Integrys Holding (TEG) 10-K 2012 FY Annual report

Exhibit 99.2

AMERICAN TRANSMISSION COMPANY LLC

Financial Statements as of December 31, 2012 and 2011 and for the Years Ended December 31, 2012, 2011 and 2010 and Report of Independent Registered Public Accounting Firm

American Transmission Company LLC

Table of Contents

Report of Independent Registered Public Accounting Firm	3
Financial Statements
Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010	4
Balance Sheets as of December 31, 2012 and 2011	5
Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	6
Statements of Changes in Members’ Equity for the Years Ended December 31, 2012, 2011 and 2010	7
Notes to Financial Statements as of December 31, 2012 and 2011 and for the Years Ended December 31, 2012, 2011 and 2010	8-30

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of ATC Management Inc.,

Corporate Manager of American Transmission Company LLC

Pewaukee, Wisconsin

We have audited the accompanying balance sheets of American Transmission Company LLC (the “Company”) as of December 31, 2012 and 2011, and the related statements of operations, changes in members’ equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Milwaukee, Wisconsin

February 1, 2013

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American Transmission Company LLC

Statements of Operations

For the Years Ended December 31, 2012, 2011 and 2010

(In Thousands)	2012			2011			2010
Operating Revenues
Transmission Service Revenue	$	602,092		$	565,968		$	555,443
Other Operating Revenue	1,162			1,206			1,298
Total Operating Revenues	603,254			567,174			556,741
Operating Expenses
Operations and Maintenance	158,271			147,121			136,619
Depreciation and Amortization	107,230			100,247			95,898
Taxes Other than Income	15,769			15,963			17,106
Income Tax Provision of ATC LLC	(271		)	(1,763		)	1,497
Total Operating Expenses	280,999			261,568			251,120
Operating Income	322,255			305,606			305,621
Other Expense, Net	2,533			1,332			885
Earnings Before Interest and Members’ Income Taxes	319,722			304,274			304,736
Net Interest Expense	82,296			80,359			85,067
Earnings Before Members’ Income Taxes	$	237,426		$	223,915		$	219,669

The accompanying notes are an integral part of these financial statements.

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American Transmission Company LLC

Balance Sheets

As of December 31, 2012 and 2011

(In Thousands)	2012			2011
ASSETS
Property, Plant and Equipment
Transmission Plant	$	3,771,745		$	3,574,786
General Plant	92,303			81,579
Less- Accumulated Depreciation	(877,539		)	(823,780		)
	2,986,509			2,832,585
Construction Work in Progress	269,501			207,554
Net Property, Plant and Equipment	3,256,010			3,040,139
Current Assets
Cash and Cash Equivalents	117			159
Accounts Receivable	56,519			52,286
Prepaid Expenses	4,619			4,681
Other Current Assets	1,879			1,545
Total Current Assets	63,134			58,671
Regulatory and Other Assets
Equity Investment in Unconsolidated Subsidiary	776			—
Regulatory Assets	7,329			1,915
Other Assets	10,589			11,688
Regulatory and Other Assets	18,694			13,603
Total Assets	$	3,337,838		$	3,112,413
CAPITALIZATION AND LIABILITIES
Capitalization
Members’ Equity (see Note 3 for redemption provisions)	$	1,440,468		$	1,331,288
Long-term Debt	1,550,000			1,400,005
Total Capitalization	2,990,468			2,731,293
Current Liabilities
Accounts Payable	18,020			19,121
Accrued Interest	22,033			20,704
Other Accrued Liabilities	37,452			49,315
Current Portion of Regulatory Liabilities	7,475			13,230
Short-term Debt	166,561			184,343
Current Portion of Advances Under Interconnection Agreements	—			11,760
Total Current Liabilities	251,541			298,473
Regulatory and Other Long-term Liabilities
Regulatory Liabilities	83,140			74,553
Other Long-term Liabilities	12,689			8,094
Total Regulatory and Other Long-term Liabilities	95,829			82,647
Commitments and Contingencies (See Note 7)	—			—
Total Capitalization and Liabilities	$	3,337,838		$	3,112,413

The accompanying notes are an integral part of these financial statements.

