)
In an Emergency, joint facilities shall be operated by the Party able to first respond with Qualified Personnel.
3.8    Local Distribution Company and Transmission Provider shall design,
install, test, calibrate, set, and maintain their respective Protective Relay equipment in accordance with Good Utility Practice, applicable federal, state or local laws and this Agreement, as set forth in Article 6 hereof. In the case of jointly owned relaying equipment, the Party having direction and control pursuant to Section 3.3 hereof shall design, install, calibrate, set, and maintain Protective Relay equipment in accordance with Good Utility Practice. Without limiting the generality of Section 3.5(c) above, costs for such work will be split between the Companies on a predetermined ownership percentage basis as set forth in the then-current version of Exhibit 6.
3.9(a)
If Transmission Provider reasonably determines that (i) any of Local Distribution Company’s Interconnection Equipment fails to perform in a manner in accordance with Good Utility Practice or this Agreement, or (ii) Local Distribution Company has failed to perform proper testing or
maintenance of its Interconnection Equipment in accordance with Good Utility Practice or this Agreement, Transmission Provider shall give Local Distribution Company written notice to take corrective action. Such written notice shall be provided by Transmission Provider to Local Distribution Company's Representative as soon as practicable upon such determination. If Local Distribution Company fails to initiate corrective action promptly, and in no event later than seven (7) days after the delivery of such notification, and if in Transmission Provider’s reasonable judgment leaving Local Distribution Company’s Distribution System connected with Transmission System would create an Emergency or Network Security Condition, Transmission Provider may, with as much prior verbal notification to Local Distribution Company and Distribution System Control as practicable, open only the Interconnection Point(s) needing corrective action connecting the Local Distribution Company and Transmission Provider until appropriate corrective actions have been completed by Local Distribution Company, as verified by Transmission Provider. Prior to taking such action, Transmission Provider shall give appropriate consideration to the needs of the Local Distribution
Company’s end-use customers. Transmission Provider’s judgment with regard to an interruption of service under this paragraph shall be made in accordance with Good Utility Practice and subject to Section 3.1 hereto. In the case of such interruption, Transmission Provider shall immediately confer with Local Distribution Company regarding the conditions causing such interruption and its recommendation concerning timely correction thereof. Both Parties shall act promptly to correct the condition leading to such interruption and to restore the connection.
3.9(b)
If Local Distribution Company reasonably determines that (i) any of Transmission Provider’s Interconnection Equipment fails to perform in a manner in accordance with Good Utility Practice or this Agreement, or (ii) Transmission Provider has failed to perform




proper testing or maintenance of its Interconnection Equipment in accordance with Good Utility Practice or this Agreement, Local Distribution Company shall give Transmission Provider written notice to take corrective action. Such written notice shall be provided by Local Distribution Company to Transmission Provider’s Representative as soon as practicable upon such determination. If Transmission Provider fails to initiate corrective action promptly, and in no event later than seven (7) days after the delivery of such notification, and if in Local Distribution Company’s reasonable judgment leaving Transmission System connected with Local Distribution Company’s Distribution System would create an Emergency, Local Distribution Company may, with as much prior verbal notification to Transmission Provider and Distribution System Control as practicable, open only the Interconnection Point(s) needing corrective action connecting the Transmission Provider and Local Distribution Company until appropriate corrective actions have been completed by Transmission Provider, as
verified by Local Distribution Company. Local Distribution Company’s judgment with regard to an interruption of service under this paragraph shall be made in accordance with Good Utility Practice and subject to Section 3.1 hereto. In the case of such interruption, Local Distribution Company shall immediately confer with Transmission Provider regarding the conditions causing such interruption and its recommendation concerning timely correction thereof. Both Parties shall act promptly to correct the condition leading to such interruption and to restore the connection.
3.10    Outages
3.10.1 Outage Authority and Coordination. In accordance with Good Utility Practice, each Party            may, in close cooperation with the other, remove from service its system elements that            may impact the other Party’s system as necessary to perform maintenance or testing or            to replace installed equipment. Absent the existence of an Emergency, the Party                scheduling a removal of a system element from service will schedule such removal on a            date mutually acceptable to both Parties, in accordance with Good Utility Practice.
3.10.2 The Parties shall coordinate inspections, Planned Outages, and maintenance of their            respective equipment, facilities and systems so as to minimize the impact on the                availability, reliability and security of both Parties’ systems and operations when the            outage is likely to have a materially adverse impact on the other Party’s system or the            Local Distribution Company’s end-use customers. Subject to the confidentiality                provisions of Article 20, on or before October 1 of each year during the term hereof, the            Parties shall exchange non-binding Planned Outage schedules for the following calendar        year, which shall be developed and followed in accordance with Good Utility Practice, for        the Distribution System and Transmission System. The Parties shall communicate the            outage schedules as promptly as possible, provided that in no event shall such schedule        be provided less than fifteen (15) days prior to a Planned Outage. The Parties shall keep        each other updated regarding any changes to such schedules.
3.10.3 Unplanned Outages
3.10.3.1     Distribution System Unplanned Outage. In the event of an Unplanned                    Outage of a system element of the Distribution System adversely affecting                    the Transmission System, the Local Distribution Company will act in                        accordance with Good Utility Practice to promptly restore that system        




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

3.10.3.2     Transmission System Unplanned Outage. In the event of an Unplanned                Outage of a system element of the Transmission System adversely                    affecting the Local Distribution Company’s Distribution System, the                    Transmission Provider will restore the system to normal as soon as possible            unless the Transmission Provider obtains concurrence from the Local                Distribution Provider that some deferral is reasonable, and this concurrence            shall not be unreasonably withheld. The Transmission Provider shall plan                and maintain its Transmission System such that the average length of                Transmission System outages having a direct impact on customers of the                Local Distribution Company shall not exceed 166 minutes on an annual                basis. For any year in which the average outage duration exceeds this limit,            the Transmission Provider shall develop a plan to improve the outage                restoration process and reduce outages and shall obtain the Local                    Distribution Company’s concurrence with this plan. Within forty-eight hours                (48) of the beginning of any Unplanned Outage the Transmission Provider                shall provide the Local Distribution Company with a restoration plan. For                any 138 kV system outage it is expected that the system will be restored to            its normal configuration within seven (7) days; for any 345 kV system                outage it is expected that the system will be restored to its normal                    configuration within thirty (30) days. If it is expected that any Unplanned                Outage will exceed these limits the Transmission Provider shall provide the            Local Distribution Company with detailed information on measures being
taken to minimize the outage time.
3.10.4 Planned Outages
3.10.4.1     Distribution System Planned Outage. In the event of a Planned Outage of a                system element of the Distribution System adversely affecting the                        Transmission System, the Local Distribution Company will act in                        accordance with Good Utility Practice to promptly restore that system                    element to service in accordance with its schedule for the work that                        necessitated the Planned Outage.
3.10.4.2     Transmission System Planned Outage. The Transmission Provider shall                    review all Transmission System Planned Outages with the Local Distribution    




            Company. In the event of a Planned Outage of a system element of the                    Transmission System adversely affecting the Local Distribution Company’s                    Distribution System, the Transmission Provider will act in accordance with                    Good Utility Practice to promptly restore that system element to service in                    accordance with its schedule for the work that necessitated the Planned                    Outage.
3.11    The Parties shall use best efforts in accordance with Good Utility Practice to coordinate            operations in the event of any Forced or Planned Outage that affects the other Party’s            system.
3.12    Black Start Plan Participation. In accordance with Good Utility Practice, Local Distribution        Company agrees to participate in Transmission Provider’s Black Start Plan for the            Distribution System and the Transmission System, as well as any verification testing.
3.13    The Parties shall notify and make available in a timely manner, electric system modeling            information necessary for the other Party to monitor, analyze, and protect its facilities in a        real time environment, no less than 30 days prior to the energization of new or                 reconfigured network facilities.
ARTICLE 4. Supervisory Control and Data Acquisition, SCADA
4.1    If the Transmission Provider chooses to operate its own SCADA system, or to make            modifications or additions to the existing system, the following terms and conditions of            this Article 4 will apply.

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




Transmission Provider’s RTU or installation of a dual port RTU to provide data and control directly to the Transmission Provider within the Local Distribution Company’s substation. The Local Distribution Company will assist in furnishing desired inputs for the Transmission Provider’s RTU.
4.4    The operating metering system shall consist of instantaneous values of
MW, MVAR, and voltage.
4.4.1
Values shall be inputted to a RTU or comparable communication device for communication with the Party having Control Area responsibility.
4.4.2
Transducers may utilize the voltage transformers and current transformer secondary circuits also utilized by the revenue metering equipment for a particular interconnection. In such case, the performance criteria listed in Exhibit 4 of the Agreement, Metering Specifications, for the voltage transformers and the current
transformers, shall apply. Relaying class voltage transformers and or current transformers shall not be utilized unless mutually agreed between all the owners of the metering equipment and the Local Distribution Company.
4.4.3
Transducers shall have maximum 0.3% inaccuracy. Transducers shall be field calibrated as necessary but at least once every ten (10) years and documentation shall be retained showing the calibration results until next calibration.
4.4.4 Telemetry shall be maintained and calibrated such that overall inaccuracy of MW, MVAR, and voltage values is less than 1.0% of full scale.
4.5
To the extent new RTUs and associated communications equipment is to be installed, the Local Distribution Company shall install or facilitate installation of the RTU and associated communications equipment as soon as practicable, provided that installation shall be accomplished within a time period of no more than 270 days following notice by Transmission Provider or prior to commissioning of any new Interconnection Points.
ARTICLE 5. Revenue Metering
5.1    Transmission Provider shall own, operate, test and maintain any metering
equipment at the Interconnection Points, as required by this Article 5 not including any metering equipment owned by the Local Distribution Company for use in metering its end-use customers. Transmission Provider and Local Distribution Company agree that, as to all Interconnection Points in existence as of the Effective Date, no new or different metering equipment or arrangements shall be required. For existing Interconnection Points where low-side metering exists without loss compensation, the Parties will agree to adjust the metering data in such a manner to account for any real power losses between the location of the meter and the Interconnection Point. To the extent existing metering equipment is replaced and when new metering equipment is installed at Interconnection Points in existence as of the Effective Date, such replacements or installations shall meet the standards set in Section 5.2. Transmission Provider shall provide, install, own, operate, test and maintain the new metering equipment located at the Interconnection Points.




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

5.2.1    Metering shall be form 9, 3-element for 4-wire systems and form 5, 2-element for                3-wire systems.
5.2.2
Meters shall measure, at a minimum, megawatt hours and megavar hours and        have bi-directional capability, where applicable. All measured values shall have        individual outputs where applicable and a minimum 35-day interval data            recording capability for each measured value.
5.2.3    Whenever feasible, any new metering facilities shall be located at the same                physical location as the Interconnection Point. If it is not reasonable to have the                metering facilities and the Interconnection Point at the same physical location, the            metering data will be adjusted to account for real power losses between the                location of the meter and the Interconnection Point.
5.2.4
Transmission Provider shall maintain records that demonstrate compliance with        all meter tests and maintenance conducted in accordance with Good Utility        Practice for the life of the Interconnection Point. Local Distribution Company        shall have reasonable access to the records.
5.2.5    For installations where the metering is performed using loss compensation, the                factory certified test results of the power transformer, if available, including load,                no-load losses and calculated meter loss calculations, shall be recorded in a                written record. Local Distribution Company shall have reasonable access to the                records.
5.2.6    Transmission Provider shall maintain records of the factory certified test results, or            the utility test shop test results, showing compliance of the meters with the                    applicable metering test standards.
5.2.7
Transmission Provider’s Metering equipment shall be tested by Transmission            Provider at its own expense not less than once every year, unless an extension of        the testing cycle is agreed upon by the Parties. The accuracy of such metering            equipment shall be maintained by Transmission Provider in accordance with            applicable regulatory standards. At the request of either Party, special tests shall            be made. If any special meter test discloses the metering device to be registering            within acceptable limits of accuracy as specified herein, then the Party requesting            such special meter test shall bear the expense thereof. Otherwise, the expense of        such test shall be borne by the owner. Representatives of either Party shall be            afforded opportunity to be present at all routine or special tests and upon                occasions when any readings for purposes of settlements hereunder are taken            from meters not producing an automatic record.
5.2.8    If, as a result of any test, any meter shall be found to be registering more than two        (2) percent above or below one hundred (100) percent of accuracy, the account        




    between the Parties hereto shall be corrected for a period equal to one-half of the            elapsed time since the last prior test, according to the percentage of inaccuracy so        found, except that if the meter shall have become defective or inaccurate at a            reasonably ascertainable time since the last prior test of such meter, the correction        shall extend back to such time. No meter shall be left in service if found to be more        than two (2) percent above or below one hundred (100) percent of accuracy.            Should metering equipment at any time fail to register, the energy delivered shall            be determined from the best available data. All meters shall be kept under seal,            such seals to be broken only when the meters are to be tested or adjusted.
5.2.9    Test switches shall be installed to allow independent testing and/or replacement of        each meter and transducer utilizing the secondary circuit so as not to interrupt the        operation of other devices utilizing the secondary circuit.
5.2.10 In substations where an RTU or other remote data collecting and
telecommunication device is present, meters shall have form C, 3-wire outputs with programmable values determined by the Transmission Provider for bi-directional MWHs and MVARs.
5.2.11
In the event an interconnection meter needs replacement or repair, a representative from Local Distribution Company shall be given a reasonable opportunity to be present during such repair or replacement.
ARTICLE 6. Protective Relaying and Control
6.1    Transmission Provider and the Local Distribution Company shall, in
accordance with Good Utility Practice, coordinate, review and approve all new Protective Relaying equipment, including equipment settings, Protective Relay schemes, drawings, and functionality associated with each Interconnection Point. Protective Relaying equipment and schemes installed before the date of this agreement shall be considered to satisfy
the terms and conditions of this Article 6. When existing equipment or schemes are replaced or when new equipment or schemes are installed per this Article 6 or in association with new Interconnection Points, then the terms and conditions of Article 6 shall apply. Each Party shall incur the expense for the work on its system.
6.2    To the extent that there is generation on the Distribution System which, in
the reasonable judgment of either Party, may contribute material amounts of current to a fault on the Transmission System, the Local Distribution Company shall have and enforce standards to ensure the provision, installation and maintenance of relays, circuit breakers, and all other devices necessary to promptly remove any fault contribution of such generation to any short circuit occurring on the Transmission System and not otherwise isolated by the Transmission Provider equipment. Such standards will be included in the Local Distribution Company’s connection requirements for generation. Transmission Provider and Local Distribution Company shall not be responsible for protection of such generation.
6.3    Transmission Provider shall own, operate, maintain and test those Protective Relay            Systems that control their breakers or equivalent protective devices. Local Distribution        




    Company shall own, operate, maintain, and test those Protective Relay Systems that            control their breakers or equivalent protective devices governed by this Article 6. The            Parties shall maintain, and, as necessary, upgrade their respective Protective Relay            Systems and shall provide the other Party with access to available copies of operation            and maintenance manuals and test records for all relay equipment upon request. The            Transmission Provider will provide protective relay settings for the relays that control            breakers or equivalent protective devices owned by the Local Distribution Company that            also protect Transmission Provider’s equipment. The Local Distribution Company will            review and apply the settings.
6.4
The owner (Transmission Provider or Local Distribution Company) of the line will provide the relay communication channel necessary for line protection at its expense. Owner will participate with other Party to test communication schemes upon request without charge.
6.5    The Parties shall test their respective relays associated with the
Interconnection Points for correct calibration and operation. Parties shall coordinate design, installation, operation, and testing of Protective Relay schemes to insure that such relays operate in a coordinated manner so as to not cause adverse operating conditions on the other Party’s system.
6.6    Local Distribution Company shall be responsible for Protective Relay
maintenance, calibration and functional testing of relay systems that protect Local Distribution Company’s equipment associated with the
Interconnection Points and that protect Transmission Provider from Local Distribution Company’s Interconnection Equipment to the extent such calibration and testing are in accordance with Good Utility Practice. All such maintenance and testing must be performed by Qualified Personnel selected by the Local Distribution Company. In addition, Local Distribution Company shall allow Transmission Provider to conduct visual inspection of all Protective Relays and associated maintenance records directly related to the interconnection. Related maintenance and operational records shall be maintained by the Local Distribution Company in accordance with Good Utility Practice. Upon completion of Protective Relay calibration testing and relay functional testing, Local Distribution Company shall make available copies of test reports and related records for review by Transmission Provider upon request. Local Distribution Company shall review test reports and document that Protective Relay System’s tests and settings, as shown on such test reports, have been done in accordance with the equipment’s specifications and Good Utility Practice.
6.7(a)
As Transmission Provider’s system protection requirements change, Transmission Provider will upgrade its Protective Relaying System in accordance with Good Utility Practice. If these upgrades affect the serviceability and acceptability of the Protective Relaying Systems on the Interconnection Equipment which may be installed, owned, and operated by Local Distribution Company, the Local Distribution Company must upgrade its Protective Relay Systems at its expense (unless such modifications are required in association with the addition of generation to the system in which case Section 9.8 shall apply) as necessary to bring them into compatibility with that installed by Transmission Provider. Transmission Provider shall give Local Distribution Company notice of such upgrade as soon as practicable prior to the anticipated date of such upgrade. Any




proposed protective system upgrades shall be reviewed by the Planning Committee in accordance with Section 7.3 (vi) hereof.
6.7(b)
As Local Distribution Company’s system protection requirements change, Local Distribution Company will upgrade its Protective Relaying System in accordance with Good Utility Practice. If these upgrades affect the serviceability and acceptability of the Protective Relaying Systems on the Interconnection Equipment which may be installed, owned, and operated by Transmission Provider, Transmission Provider must upgrade its Protective Relaying Systems at its expense (unless such modifications are required in association with the addition of generation to the system in which case Section 9.8 shall apply) as necessary to bring them into compatibility with that installed by Local Distribution Company. Local Distribution Company shall give Transmission Provider notice of such upgrade as soon as practicable prior to the anticipated date of such
upgrade. Any proposed protective system upgrades shall be reviewed by
the Planning Committee in accordance with Section 7.3 (vi) hereof.
6.8    Local Distribution Company shall provide necessary space to install or
expand relay panels for substation system protection if requested by Transmission Provider. Any incremental costs required to accommodate
such request shall be the responsibility of the Transmission Provider.
6.9    Transmission Provider shall provide the necessary space to install or
expand relay panels for substation system protection if requested by Local Distribution Company. Any incremental costs required to accommodate such request shall be the responsibility of the Local Distribution Company.
6.10     Each Party will provide access to the other to fault recorder, sequence of
events and relay information such as dial up access of digital relays.
ARTICLE 7. Planning and Obligation to Serve
7.1    Adequacy Obligation. Subject to applicable regulatory approvals,
including adherence to Least-Cost planning requirements and principles, adherence to applicable NERC, ECAR or other regional reliability council or successor organization’s reliability requirements, and all other applicable operating reliability criteria and subject to the oversight and direction of the appropriate RTO or ISO, the Transmission Provider shall operate, maintain, plan and construct its Transmission System in accordance with Good Utility Practice in order to:
(i)
deliver on a reliable basis the projected capacity and energy needs of all loads served by the Local Distribution Company’s Distribution System and dependent upon the Transmission Provider’s facilities for delivery of such energy to the Distribution System;
(ii)
provide needed support to the Local Distribution Company where a transmission addition is the Least-Cost electric solution to an improvement need, including but not limited to, the reliability needs of the Local Distribution Company; and
(iii)
deliver energy from both existing and new generating facilities connected to and dependent upon Transmission Provider’s transmission of such energy
7.2     With regard to planning and construction of projects which affect Local