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American Transmission Company LLC

Statements of Cash Flows

For the Years Ended December 31, 2012, 2011 and 2010

(In Thousands)	2012			2011			2010
Cash Flows from Operating Activities
Earnings Before Members’ Income Taxes	$	237,426		$	223,915		$	219,669
Adjustments to Reconcile Earnings Before Members’ Income Taxes to Net
Cash Provided by Operating Activities-
Depreciation and Amortization	107,230			100,247			95,898
Bond Discount and Debt Issuance Cost Amortization	458			584			1,110
Provision for Deferred Income Taxes of ATC LLC, Net	—			(2,070		)	1,021
Equity Loss in Unconsolidated Subsidiary Investment	1,574			—			—
Change in-
Accounts Receivable	(5,597		)	(3,275		)	(1,373		)
Current Assets	(679		)	5,119			(1,995		)
Accounts Payable	813			(83		)	837
Accrued Liabilities	(3,627		)	4,263			7,270
Other, Net	(11,951		)	(1,186		)	7,505
Total Adjustments	88,221			103,599			110,273
Net Cash Provided by Operating Activities	325,647			327,514			329,942
Cash Flows from Investing Activities
Capital Expenditures for Property, Plant and Equipment	(315,808		)	(250,749		)	(225,782		)
Insurance Proceeds Received for Damaged Property, Plant and Equipment	—			1,668			—
Investment in Unconsolidated Subsidiary	(2,350		)	—			—
Net Cash Used in Investing Activities	(318,158		)	(249,081		)	(225,782		)
Cash Flows from Financing Activities
Distribution of Earnings to Members	(188,246		)	(177,594		)	(176,098		)
Issuance of Membership Units for Cash	60,000			25,000			20,000
Issuance (Repayment) of Short-term Debt, Net	(17,782		)	155,480			(168,693		)
Issuance of Long-term Debt, Net of Issuance Costs	148,972			224,959			222,209
Repayment of Long-term Debt	—			(310,000		)	—
Advances Received Under Interconnection Agreements	2,524			6,621			1,874
Repayments of Interconnection Agreements	(12,982		)	(3,035		)	(3,347		)
Other, Net	(17		)	16			(2		)
Net Cash Used in Financing Activities	(7,531		)	(78,553		)	(104,057		)
Net Change in Cash and Cash Equivalents	(42		)	(120		)	103
Cash and Cash Equivalents, Beginning of Period	159			279			176
Cash and Cash Equivalents, End of Period	$	117		$	159		$	279

The accompanying notes are an integral part of these financial statements.

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American Transmission Company LLC

Statements of Changes in Members’ Equity

For the Years Ended December 31, 2012, 2011 and 2010

(In Thousands)
Members’ Equity as of December 31, 2009		$	1,196,396
Membership Units Outstanding at December 31, 2009	75,266
Issuance of Membership Units		$	20,000
Earnings Before Members’ Income Taxes		219,669
Distribution of Earnings to Members		(176,098		)
Members’ Equity as of December 31, 2010		$	1,259,967
Membership Units Outstanding at December 31, 2010	76,656
Issuance of Membership Units		$	25,000
Earnings Before Members’ Income Taxes		223,915
Distribution of Earnings to Members		(177,594		)
Members’ Equity as of December 31, 2011		$	1,331,288
Membership Units Outstanding at December 31, 2011	78,325
Issuance of Membership Units		$	60,000
Earnings Before Members’ Income Taxes		237,426
Distribution of Earnings to Members		(188,246		)
Members’ Equity as of December 31, 2012		$	1,440,468
Membership Units Outstanding at December 31, 2012	82,154

The accompanying notes are an integral part of these financial statements.

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American Transmission Company LLC

Notes to Financial Statements as of December 31, 2012 and 2011 and for the Years Ended
December 31, 2012, 2011 and 2010

(1)Nature of Operations and Summary of Significant Accounting Policies

(a)General

American Transmission Company LLC (the “Company”) was organized, as a limited liability company under the Wisconsin Limited Liability Company Act, as a single-purpose, for-profit electric transmission company.  The Company’s purpose is to plan, construct, operate, own and maintain electric transmission facilities to provide an adequate and reliable transmission system that meets the needs of all users on the system and supports equal access to a competitive, wholesale electric energy market.

The Company owns and operates the electric transmission system, under the direction of the Midwest Independent Transmission System Operator, Inc. (MISO), in parts of Wisconsin, Illinois, Minnesota and the Upper Peninsula of Michigan.  The Company is subject to regulation by the Federal Energy Regulatory Commission (FERC) as to rates, terms of service and financing and by state regulatory commissions as to other aspects of business, including the construction of electric transmission assets.

The Company’s five largest customers are also members and account for over 80% of the Company’s operating revenues.  The rates for these transmission services are subject to review and approval by the FERC. In addition, several members provide operations, maintenance and construction services to the Company.  The agreements under which these services are provided are subject to review and approval by the Public Service Commission of Wisconsin (PSCW).  See note (8) for details of the various transactions between the Company and its members.

The Company evaluated potential subsequent events through February 1, 2013, which is the date these statements were available to be issued.

(b)Corporate Manager

The Company is managed by a corporate manager, ATC Management Inc. (“Management Inc.”).  The Company and Management Inc. have common ownership and operate as a single functional unit.  Under the Company’s operating agreement, Management Inc. has complete discretion over the business of the Company and provides all management services to the Company at cost.  The Company itself has no employees and no governance structure separate from Management Inc.  The Company’s operating agreement establishes that all expenses of Management Inc. are the responsibility of the Company.  These expenses consist primarily of payroll, benefits, payroll-related taxes and other employee-related expenses.  All such expenses are recorded in the Company’s accounts as if they were direct expenses of the Company.

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As of December 31, the following net payables to Management Inc. were included in the Company’s balance sheets (in thousands):

	2012		2011
Other Accrued Liabilities	$	15,259	$	14,246
Other Long-term Liabilities	5,383		5,903
Net Amount Payable to Management Inc.	$	20,642	$	20,149

Amounts included in other accrued liabilities are primarily payroll- and benefit-related accruals.  Amounts included in other long-term liabilities relate primarily to certain long-term compensation arrangements covering Management Inc. employees, as described in note (2), offset by a $12.6 million and $12.4 million receivable as of December 31, 2012 and 2011, respectively, for income taxes paid on Management Inc.’s behalf by the Company.  The income taxes paid are due to temporary differences relating to the tax deductibility of certain employee-related costs.  As these temporary differences reverse in future years, Management Inc. will receive cash tax benefits and will then repay the advances from the Company.

(c)Revenue Recognition

Wholesale electric transmission service for utilities, municipalities, municipal electric companies, electric cooperatives and other eligible entities is provided through the Company’s facilities under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (“MISO Tariff”) regulated by the FERC. The Company charges for these services under FERC-approved rates.  The MISO Tariff specifies the general terms and conditions of service on the transmission system and the approved rates set forth the calculation of the amounts to be paid for those services.  The Company does not take ownership of the electricity that it transmits.

The Company’s FERC-approved formula rate tariff for the revenue requirement determined under Attachment O of the MISO Tariff includes a true-up provision that meets the requirements of an alternative revenue program as defined in the Financial Accounting Standards Board’s (FASB) Financial Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.”  Accordingly, revenue is recognized for transmission system access the Company provided during the reporting period based on the revenue requirement formula in the tariff.  Annually, the Company prepares a forecast for the upcoming rate year of total operating expenses, projected rate base resulting from planned construction and other capital expenditures, as well as projected amounts to be received from MISO.  From this forecast, the Company computes an annual projected total revenue requirement for the reporting period.  Based on the criteria in the MISO Tariff, the Company also calculates its regional cost-sharing revenue requirements which, in addition to other forecasted revenues from MISO and other sources, are subtracted from the total revenue requirement to determine the Company’s annual network revenue requirement.  The annual network revenue requirement is billed to and collected from network transmission customers in equal monthly installments throughout the rate year.  Subsequent to the rate year, the Company compares actual results from the rate year to the forecast to determine any under or over collection of revenue from network and regional customers.  In accordance with ASC Topic 980, the Company accrues or defers revenues that are higher or lower, respectively, than the amounts collected during the reporting period.  In accordance with ASC Topic 980, an accumulated over-collected true-up balance is classified as a regulatory liability in the balance sheets and an accumulated under-collected true-up balance is classified as a regulatory asset in