Distribution Company and Local Distribution Company’s load-serving area, the Parties shall develop methods and procedures covering at least the following areas:
(i)
coordination between short-term and long-term distribution and transmission planning;
(ii)
developing and sharing computer simulation models needed to support Transmission Provider and Local Distribution Company planning activities;
(iii)
coordination of permitting (including local and state approvals) and siting;
(iv)
engineering and scheduling of new projects;
(v)
construction and inspection standards;
(vi)
information-sharing and priority-setting; and
(vii)
health and safety issues.
7.3     With respect to Local Distribution Company’s load-serving area, the
Planning Committee, shall:
(i)
implement the methods and procedures developed pursuant to Section 7.2;
(ii)
review planning studies and reports regarding projects needed or proposed for the area in the next five (5) years, or as determined by the Planning Committee;
(iii)
recommend additional studies or evaluation of plans;
(iv)
follow Least-Cost planning principles in recommending specific projects;
(v)
at least once every year, prepare a planning report which shall include in priority order a list of projects proposed by either Party for the next year, the estimated costs of such projects, and the timetable for such projects, including the in-service date; and
(vi)
review proposed programmatic changes to the electric system, including protective system upgrades
7.4    If the Parties agree upon the need for any such project, they shall
cooperate and coordinate in seeking all necessary regulatory approvals for such project. Transmission Provider shall coordinate and cooperate with Local Distribution Company with respect to all communications and commitments to municipal, county, and state agencies involved in such project.
7.5    If Local Distribution Company proposes construction of a transmission
project and Transmission Provider does not agree that such project is needed, Local Distribution Company shall have the right to petition an appropriate RTO, ISO or applicable regulatory agency for a declaratory ruling on whether the proposed project is needed pursuant to Transmission Provider’s public-utility duty to plan and construct a reliable, adequate Transmission System.
7.6    Load Growth and Reliability Needs. Transmission Provider is obligated
to plan and install any Transmission System components that may be necessary, as determined by a Least-Cost planning process in accordance with Section 7.1 and consistent with the established and consistently applied reliability criteria of the Parties, to accommodate Local Distribution Company’s planned load growth and planned reliability improvements. Transmission Provider will construct new interconnections to Local Distribution Company facilities in accordance with Transmission Provider’s planning criteria, other agreements in effect between the Parties, and Good Utility Practice. Transmission Provider shall bear the responsibility for such planning and installing in accordance with this Article 7. Transmission Provider’s obligations under this Section 7.6 shall include the planning and installation of any new Interconnection Points




that may be necessary to accommodate Local Distribution Company’s planned load growth and planned reliability improvements. Recovery of the cost of such additions shall be in accordance with the OATT or other applicable tariff.
7.7    Local Distribution Company shall be the first point of contact and the
wire-services provider for end-use customers.
7.8    Transmission Provider shall annually submit to Local Distribution
Company, no later than February 1 of each year:
(i) Transmission Provider’s plans covering the next five (5) years, or as determined by the Planning Committee, for installing Transmission System components that may be necessary to accommodate Local Distribution Company’s planned load growth and reliability improvements as described in Section 7.6. Transmission Provider’s plans shall include, but not be limited to,
cost estimates and installation schedules for Transmission System components, and shall provide specific detail sufficient to allow Local Distribution Company to compare Transmission Provider’s plans with Local Distribution Company’s in-service requirements to meet its planned load growth and reliability needs.
(i)
A description of any changes to the Local Distribution Company’s Distribution System that may be needed to accommodate Transmission Provider’s plans set forth in Section 7.8(i) will be requested by the Transmission Provider.
(ii)
Projected voltage levels under Normal System Conditions and Transmission Provider’s FERC 715 Planning criteria conditions at anticipated annual peak load and 80% of anticipated annual peak load for each Interconnection Point with planned additions for the next five (5) years, or as determined by the Planning Committee.
7.9     Local Distribution Company shall annually submit to Transmission
Provider,
(a)
no later than December 1 of each year, the most recent actual summer and winter demands in megawatts (MW) and megavars (Mvar) for all Interconnection Points connected to the Transmission System at the time of the Transmission Provider’s most recent seasonal system peaks (Transmission Provider must provide the Local Distribution Company the day and hour of such peak no later than September 1); and
(b)
no later than February 1 of each year:
(i)
annual peak demand forecasts in MW for each Local Distribution Company Interconnection Point to the Transmission System for the next five (5) years, or as determined by the Planning Committee, together with corresponding projected power factors; and
(ii)
planned facility (new Interconnection Points) connections to the Transmission System for the next five (5) years, or as determined by the Planning Committee.
ARTICLE 8. Transmission Service Level
8.1     Subject to applicable regulatory approvals, including adherence to Least‑




Cost planning requirements and principles, adherence to applicable NERC, ECAR or other regional reliability council or successor organization’s reliability requirements, and all other applicable operating reliability criteria and subject to the oversight and direction of the appropriate RTO or ISO, the Transmission Provider shall operate, maintain, plan and construct its Transmission System in accordance with Good Utility Practice to provide the following service levels:
(i)
A minimum Steady-State Voltage of 0.97 Per Unit (PU) at all Interconnection Points with Local Distribution Company with all influential Transmission Provider facilities in service (no contingency conditions);
(ii)
A minimum Steady-State Voltage of 0.92 PU at all Interconnection Points with the Local Distribution Company influenced by one or more Transmission Provider facilities out of service (contingency conditions);
(iii)
A maximum Steady-State Voltage of 1.05 PU at all Interconnection Points with the Local Distribution Company during all operating conditions;
(iv)
An adequate Transmission System that shall not load Local Distribution Company facilities above normal ratings during peak load conditions with all influential Transmission Provider facilities in service (no contingency conditions);
(v)
An adequate Transmission System that shall not load Local Distribution Company facilities above emergency ratings during peak load conditions with one or more influential Transmission Provider facilities out of service (contingency conditions);
(vi)
On a three-year rolling average, experience no more than 0.357 Momentary Outage Events per 138 kV line protective zone (system average) and 0.743 Momentary Outage Events per 345 kV line protective zone (system average) per year. As used in this Article 8 the term “year” shall mean calendar year; and the term “line protective zone” is illustrated and defined as follows: Any given electrical fault on a transmission line will trip specific circuit breakers in a normally functioning system. All of the possible line fault locations that will trip these specific circuit breakers constitute the same line protective zone. Physically, a line protective zone consists of the conductors located between the current transformers that provide sensing to trip the circuit breakers for a line fault;
(i)
Experience no more than three (3) Momentary Outage Events on any given 138 kV line protective zone and two (2) Momentary Outage Events on any given 345 kV line protective zone per year;
(ii)
On a three-year rolling average, experience no more than 0.21 Unplanned Outages per 138 kV line protective zone (system average) and 0.18 Unplanned Outages per 345 kV line protective zone (system average) per year;
(iii)
Experience no more than four (4) Unplanned Outages on any given 138 kV line protective zone and three (3) Unplanned Outages on any given 345 kV line protective zone per year;
(iv)
Should the Transmission Provider fail to meet any of the requirements of Section 8.1(vi) or 8.1(viii) by more than 10% two years in a row, the Transmission Provider shall pay, as liquidated damages and not as a penalty, to the Local Distribution Company, an amount equal to one half of one percent (0.5%) of the annual revenue paid by the Local Distribution Company under the applicable transmission tariff; such liquidated damages amount shall be based upon the revenue received in the second year of such failure. Such liquidated damages amount shall be increased by one half of a percent (0.5%) for each additional 10% by which the Transmission Provider fails to meet the any of the given outage targets, up to a maximum of 4.0% of the annual revenue. Outage events affecting 15% or more of transmission line protective zones within a 24-




hour period will not be counted toward the requirements of Section 8.1.
If transmission service does not meet the requirements of this Article 8, Transmission Provider shall present an action plan acceptable to the Local Distribution Company within sixty (60) days of non-compliance of this Article 8 to restore transmission service to the minimum standards as described in this Article 8 in a timely manner. Should the Transmission Provider fail to correct the deficiency(s) within one year of notification from the Local Distribution Company, the Local Distribution Company shall have the right to take corrective action at the Transmission Provider’s expense. The Local Distribution Company shall defer taking such actions for corrective measures normally requiring longer than one year to complete, provided the Transmission Provider is diligently pursuing such measures.
8.2     Should the Michigan Public Service Commission (MPSC) adopt service
     quality standards that the Local Distribution Company must meet that are more             stringent than current historical performance; and should the transmission service         level provided by the Transmission Provider directly or indirectly influence the Local         Distribution Company’s ability to meet such standards, the Local Distribution              Company will promptly notify the Transmission Provider of such proposal and the         Transmission Provider shall have an opportunity to participate either as a party or in
cooperation with the Distribution Company, in any related MPSC hearings or          proceedings. Subject to the foregoing and to any required approval by FERC, the Transmission Provider shall be responsible for meeting its proportional share of the adopted service quality standard and for any penalties that might be assessed if the standards are not met.
8.3     Transmission Provider shall be responsible for those compensable
disruptions/interruptions caused by the Transmission Provider’s Transmission System to those Local Distribution Company customers under Special Manufacturing Contracts in existence at the time of execution of this document as set forth in Exhibit 3, including any contractual payments due.
ARTICLE 9. New Construction and Modification
9.1    Subject to this Article 9, Transmission Provider may construct additional                    Transmission System elements or modify the existing Transmission System and Local            Distribution Company may construct additional Distribution System elements or modify            the existing Distribution System. All such modifications and construction provided for            herein, shall be conducted in accordance with Good Utility Practice and all applicable            NERC and ECAR Standards. The Party that modifies the system elements or constructs            new system elements is obligated to maintain the transmission, distribution and                communications capabilities of the other Party in accordance with Good Utility Practice            to avoid or minimize any adverse impact on the other Party. The Parties shall look to the            operating history of the Local Distribution Company in the relevant geographic area prior        to the Effective Date of this Agreement, where available, in determining what constitutes            Good Utility Practice.
9.2    Notwithstanding the foregoing, no modifications to or new construction of facilities or        




    access thereto, including but not limited to rights-of-way, fences, and gates, shall be            made by either Party which might reasonably be expected to have a material effect upon        the other Party with respect to operations or performance under this Agreement, without            providing the other Party with sufficient information regarding the work prior to                commencement to enable such Party to evaluate the impact of the proposed work on its            operations. The information provided must be of sufficient detail to satisfy reasonable            Transmission Provider or Local Distribution Company review and operational                requirements. Each Party shall use reasonable efforts to minimize any adverse impact on        the other Party.
9.3    If any Party intends to install any new facilities, equipment, systems, or circuits or any            modifications to existing or future facilities, equipment, systems or circuits that could            reasonably be expected to have a material effect upon the operation of the other Party,            the Party desiring to perform said work shall, in addition to the requirements of Section            9.2, provide the other Party with drawings, plans, specifications and other necessary            documentation for review at least 60 days prior to the start of the construction of any such        installation. This notice period shall not apply to modifications or new installations made            to resolve or prevent pending Emergency or Network Security Conditions.
9.4    The Party reviewing any drawings, plans, specifications, or other necessary                documentation for review shall promptly review the same and provide any comments to            the performing Party no later than 30 days prior to the start of the construction of any            installation. Unless system modifications are required in association with the addition of            generation to the system (in which case Section 9.8 hereof shall apply) all such reviews            shall be performed at no cost to either Party. The performing Party shall incorporate all            requested modifications to the extent required in accordance with Good Utility Practice            and compliance with this Agreement.
9.5    Within 180 days following placing in-service of any modification or construction subject to        this Article 9, the Party initiating the work shall provide “as built” drawings, plans and            related technical data to the other Party. Approval or review of any document referenced            herein shall not relieve the initiating Party of its responsibility for the design or                construction of any proposed facility, nor shall it subject the other Party to any liability,            except with respect to the confidentiality provisions of Article 20.
9.6    Each Party shall, at its own expense, have the right to inspect or observe all maintenance        activities, equipment tests, installation work, construction work, and modification work to            the facilities of the other Party that could have a material effect upon the facilities or            operations of the first Party.
9.7    Construction and installation of any facility shall meet all or exceed all environmental            permitting requirements, reviews or approvals as required by Federal, State or local law            prior to the installation of such facilities. The Parties agree to coordinate environmental            permitting related activities such as site review for regulated resources, permit application        and project oversight (e.g. monitoring as applicable).
9.8    Whenever system modifications are required to connect generating facilities to either the        Local Distribution Company’s or the Transmission Provider’s system it is expected that            the party installing the generating facilities will normally be responsible for much or all of        




    the associated costs. The Parties agree to cooperate in sharing information regarding            such projects and to individually make arrangements with the party adding the generation        to obtain payment of all related costs as appropriate.
ARTICLE 10. Access to Facilities
10.1    The Parties hereby agree to provide each other reasonable access to their respective            property as may be necessary and appropriate to enable each Party to operate and            maintain its respective facilities and equipment on such property. Such right of access            shall be provided in a manner so as not to unreasonably interfere with either Party’s            ongoing business operations, rights, and obligations.
10.2    Each Party shall provide the other Party keys, access codes or other access methods            necessary to enter the other Party’s facilities to exercise rights under this Agreement.            Access shall only be granted to Qualified Personnel.
ARTICLE 11. Notifications and Reporting
11.1    Unless otherwise provided, any notice required to be given by either Party to the other            Party in connection with this Agreement shall be given in writing: (a) personally; (b) by            facsimile transmission (if sender thereafter sends such notice to recipient by any of the            other methods provided in this Section 11.1; (c) by registered or certified U.S. mail, return        receipt requested, postage prepaid; or (d) by reputable overnight carrier, with                acknowledged receipt of delivery; or (e) any other method mutually agreed by the Parties        in writing. Notice shall be deemed given on the date of receipt personally. Notice sent by            facsimile shall be deemed given on the date the transmission is confirmed by sender’s            facsimile machine, so long as the facsimile is sent on a business day during normal            business hours of the recipient. Otherwise, the notice shall be deemed given on the next        succeeding business day. Notice provided by mail or overnight courier shall be deemed            given at the date of acceptance or refusal of acceptance shown on such receipt.
11.2    Notice to the Transmission Provider shall be to the Transmission Provider’s                Representative, at the addresses identified in Exhibit 2. Notice to the Local Distribution            Company shall be to the Local Distribution Company’s Representative, at the addresses            identified in Exhibit 2.
11.3    Each Party shall provide prompt notice describing the nature and extent of the condition,        the impact on operations, and all corrective action, to the other Party of any Emergency            or Network Security Condition which may be reasonably anticipated to affect the other            Party’s equipment, facilities or operations. Either Party may take reasonable and                necessary action, both on its own and the other Party’s system, equipment, and facilities,        to prevent, avoid or mitigate injury, danger, damage or loss to its own equipment and            facilities, or to expedite restoration of service; provided however, that the Party taking            such action shall give the other Party prior notice, if at all possible, before taking any            action on the other Party’s system, equipment, or facilities.
11.4    In the event of an Emergency or Network Security Condition contemplated by Section            11.3, each Party shall provide the other with such information, documents, and data        




    necessary for operation of the Transmission System and Distribution System, including,            without limitation, such information which is to be supplied to any Governmental Authority,        NERC, ECAR, or Transmission System Operations Center or Distribution System Control        Center.
11.5    In order to continue interconnection of the Distribution System and Transmission System,        each Party shall promptly provide the other Party with all relevant information,                documents, or data regarding the Distribution System and the Transmission System that            would be expected to affect the Distribution System or Transmission System, and which            is reasonably requested by NERC, ECAR, or any Governmental Authority.
11.6.    For routine maintenance and inspection activities on either Parties system that will             require major equipment or system outages, and could impact the other Party’s                system, the Party performing the same shall provide the other Party with not less                than seventy-two (72) hours prior notice, if practicable; provided that the provisions            of Section 3.9 remain applicable to the outages, and said notice is in addition to, and            does not substitute for, the requirements of Section 3.9 (maintenance and inspection            activities in generating plant substations require 20 working days notification).
11.7    Transmission Provider shall notify Local Distribution Company prior to entering Local            Distribution Company’s facilities for routine measurements, inspections and meter reads            in accordance with the requirements of Section 11.6. Local Distribution Company shall            notify Transmission Provider prior to entering Transmission Provider’s facilities, including        switchyards, for routine maintenance, operations, measurements, inspections and meter        reads, in accordance with the requirements of Section 11.6.
11.8    Each Party shall provide prompt verbal notice to the other Party of any system alarm that        applies to the other Party’s equipment, unless the system alarm is automatically sent to            the other Party.
11.9    Each Party shall provide a report or a copy of the data from a system events recorder,            SCADA system sequence of events or digital fault recorder that applies to the other            Party’s equipment.
11.10 Each Party agrees to immediately notify the other Party verbally, and then in writing, of any labor dispute or anticipated labor dispute of which its management has actual         Knowledge that might reasonably be expected to affect the operations of the other Party with respect to this Agreement.
ARTICLE 12. Safety
12.1    Each Party agrees that all work performed by either Party that may reasonably be            expected to affect the other Party shall be performed in accordance with Good Utility            Practice and all applicable laws, regulations, safety standards, practices and procedures        and other requirements pertaining to the safety of Persons or property, (including, but not        limited to those of the Occupational Safety and Health Administration, the National            Electrical Safety Code and those developed or accepted by Transmission Provider and            Local Distribution Company for use on their respective systems) when entering or            working in the other Party’s property or facilities or switching area. A Party performing        




    work within the boundaries of the other Party’s facilities must abide by the safety rules            applicable to the site.
12.2    Each Party shall be solely responsible for the safety and supervision of its own                employees, agents, representatives, and subcontractors.
12.3    Transmission Provider shall immediately report any injuries that occur while working on            the Local Distribution Company’s property or facilities or switching area to appropriate            agencies and the Local Distribution Company’s Site Representative. Local Distribution            Company shall immediately report any injuries that occur while working on the                Transmission Provider’s property or facilities or switching area to appropriate agencies            and the Transmission Provider’s Site Representative. Each Party will provide the other            with its clearing/tagging/lockout procedures. For clearances requested or initiated by the            Local Distribution Company on the Local Distribution Company’s equipment that utilizes            the Transmission Provider’s equipment as an isolation device, Local Distribution                Company procedures shall govern. For clearances requested or initiated by the                Transmission Provider on the Transmission Provider’s’ equipment that utilizes the Local            Distribution Company’s equipment as an isolation device, Transmission Provider                procedures shall govern. Under no circumstances shall either Party remove the other            Party’s protective tags without proper authorization.
ARTICLE 13. Environmental Compliance and Procedures
13.1    Release Prevention and Response. Each Party shall notify the other Party, verbally within        24 hours upon discovery of any Release of any Regulated Substance caused by the            Party’s operations or equipment that impacts the property or facilities of the other Party,            or which may migrate to, or adversely impact the property, facilities or operations of the            other Party and shall promptly furnish to the other Party copies of any reports filed with            any governmental agencies addressing such events. Such verbal notification shall be            followed by written notification within five (5) days. The Party responsible for the Release        of any Regulated Substance on the property or facilities of the other Party, or which may            migrate to, or adversely impact the property, facilities or operations of the other Party            shall be responsible for: (1) the cost and completion of reasonable remediation or                abatement activity for that Release, and; (2) required notifications to governmental            agencies and submitting of all reports or filings required by environmental laws for that            Release. Advance written notification (except in Emergency situations, in which verbal,            followed by written notification, shall be provided as soon as practicable) shall be                provided to the other Party by the Party responsible for any remediation or abatement            activity on the property or facilities of the other Party, or which may adversely impact the            property, facilities, or operations of the other Party. Except in Emergency situations such            remediation or abatement activity shall be performed only with the consent of the Party            owning the affected property or facilities.
13.2    The Parties agree to coordinate, to the extent necessary, the preparation of site plans,            reports, environmental permits, clearances and notifications required by federal and state        law or regulation, including but not limited to Spill Prevention, Control and                    Countermeasures (SPCC), Storm Water Pollution Prevention Plans (SWPP), Act 451 Part        31 Part 5 Rules, CERCLA, EPCRA, TSCA, soil erosion and sedimentation control plans            (SESC) or activities, wetland or other water-related permits, threatened or endangered        