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the balance sheets.  The Company is required to refund any over collected amounts, plus interest, within two fiscal years subsequent to the rate year, with the option to accelerate all or a portion of any such refund, and is permitted to include any under collected amounts, plus interest, in annual network billings two fiscal years subsequent to the rate year.  Under these true up provisions, the Company refunded, inclusive of interest, approximately $8.0 million, $10.1 million and $0.6 million to network customers through their monthly bills in 2012, 2011 and 2010, respectively.  The Company also has FERC-approved true-up provisions for MISO regional cost-sharing revenues, including for Multi-value Projects, to refund over collections or receive under collections in the second year subsequent to the rate year.  The Company refunded, inclusive of interest, approximately $5.5 million and $0.9 million in 2012 and 2010 to regional customers, respectively, and collected, inclusive of interest, approximately $3.8 million from regional customers in 2011.  See note 1(h) for more information on the Company’s true-up provisions.

The Company records a reserve for revenue subject to refund when such refund is probable and can be reasonably estimated.

The Company is currently operating under a settlement agreement approved by the FERC in 2004 which limits the rights of interested parties to challenge, through a FERC Section 206 proceeding, the provisions noted above for the term of the agreement.  Certain provisions of the settlement agreement terminated on December 31, 2012.  After this date, the Company may elect to change, or intervenors may request a change in, the Company’s revenue requirement formula.  A change in the revenue requirement formula could result in lowered rates and have an adverse effect on the Company’s financial position, results of operations and cash flows.  If no filings are made by either the Company or other parties, the current terms of the settlement agreement will continue in effect.

(d)Transmission and General Plant and Related Depreciation

Transmission plant is recorded at the original cost of construction.  Assets transferred to the Company primarily by its members, which include investor-owned utilities, municipalities, municipal electric companies and electric cooperatives, have been recorded at their original cost in property, plant and equipment with the related reserves for accumulated depreciation also recorded.

The original cost of construction includes materials, construction overhead and outside contractor costs.  Additions to, and significant replacements of, transmission assets are charged to property, plant and equipment at cost; replacements of minor items are charged to maintenance expense.  The cost of transmission plant is charged to accumulated depreciation when an asset is retired.

The provision for depreciation of transmission assets is an integral part of the Company’s cost of service under FERC-approved rates.  Depreciation rates include estimates for future removal costs and salvage value.  Amounts collected in depreciation rates for future non-legal removal costs are included in regulatory liabilities in the balance sheets, as described in note 1(h).  Removal costs incurred are charged against the regulatory liability.  Depreciation expense, including a provision for removal costs, as a percentage of average transmission plant was 2.75% in 2012 and 2.63% in both 2011 and 2010.

The Company completed a depreciation study during 2011 and filed with the FERC on November 30, 2011 for an adjustment to its depreciation rates based on the findings of the study.  In docket ER12-212-000 issued on December 21, 2011, the FERC approved the Company’s revised rates, effective January 1, 2012.

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The Company’s annual depreciation expense for 2012 increased by approximately $1.0 million as a result of implementing the adjusted rates.

General plant, which includes buildings, office furniture and equipment, and computer hardware and software, is recorded at cost.  Depreciation is recorded at straight-line rates over the estimated useful lives of the assets, which range from five to 45 years.

(e)Asset Retirement Obligations

Consistent with ASC Topic 410, “Asset Retirement and Environmental Obligations,” the Company records a liability at fair value for a legal asset retirement obligation (ARO) in the period in which it is incurred.  When a new legal obligation is recorded, the costs of the liability are capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.  In accordance with ASC Topic 980, the Company recognizes regulatory assets or liabilities, as described in note 1(h), for the timing differences between when it recovers the ARO in rates and when it recognizes these costs under ASC Topic 410.  At the end of the asset’s useful life, the Company settles the obligation for its recorded amount and records the gain or loss in the appropriate regulatory account.