    species reviews or management and archeological clearances or notifications required by        any regulatory agency or competent jurisdiction. Notification of permits applied for and/or        received will occur in a timeframe manner suitable to the interests of both Parties.
ARTICLE 14. Billings and Payment
14.1    Any invoices payable under this Agreement shall be provided to the other Party under this        Agreement during the preceding month. Invoices shall be prepared within a reasonable            time after the first day of each month. Each invoice shall delineate the month in which            services were provided, shall fully describe the services rendered and shall be itemized to        reflect the services performed or provided. The invoice shall be paid within twenty (20)            days of the invoice date, or the first business day thereafter if the payment date falls on            other than a business day. All payments shall be made in immediately available funds            payable to the other Party, or by wire transfer to a bank of the Party being paid, provided        that payments expressly required by this Agreement to be mailed shall be mailed in            accordance with Section 14.2.
14.2    Any payments required to be made by Local Distribution Company under this Agreement        shall be made to Transmission Provider at the following address:
Michigan Electric Transmission Company, LLC P.O. Box 673971
Detroit, MI 48267-3971

Any payments required to be made by Transmission Provider under this Agreement shall be made to Local Distribution Company at the following address:
Consumers Energy Company
One Energy Plaza Jackson, MI 49201 Attention: Treasurer

14.3    The rate of interest on any amount not paid when due shall be equal to the Interest Rate            in effect at the time such amount became due. Interest on delinquent amounts shall be            calculated from the due date of the invoice to the date of the payment. When payments            are made by mail, invoices shall be considered as having been paid on the date of receipt        by the other Party. Nothing contained in this article is intended to limit either Party’s            remedies under Article 21 of this Agreement.
14.4    Payment of an invoice shall not relieve the paying Party from any responsibilities or            obligations it has under this Agreement, nor shall such payment constitute a waiver of            any claims arising hereunder.
14.5    If all or part of any bill is disputed by a Party, that Party shall promptly pay the amount            that is not disputed and provide the other Party a reasonably detailed written explanation        of the basis for the dispute pursuant to Article 26. While the dispute is being resolved, the        Parties shall continue to provide services and pay all invoiced amounts not in dispute.            Following resolution of the dispute, the prevailing Party shall be entitled to receive the            disputed amount, as finally determined to be payable, along with interest accrued at the        




    Interest Rate through the date on which payment is made, within ten (10) business days            of such resolution.
14.6    Subject to the Confidentiality provisions of Article 20, within two (2) years following a            calendar year, during normal business hours, Local Distribution Company and                Transmission Provider shall have the right to audit each other’s accounts and records            pertaining to transactions under this Agreement that occurred during such calendar year            at the offices where such accounts and records are maintained; provided that the audit            shall be limited to those portions of such accounts and records that reasonably relate to            the services provided to the other Party under this Agreement for said calendar year. The        Party being audited shall be entitled to review the audit report and any supporting                materials. To the extent that audited information includes Confidential Information, the            auditing Party shall keep all such information confidential pursuant to Article 20.
14.7    Neither Party shall be responsible for the other Party’s costs of collecting amounts due            under this Agreement, including attorney fees and expenses and the expenses of                arbitration.

ARTICLE 15. Applicable Regulations and Interpretation
15.1    Each Party’s performance under this Agreement is subject to the condition that all            requisite governmental and regulatory approvals for such performance are obtained in            form and substance satisfactory to the other Party in its reasonable judgment. Each Party        shall exercise Due Diligence and shall act in good faith to secure all appropriate                approvals in a timely fashion.
15.2    This Agreement and all rights, obligations, and performances of the Parties hereunder,            are subject to present or future state or federal laws, regulations, or orders properly            issued by state or federal bodies having jurisdiction. When not in conflict with or                 pre-empted by Federal law, this Agreement shall be interpreted pursuant to the laws of            the State of Michigan, exclusive of its conflicts of law principles.
ARTICLE 16. Force Majeure
16.1    An event of Force Majeure means any act of God, labor disturbance, act of the public            enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to            machinery or equipment, any curtailment, order, regulation or restriction imposed by            governmental military or lawfully established civilian authorities, or any other cause            beyond a Party’s reasonable control. A Force Majeure event does not include an act of            negligence or intentional wrongdoing.
16.2    If either Party is rendered unable, wholly or in part, by Force Majeure, to carry out its            obligations under this Agreement, then, during the continuance of such inability, the            obligation of such Party shall be suspended except that Transmission Provider’s and            Local Distribution Company’s obligation under Section 16.3 of this Agreement to provide            protection shall not be suspended. The Party relying on Force Majeure shall give written            notice of Force Majeure to the other Party as soon as practicable after such event occurs.        Upon the conclusion of Force Majeure, the Party heretofore relying on Force Majeure            shall, with all reasonable dispatch, take all necessary steps to resume the obligation        




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

ARTICLE 17. Indemnification And Limitation on Liability
17.1    Each Party shall at all times assume all liability for, and shall indemnify and save the            other Party harmless from any and all damages, losses, claims, demands, suits,                recoveries, costs, legal fees, expenses for injury to or death of any Person or Persons            whomsoever, or for any loss, destruction of or damage to any property of third persons,            firms, corporations or other entities that occurs on its own system and that arises out of or        results from, either directly or indirectly, its own facilities or facilities controlled by it,            unless caused by the sole negligence, or intentional wrongdoing, of the other Party.
17.2
EXCEPT AS SET FORTH IN SECTION 8.3, NEITHER PARTY SHALL BE LIABLE TO THE OTHER FOR ANY SPECIAL, INCIDENTAL, EXEMPLARY, PUNITITIVE OR CONSEQUENTIAL DAMAGES SUCH AS, BUT NOT LIMITED TO, LOST PROFITS, REVENUE OR GOOD WILL, INTEREST, LOSS BY REASON OF SHUTDOWN OR NON-OPERATION OF EQUIPMENT OR MACHINERY, INCREASED EXPENSE OF OPERATION OF EQUIPMENT OR MACHINERY, COST OF PURCHASED OR REPLACEMENT POWER OR SERVICES OR CLAIMS BY CUSTOMERS, WHETHER SUCH LOSS IS BASED ON CONTRACT, WARRANTY, NEGLIGENCE, STRICT LIABILITY OR OTHERWISE.
ARTICLE 18. Insurance
18.1    The Parties agree to maintain, at their own cost and expense, the following insurance            coverages for the life of this Agreement in the manner and amounts, at a minimum, as set        forth below:
(a)
Workers’ Compensation Insurance in accordance with all applicable State, Federal, and Maritime Law.
(b)
Employer’s Liability insurance in the amount of $1,000,000 per accident.
(c)
Commercial General Liability or Excess Liability Insurance in the amount of $25,000,000 per occurrence.
(d)
Automobile Liability Insurance for all owned, non-owned, and hired vehicles in the amount of $5,000,000 each accident.
18.2
A Party may, at its option, [A] be an approved self-insurer by the State of Michigan for the insurances required in 1.(a) and (d); and [B] maintain such deductibles and/or retentions under the insurance required in 1.(b) and (c) as is maintained by other similarly situated companies engaged in a similar business. The Parties agree that all amounts of self-insurance, retentions and/or deductibles are the responsibility of, and shall be borne by, the Party whom makes such an election.
18.3
Within fifteen (15) days of the Effective Date and thereafter when requested, in writing, but not more than once every 12 months, during the term of this Agreement (including any extensions) each Party shall provide to the other Party properly executed and




current certificates of insurance or evidence of approved self-insurance status with respect to all insurance required to be maintained by such Party under this Agreement. Certificates of insurance shall provide the following information:
(a)
Name of insurance company, policy number and expiration date.
(b)
The coverage maintained and the limits on each, including the amount of deductibles or retentions, which shall be for the account of the Party maintaining such policy.
(c)
The insurance company shall endeavor to provide thirty (30) days prior written notice of cancellation to the certificate holder.

ARTICLE 19. Several Obligations
19.    Except where specifically stated in this Agreement to be otherwise, the duties, obligations        and liabilities of the Parties are intended to be several and not joint or collective. Nothing        contained in this Agreement shall ever be construed to create an association, trust,            partnership, or joint venture or to impose a trust or partnership duty, obligation or liability            or agency relationship on or with regard to either Party. Each Party shall be individually            and severally liable for its own obligations under this Agreement.
ARTICLE 20. Confidentiality
20.1 (a)    “Confidential Information” shall mean any confidential, proprietary
or trade secret information of a plan, specification, pattern, procedure, design, device, list concept, policy or compilation relating to the present or planned business of a Party, which is designated in good faith as Confidential by the Party supplying the information, whether conveyed orally, electronically, in writing, through inspection or otherwise. Confidential Information shall include, without limitation, all information relating to a Party’s technology, research and development, business affairs, and pricing, customer-specific load data that constitutes a trade secret,
and any information supplied by either of the Parties to the other prior to the execution of this Agreement.

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





(c) Term: During the term of this Agreement, and for a period of three (3) years after                the expiration or termination of this Agreement, except as otherwise provided in                this Article 20, each Party shall hold in confidence and shall not disclose to any                Person Confidential Information.
(d)
Standard of Care: Each Party shall use at least the same standard of care to protect Confidential Information it receives as that it uses to protect its own Confidential Information from unauthorized disclosure, publication or dissemination.
20.2    Scope: Confidential Information shall not include information that the receiving Party can        demonstrate: (1) is generally available to the public other than as a result of disclosure by        the receiving Party (2) was in the lawful possession of the receiving Party on a                 non-confidential basis prior to receiving it from the disclosing Party; or (3) was supplied to        the receiving Party without restriction by a third party, who, to the Knowledge of the            receiving Party, after due inquiry was under no obligation to the disclosing Party to keep            such information confidential; (4) was independently developed by the receiving Party            without reference to Confidential Information of the disclosing Party; (5) is, or becomes,            publicly known, through no wrongful act or omission of the receiving Party or breach of            this Agreement; or (6) is required, in accordance with Section 20.1(b) of this Agreement,            to be disclosed by any federal or state government or agency or is otherwise required to            be disclosed by law or subpoena, or is necessary in any legal proceeding establishing            rights and obligations under this Agreement. Information designated as Confidential            Information will no longer be deemed confidential if the Party that designated the                information as confidential notifies the other Party that it no longer is confidential.
20.3     Order of Disclosure. If a court or a government agency or entity with the right power, and        apparent authority to do so requests or requires either Party, by subpoena, oral                deposition, interrogatories, requests for production of documents, administrative order, or        otherwise, to disclose Confidential Information, that Party shall provide the other Party            with prompt notice of such request(s) or requirement(s) so that the other Party may seek        an appropriate protective order or waive compliance with the terms of this Agreement.            The notifying Party shall have no obligation to oppose or object to any attempt to obtain            such production except to the extent requested to do so by the disclosing Party and at the        disclosing Party’s expense. If either Party desires to object or oppose such production, it            must do so at its own expense. The disclosing Party may request a protective order to            prevent any Confidential Information from being made public. Notwithstanding the            absence of a protective order or waiver, the Party may disclose such Confidential                Information which, in the opinion of its counsel, the Party is legally compelled to disclose.        Each Party will use reasonable effort to obtain reliable assurance that confidential            treatment will be accorded any Confidential Information so furnished.
20.4     Use of Information or Documentation. Each Party may utilize information or                documentation furnished by the disclosing Party and subject to Section 20.1 in any            proceeding under Article 26 or in an administrative agency or court of competent                jurisdiction addressing any dispute arising under this Agreement, subject to a                confidentiality agreement with all participants (including, if applicable, any arbitrator) or a        protective order.




20.5     Remedies Regarding Confidentiality. The Parties agree that monetary damages by            themselves will be inadequate to compensate a Party for the other Party’s breach of its            obligations under this article. Each Party accordingly agrees that the other Party is            entitled to equitable relief, by way of injunction or otherwise, if it breaches or threatens to        breach its obligations under this article.
ARTICLE 21. Breach, Default and Remedies
21.1     General. A breach of this Agreement (“Breach”) shall occur upon the failure by a Party to        perform or observe a material term or condition of this Agreement. A default of this            Agreement (“Default”) shall occur upon the failure of a Party in Breach of this Agreement        to cure such Breach in accordance with Section 21.4.
21.2     Events of Breach. A Breach of this Agreement shall include:
(a)
The failure to pay any amount when due;
(b)
The failure to comply with any material term or condition of this Agreement, including but not limited to any material Breach of a representation, warranty or covenant made in this Agreement;
(c)
A Party’s abandonment of its work or the facilities contemplated in this Agreement;
(d)
If a Party: (1) becomes insolvent; (2) files a voluntary petition in bankruptcy under any provision of any federal or state bankruptcy law or shall consent to the filing of any bankruptcy or reorganization petition against it under any similar law; (3) makes a general assignment for the benefit of its creditors; or (4) consents to the appointment of a receiver, trustee or liquidator;
(e)
Failure of either Party to provide information or data to the other Party as required under this Agreement, provided the Party entitled to the information or data under this Agreement requires such information or data to satisfy its obligations under this Agreement.
21.3     Continued Operation. Except as specifically provided in this Agreement, in the event of a        Breach or Default by either Party, the Parties shall continue to operate and maintain, as            applicable, facilities and appurtenances that are reasonably necessary for the                Transmission Provider to operate and maintain the Transmission System, or the Local            Distribution Company to operate and maintain the Distribution System, in a safe and            reliable manner.
21.4     Cure and Default. Upon the occurrence of an event of Breach, the non‑Breaching Party,        when it becomes aware of the Breach, shall give written notice of the Breach to the            Breaching Party and to any other Person a Party to this Agreement identifies in writing to        the other Party in advance. Such notice shall set forth, in reasonable detail, the nature of        the Breach, and where known and applicable, the steps necessary to cure such Breach.            Upon receiving written notice of the Breach hereunder, the Breaching Party shall have            thirty (30) days, to cure such Breach. If the breach is such that it cannot be cured within            thirty (30) days, the Breaching Party will commence in good faith all steps as are                reasonable and appropriate to cure the Breach within such thirty (30) day time period and        thereafter diligently pursue such action to completion. In the event the Breaching Party            fails to cure the Breach, or to commence reasonable and appropriate steps to cure the            Breach, within thirty (30) days of becoming aware of the Breach, the Breaching Party will        be in Default of the Agreement. In the event of a Default, the non-Defaulting Party has the    




    right to take whatever action at law or equity as may be permitted under this Agreement.
21.5    Right to Compel Performance. Notwithstanding the foregoing, upon the occurrence of an        event of Default, the non-Defaulting Party shall be entitled to Commence an action to            require the Defaulting Party to remedy such Default and specifically perform its duties            and obligations hereunder in accordance with the terms and conditions hereof, and            exercise such other rights and remedies as it may have in equity or at law.
ARTICLE 22. Term
22.1    Term. This Agreement shall become effective as of the Effective Date and shall continue            in full force and effect so long as any Interconnection Point is connected to the                Transmission System, except that it may be terminated by mutual agreement of the            Parties.
22.2    Material Adverse Change.
(a)
In the event of a material change in law or regulation that adversely affects, or may reasonably be expected to adversely affect, either Party’s performance under this Agreement, including but not limited to the following:
(i)
this Agreement is not accepted for filing by the FERC without material modification or condition;
(ii)
NERC or ECAR prevents, in whole or in part, either Party from performing any provision of this Agreement in accordance with its terms; or
(iii)
The FERC, the United States Congress, any state, or any federal or state regulatory agency or commission implements any change in any law, regulation, rule or practice which
materially affects or is reasonably expected to materially affect either Party’s ability to perform under this Agreement.
The Parties will negotiate in good faith any amendment or amendments to the Agreement necessary to adapt the terms of this Agreement to such change in law or regulation, and the Transmission Provider shall file such amendment or amendments with FERC.
(b)
If the Parties are unable to reach agreement on any such amendments, then the Parties shall continue to perform under this Agreement to the maximum extent possible, taking all reasonable steps to mitigate any adverse effect on each other resulting from the Event. If the Parties are unable to reach agreement on any such amendments, Transmission Provider shall have the right to make a unilateral filing with FERC to modify this Agreement pursuant to Section 205 of the Federal Power Act and Local Distribution Company shall have the right to make a unilateral filing with FERC to modify this Agreement pursuant to Section 206 of the Federal Power Act. Each Party shall have the right to protest any such filing by the other Party and to participate fully in any proceeding before FERC.
22.3     Survival. The applicable provisions of this Agreement shall continue in effect after            expiration, cancellation or termination hereof to the extent necessary to provide for final            billings, billing adjustments and the determination and enforcement of liability and            




    indemnification obligations arising from acts or events that occurred while this Agreement        was in effect.

ARTICLE 23. Assignment/Change in Corporate Identity
23.1    Transmission Provider Assignment Rights. Transmission Provider may not assign this            Agreement or any of its rights, interests, or obligations hereunder without the prior written        consent of Local Distribution Company, which consent shall not be unreasonably                withheld; provided however, that Transmission Provider may assign this Agreement or            any of its rights or obligations hereunder without the prior consent of Local Distribution            Company and may assign this Agreement to any entity(ies) in connection with a merger,            consolidation, or reorganization, provided that the surviving entity(ies) or assignee owns            the Transmission System, agrees in writing to be bound by all the obligations and duties            of Transmission Provider provided for in this Agreement and the assignee’s                creditworthiness is equal to or higher than that of Transmission Provider.

23.2    Local Distribution Company Assignment Rights. Local Distribution Company may not            assign this Agreement or any of its rights, interests or obligations hereunder without the            prior written consent of Transmission Provider, which consent shall not be unreasonably            withheld; provided however, that Local Distribution Company may, without the consent of        Transmission Provider, and by providing prior reasonable notice under the circumstances        to Transmission Provider, assign, this Agreement to any entity(ies) in connection with a            merger, consolidation, or reorganization, provided that the surviving entity(ies) or                assignee owns the Local Distribution Company, agrees in writing to be bound by all the            obligations and duties of Local Distribution Company provided for in this Agreement and            the assignee’s creditworthiness is equal to or higher than that of Local Distribution            Company.
23.3    Assigning Party to Remain Responsible. Any assignments authorized as provided for in            this article will not operate to relieve the Party assigning this Agreement or any of its            rights, interests or obligations hereunder of the responsibility of full compliance with the            requirements of this Agreement unless (a) the other Party consents, such consent not to            be unreasonably withheld, and (b) the assignee agrees in writing to be bound by all of the        obligations and duties of the assigning Party provided for in this Agreement.
23.4    This Agreement and all of the provisions hereof are binding upon, and inure to the benefit        of, the Parties and their respective successors and permitted assigns.
ARTICLE 24. Subcontractors
24.1    Nothing in this Agreement shall prevent the Parties from utilizing the services of                subcontractors as they deem appropriate; provided, however, the Parties agree that,            where applicable, all said subcontractors shall comply with the terms and conditions of            this Agreement.
24.2    Except as provided herein, the creation of any subcontract relationship shall not relieve            the hiring Party of any of its obligations under this Agreement. Each Party shall be fully        




    responsible to the other Party for the acts and/or omissions of any subcontractor it hires            as if no subcontract had been made. Any obligation imposed by this Agreement upon the        Parties, where applicable, shall be equally binding upon and shall be construed as having        application to any subcontractor.
24.3    No subcontractor is intended to be or shall be deemed a third-party beneficiary of this            Agreement.
    
24.4    The obligations under this Article 26 shall not be limited in any way by any limitation on            subcontractor’s insurance.
24.5    Each Party shall require its subcontractors to comply with all federal and state laws            regarding insurance requirements and shall maintain standard and ordinary insurance            coverages.
ARTICLE 25. Dispute Resolution
Any dispute between the parties arising out of or relating to this Contract or the breach thereof shall be brought to the Administrative Committee. If the Administrative Committee can resolve the dispute, such resolution shall be reported in writing to and shall be binding upon the Parties. If the Administrative Committee cannot resolve the dispute within a reasonable time, the senior officer of Local Distribution Company or the senior officer of Transmission Provider may, by written notice to the senior officer of the other Party and the members of the Administrative Committee, withdraw the matter from consideration by the Administrative Committee and submit the same for resolution to the senior officers of the Parties. If the senior officers of the Parties agree to a resolution of the matter, such resolution shall be reported in writing to, and shall be binding upon, the Parties; but if said senior officers fail to resolve the matter within five (5) Business Days after its submission to them, then the Parties agree to try in good faith to settle the dispute by mediation administered by the American Arbitration Association under its Commercial Mediation Rules before resorting to litigation.
ARTICLE 26. Miscellaneous Provisions
26.1
This Agreement shall constitute the entire Agreement between the Parties hereto relating to the subject matter hereof. In all other respects, special contracts or superseding rate schedules shall govern Transmission Provider’s transmission service to Local Distribution Company.
26.2
No failure or delay on the part of Transmission Provider or Local Distribution Company in exercising any of its rights under this Agreement, no partial exercise by either Party of any of its rights under this Agreement, and no course of dealing between the Parties shall constitute a waiver of the rights of either Party under this Agreement. Any waiver shall be effective only by a written instrument signed by the Party granting such waiver, and such shall not operate as a waiver of, or estoppel with respect to, any subsequent failure to comply therewith.

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




    hereunder.
26.4 In the event that any clause or provision of this Agreement or any part hereof shall be held to be invalid, void, or unenforceable by any court or Governmental Authority of competent jurisdiction, said holding or action shall be strictly construed and shall not affect the validity or effect of any other provision hereof, and the Parties shall endeavor in good faith to replace such invalid or unenforceable provisions with a valid and enforceable provision which achieves the purposes intended by the Parties to the greatest extent permitted by law.
26.5 The article and section headings herein are inserted for convenience only and are not to be construed as part of the terms hereof or used in the interpretation of this Agreement.
26.6 In the event an ambiguity or question of intent or interpretation arises, this Agreement shall be construed as if drafted jointly by the Parties and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of authorship of any of the provisions of this Agreement. Any reference to any federal, state, local, or foreign statute or law shall be deemed also to refer to all rules and regulations promulgated thereunder, unless the context requires otherwise. The word “including” in this Agreement shall mean including without limitation.
26.7 This Agreement may be executed in one or more counterparts, each of which shall be deemed an original.
26.8 Each Party shall act as an independent contractor with respect to the provision of services hereunder.


















IN WITNESS WHEREOF, Transmission Provider and Local Distribution Company have caused this instrument to be executed by their duly authorized representatives as of the day and year first above written.
CONSUMERS ENERGY COMPANY
By: /s/Mary P. Palkovich
Name: Mary P. Palkovich
Title: Vice President, Energy Delivery


MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC, a Michigan
limited liability company

By: ITC Holdings Corp., its manager


By:/s/Gregory Loanidis    
Name: Gregory Ioanidis
Title: Vice President














EXHIBIT 1 - Interconnection
37
Blackman
38
Blackstone
39
Blinton
40
Blue Water
Points (Substations) Addendum 8, Final 10/02/14
41
 Bluegrass
Substation
42
 Boardman
1
Abbe
43
Boxboard
2
Acme (04/10)
44
Bricker
3
Alcona
45
Brickyard
4
Alder Creek
46
Briggs & Stratton
5
Alger
47
Broadmoor
6
Algoma
48
Bronco
7
Alma
49
Broughwell
8
Almeda
50
Buck Creek
9
Alpena
51
Bullock
10
Alpine
52
Busch Road (02/08)
11
Amber
53
Calhoun
12
American Bumper
54
Camelot Lake
13
Arthur (06/06)
55
Campbell 138
14
Aubil Lake
56
Canal
15
Backus
57
Cannon
16
Bagley
58
Carpenter Rd (08/06)
17
Bangor
59
Carter
18
Baraga (12/07)
60
Cedar Springs
19
Bard Road
61
Cement City
20
Barnum Creek
62
Chase
21
Barry
63
Cheesman
22
Bass Creek
64
Chicago
23
Batavia
65
Churchill
24
Bay Road
66
Clare
25
Bayberry
67
Claremont
26
Beals Road
68
Clearwater
27
Becker
69
Cleveland
28
Beebe
70
Club
29
Beecher
71
Cobb
30
Bell Road
72
Cochran
31
Bennington
73
Cole Creek
32
Beveridge
74
Colony Farm
33
Bilmar
75
Convis
34
Bingham
76
Cork Street
35
Birchwood (06/12)
77
Cornell
36
Black River
78
Cottage Grove
Changes, relative to previous revisions (addendums), are shown in bold type.
New interconnections have (month/year) in-service date after substation name if their in-service date was after May of 2002.
Note, this list of substations is not necessarily a list of the true points of facility ownership change between the Transmission Provider and the Local Distribution Company. This also is not a complete listing of all Local Distribution Company substations that have a 138 kV high-side supply voltage.




79 Covert
121 Grand Blanc BOC
80 Cowan Lake
122 Gratiot
81 Crahen (10/07)
123 Gray Road (04/10)
82 Croton
124 Greenwood
83 David
125 Grey Iron
84 Dean Road
126 Grodi Road
85 Deja
127 Grout
86 Delaney
128 Hackett
87 Delhi
129 Hagadorn
88 Denso Jackson
130 Hager Park
89 Derby
131 Halsey
90 Discovery Way (04/11)
132 Haring
91 Dorr Corners
133 Harvard Lake (06/09)
92 Dort
134 Hazelwood
93 Dow Corning
135 Hemphill
94 Dowling
136 Hendershot
95 Drake Road
137 Higgins
96 Duffield Rd
138 Hillman Cogen
97 Dupont
139 Hodenpyl
98 Duquite
140 Holland Road
99 Dutton
141 Hotchkiss
100 East Paris
142 HSC
101 East Tawas
143 Hubbard Lake (12/07)
102 Easton
144 Hubbardston Road (06/10)
103 Edenville
145 Hudsonville
104 Ellis
146 Hughes Road
105 Emmet
147 Hull Street
106 Englishville
148 Iosco
107 Eureka
149 Island Road
108 Farr Road
150 Jamestown
109 Felch Road
151 Karn 138
110 Filer City
152 Kentwood
111 Fillmore
153 Keystone
112 Fort Custer
154 Kinderhook (05/07)
113 Forty Fourth Street
155 Kipp Road
114 Foundry
156 Kraft
115 Four Mile
157 Lafayette
116 Gaines (05/06)
158 Laundra (05/07)
117 Gallagher
159 Lawndale
118 Gaylord
160 Layton
119 Geddes (04/08)
161 Leoni
120 Gleaner
162 Letts Road

Changes, relative to previous revisions (addendums), are shown in bold type.
New interconnections have (month/year) in-service date after substation name if their in-service date was after May of 2002.
Note, this list of substations is not necessarily a list of the true points of facility ownership change between the Transmission Provider and the Local Distribution Company. This also is not a complete listing of all Local Distribution Company substations that have a 138 kV high-side supply voltage.




163 Lewiston
205 Plymouth Street
164 Lindbergh
206 Plywood
165 Livingston Peaker
207 Port Calcite
166 Lovejoy
208 Port Sheldon
167 Ludington
209 Porter
168 Manlius
210 Portsmouth
169 Marquette
211 Price Road (09/07)
170 McGulpin
212 Progress Street
171 MCV
213 Race Street
172 Meadowbrooke
214 Raisin
173 Mecosta
215 Ransom
174 Michigan
216 Ratigan (12/12)
175 Michigan Power (MPLP)
217 Regal (01/13)
176 Milham
218 Renaissance
177 Mio
219 Rice Creek
178 Monitor
220 Riggsville
179 Moore Road
221 Rivertown
180 Morrow
222 Riverview
181 Mullins
223 Rockport/Presque Isle
182 Neff Road
224 Roedel Road
183 Nineteen Mile Road
225 Rogue River (06/07)
184 North Belding
226 Saginaw River
185 North Corunna
227 Samaria
186 Northern Fibre
228 Sanderson
187 Nugent Sand
229 Savidge
188 Oakland
230 Scott Lake
189 Oceana
231 Seamless East/Seamless
190 Orr Road (03/09)
232 Simpson (08/12)
191 Packard
233 Sonoma (05/06)
192 Palisades
234 Spaulding
193 Parkville (08/12)
235 Spruce Road
194 Parr Road
236 Stacey
195 Parshallville
237 Stamping Plant
196 Pasadena
238 Sternberg Road (05/11)
197 Pavilion
239 Steelcase
198 Pearline (06/11)
240 Stonegate
199 Pettis Road
241 Stover
200 Pigeon River/Rondo
242 Stronach
201 Pingree (10/08)
243 Summerton
202 Piston Ring
244 Thetford 138
203 Plaster Creek
245 Tihart
204 Plum (07/10)
246 Tinsman

Changes, relative to previous revisions (addendums), are shown in bold type.
New interconnections have (month/year) in-service date after substation name if their in-service date was after May of 2002.
Note, this list of substations is not necessarily a list of the true points of facility ownership change between the Transmission Provider and the Local Distribution Company. This also is not a complete listing of all Local Distribution Company substations that have a 138 kV high-side supply voltage.




247 Tippy
264 Wackerly
248 Titus Lake
265 Warner
249 Trillium (06/07)
266 Warren
250 Trowbridge
267 Washtenaw
251 Tuscola Bay
268 Wayland
252 Twelfth Street
269 Weadock
253 Twilight
270 Wealthy Street
254 Twining
271 West Fenton (05/07)
255 Upjohn
272 Wexford
256 Van Atta
273 White Lake
257 Van Buren (06/08)
274 White Road
258 Vanderbilt
275 Whiting
259 Vernon
276 Whittemore
260 Verona
277 Willard
261 Vevay
278 Withey Lake (05/06)
262 Viking Lincoln
279 Zeeland
263 Vrooman
 




























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

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

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





EXHIBIT 2 - Contact Information For Local Distribution Company’s Representatives and Transmission
Provider’s Representatives
Local Distribution Company:
Consumers Energy Company 4000 Clay Ave SW, PO Box 201 Grand Rapids, MI 49501-0201
Attn: Executive Manager of System Planning and Control

Transmission Provider:

Michigan Electric Transmission Company, LLC
27175 Energy Way
Novi, MI 48377

Attn: Legal Department - Contracts
































EXHIBIT 3
Transmission Provider and the Local Distribution Company acknowledge that the Special Manufacturing Contracts in existence at the time of the original execution of the 2001 Amendment and Restatement of the Distribution-Transmission Interconnection Agreement and as listed below under this Exhibit 3 are no longer in effect or no longer have clauses with compensable disruptions/interruptions associated with them. Upon FERC acceptance of this 2014 Agreement, the Transmission Provider, under Section 8.3, shall no longer be responsible for those compensable disruptions/interruptions under the Special Manufacturing Contracts.
SPECIAL MANUFACTURING CONTRACTS INFLUENCED BY TRANSMISSON SYSTEM
CUSTOMER
SUBSTATION
PAYMENT PER DISRUPTION EVENT
 
 
INTERRUPTION
VOLTAGE SAG
GM
BUICK STEWART
$150,000
NOT APPLICABLE
 
MALLEABLE
$150,000
NOT APPLICABLE
 
FLORENCE ST.
$150,000
NOT APPLICABLE
 
GRAND BLANC BOC
$100,000
NOT APPLICABLE
 
GREY IRON
$150,000
NOT APPLICABLE
 
STAMPING PLANT
$100,000
NOT APPLICABLE
DELPHI
HOLLAND RD.
$150,000
NOT APPLICABLE

NOTES FOR GM & DELPHI:
 
NO PAYMENTS FOR VOLTAGE SAGS.
CUMULATIVE ANNUAL PAYMENT IS CAPPED AT $3,000,000.
INITIAL TERM OF GM AND DELPHI CONTRACTS EXPIRE IN 2005.
CONTRACTS MAY BE EXTENDED TO 2010 BY MUTUAL AGREEMENT.
EVENT #
DOW CORNING
CARTER
($15,000)
($15,000)
no events
 
 
$15,000
0
1st /yr
 
 
$15,000
$15,000
2nd/yr
 
 
$55,000
NOT APPLICABLE
3rd/yr
DOW CORNING
DOW CORNING
($25,000)
($25,000)
no events
 
 
$25,000
0
1st /yr
 
 
$35,000
$25,000
2nd/yr
 
 
$105,000
NOT APPLICABLE
3rd/yr
HEMLOCK
HSC
($40,000)
($20,000)
no events
SEMICONDUCTOR
 
$40,000
0
1st /yr
 
 
$60,000
$20,000
2nd/yr
 
 
$150,000
NOT APPLICABLE
3rd/yr
HEMLOCK
SILICON
NOT APPLICABLE
($15,000)
no events
SEMICONDUCTOR
 
NOT APPLICABLE
0
1st /yr
 
 
NOT APPLICABLE
0
2nd/yr







NOT APPLICABLE0 3rd/yr
NOT APPLICABLE    $15,000 4th/yr
NOTES FOR DOW CORNING & HEMLOCK SEMICONDUCTOR:
1.IF NO EVENTS IN A YEAR, PAYMENT IS MADE TO CONSUMERS.
2.MAXIMUM # OF PAYABLE EVENTS/YR IS 3 FOR INTERRUPTIONS & 1 FOR SAGS.
3.WEATHER RELATED EVENTS ARE NOT PAYABLE.















































EXHIBIT 4 - Metering Specifications

Performance criteria:

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

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

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

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

























EXHIBIT 5
Addendum 6 - Final 10/02/14
For ownership changes since August 7, 2007, refer to the drawings in each Party’s Drawing Management System (DMS), as discussed in Section 3.2 of this Agreement.
The WDs of the following substations have been revised since the last update of 11/28/12 (Addendum 5):
Consumers Energy (CE)
Michigan Electric Transmission Company (METC)
Beals Road
Beals Road
Bingham
Black River
Black River
Bullock
Cobb
Claremont
Dort
Cobb
Felch Road
Cornell
Hemphill
Croton
McGulpin
Lawndale
Mecosta
Marquette
Milham
McGulpin
Moore Road
Milham
Oakland
Morrow
Spaulding
North Belding
Tippy Hydro
Saginaw River
Verona
Stonach
Wealthy
Tihart
 
Wealthy
 
Whiting


























EXHIBIT 6 - Jointly Owned Assets Ownership by Percent of Major Equipment Addendum 8 - Final 10/02/14

Substations
Jointly Owned Assets
Percentage Split by Major Equipment Count



 
Substation Name
Distribution
Transmission
Generation Owned by Local Distribution Company
Third-Party Assets
Last Revision Date
 
 
 
Alma
        66.67
            33.33
 
 
10/24/2003
 
Bard Road
        41.67
            58.33
 
 
6/10/2010
 
Batavia
        50.00
            50.00
 
 
10/2/2014
 
Beals Road
        84.62
            15.38
 
 
6/10/2010
 
Beecher
        82.50
            17.50
 
 
11/28/2011
 
Bingham
        90.91
             9.09
 
 
11/28/2011
 
Black River1
        66.67
            25.93
 
7.40
11/28/2011
 
Blackstone
        70.83
            29.17
 
 
11/28/2011
 
Bullock
        76.00
            24.00
 
 
11/20/2008
Changes, relative to previous revisions (addendums), are shown in bold type.
1 At 120kV and above, third-party related assets will be included as part of the Transmission Provider’s assets for purposes of making this calculation. Also, the third-party may share in the financial responsibility associated with O&M activities.





Claremont
68.00

32.00
 
 
5/1/2002
Cobb Plant
47.22

25.00
27.78
 
5/1/2002
Cornell
66.67

33.33
 
 
11/28/2011
Croton
54.54

31.82
13.64
 
6/10/2010
Delhi
52.38

47.62
 
 
10/2/2014
Dort2
68.18

31.82
 
 
11/28/2011
Emmet
92.31

7.69
 
 
5/1/2002
Eureka
88.89

11.11
 
 
6/10/2010
Felch Road
83.33

16.67
 
 
3/31/2006
Four Mile
73.33

26.67
 
 
3/16/2006
Gaylord
44.44

44.44
11.12
 
11/20/2008
Halsey
76.92

23.08
 
 
10/24/2003
Hemphill
64.29

35.71
 
 
11/28/2011
HSC
33.33

66.67
 
 
11/28/2011
Iosco
83.33

16.67
 
 
5/30/2007





















Changes, relative to previous revisions (addendums), are shown in bold type.
2 Third-party may share in the financial responsibility associated with O&M activities.




Lawndale
70.59
29.41
 
 
11/28/12
Marquette
62.50
37.50
 
 
11/28/12
McGulpin1
55.56
44.44
 
 
11/28/11
Mecosta
86.67
13.33
 
 
11/28/11
Milham
70.59
29.41
 
 
11/28/12
Moore Road3
64.65
10.00
 
25.35
08/07/07
Morrow1
63.33
30.00
6.67
 
11/28/12
North Belding
66.67
33.33
 
 
10/24/03
Oakland
87.50
12.50
 
 
10/24/03
Ransom
88.89
11.11
 
 
01/05/05
Rice Creek
92.86
7.14
 
 
10/24/03














__________________________________________ 
1 At 120kV and above, third-party related assets will be included as part of the Transmission Provider’s assets for purposes of making this calculation. Also, the third-party may share in the financial responsibility associated with O&M activities.
3 Below 120kV the third-party related assets will be included as part of the Local Distribution Company’s assets for purposes of making this calculation. Also, the third-party may share in the financial responsibility associated with O&M activities.




Riggsville
75.00
25.00
 
 
11/20/08
Riverview
93.75
6.25
 
 
10/24/03
Saginaw River
11.11
88.89
 
 
10/02/14
Spaulding
53.33
46.67
 
 
10/02/14
Stover
85.71
14.29
 
 
11.20/08
Stronach2
66.67
33.33
 
 
05/24/04
Tihart
66.67
33.33
 
 
11/28/12
Tippy
33.33
66.67
 
 
11/13/02
Twining
76.92
23.08
 
 
05/01/02
Verona
60.87
39.13
 
 
03/31/06
Weadock
35.14
24.32
40.54
 
03/16/06
Wealthy Street
86.11
13.89
 
 
03/16/06
Wexford
92.86
7.14
 
 
11/28/11
White Lake
81.25
18.75
 
 
10/24/03
Whiting
31.58
31.58
36.84
 
08/07/07








Changes, relative to previous revisions (addendums), are shown in bold type.
2 Third-party may share in the financial responsibility associated with O&M activities.






EXHIBIT 31.1
CERTIFICATION PURSUANT TO SECTION 13a-14 OF THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Joseph L. Welch, certify that:
1.
I have reviewed this report on Form 10-Q for the quarterly period ended March 31, 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: April 30, 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 March 31, 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: April 30, 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 March 31, 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: April 30, 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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