The Company has recognized AROs primarily related to asbestos, lead-based paint, and polychlorinated biphenyls contained in its electrical equipment.  AROs are recorded as other long-term liabilities in the balance sheets.  The following table describes all changes to AROs for the year ended December 31, 2012 (in thousands):

Asset Retirement Obligations at December 31, 2011	$	1,896
Accretion	133
Liabilities Recognized	5,354
Liabilities Settled	(77		)
Asset Retirement Obligations at December 31, 2012	$	7,306

(f)Interconnection Agreements

The Company has entered into interconnection agreements with entities planning to build generation plants.  The Company will construct the facilities; however, the generator will finance and bear all financial risk of constructing the interconnection facilities under these agreements.  The Company will own and operate the interconnection facilities when the generation plants become operational and will reimburse the generator for construction costs, plus interest.  If the generation plants do not become operational, the Company has no obligation to reimburse the generator for costs incurred during construction.

In cases in which the Company is contractually obligated to construct the interconnection facilities, the Company receives cash advances for construction costs from the generators.  During construction, the Company includes actual costs incurred in construction work in progress (CWIP) and records liabilities for the cash advances from the generators, along with accruals for interest.  The accruals for interest are capitalized and included in CWIP.  The construction costs and accrued interest related to interconnection

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agreements that are included in CWIP are not included as a component of the Company’s rate base until the generation facilities become operational and the Company has reimbursed the generator.

At December 31, 2012 the Company had no active projects related to these agreements.  Therefore, at December 31, 2012 there were no amounts included in CWIP or liabilities related to cash advances from generator interconnection agreements.  At December 31, 2011, amounts included in CWIP related to generator interconnection agreements were $10.7 million.  Similarly, at December 31, 2011, generator advances, including accrued interest, totaled $11.8 million and were included in current liabilities.

(g)Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with original maturities of three months or less.

The Company paid cash for the following items during 2012, 2011 and 2010 (in millions):

	2012		2011		2010
Interest	$	80.0	$	81.5	$	80.9
Income Taxes of ATC LLC	—		0.6		0.7

At December 31, 2012, 2011 and 2010, construction costs funded through accounts payable and accrued liabilities were $25.5 million, $40.0 million and $30.7 million, respectively.  Accordingly, these noncash investing activities are not reported in the statements of cash flows until the period in which the payables are paid.

(h)Regulatory Accounting

The Company’s accounting policies conform to ASC Topic 980.  Accordingly, assets and liabilities that result from the regulated ratemaking process are recorded that would otherwise not be recorded under accounting principles generally accepted in the United States of America for non-regulated companies.  Certain costs are recorded as regulatory assets as incurred and are recognized in the statements of operations at the time they are reflected in rates.  As such, regulatory assets are not included as a component of rate base.  Regulatory liabilities represent amounts that have been collected in current rates to recover costs that are expected to be incurred, or refunded to customers, in future periods.

In accordance with ASC Topic 715, “Compensation — Retirement Benefits,” the Company recognizes the overfunded or underfunded status of its postretirement benefit plan, measured as the amount by which its accumulated postretirement benefit obligation is less than or greater than the fair value of the assets that fund its plan.  Since the Company expects to refund or recover these amounts in future rates, a regulatory liability or asset has been established for an amount equal to the ASC Topic 715 asset or liability.

In accordance with ASC Topic 980, an accumulated over collected revenue true-up balance is classified as a regulatory liability in the balance sheets and an accumulated under collected revenue true-up balance is classified as a regulatory asset in the balance sheets.

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The Company recognizes a regulatory asset or liability for the cumulative difference between amounts recognized for AROs under ASC Topic 410 and amounts recovered through depreciation rates related to these obligations.

As of December 31, regulatory assets, which were all recorded as long-term assets in the balance sheets, included the following amounts (in thousands):

	2012		2011
2012 Network Revenue True-up to be Collected, Including Interest	$	2,058	$	—
2012 Multi-Value Projects Revenue True-up to be Collected, Including Interest	4,371		—
Postretirement Benefit Plan Amounts to be Recovered through Future Rates	900		1,915
Total Regulatory Assets	$	7,329	$	1,915

As described in note 1(d), the Company’s depreciation rates include an estimate for future asset removal costs which do not represent AROs.  The cumulative amounts that have been collected for future asset removal costs are reflected as regulatory liabilities.

As of December 31, regulatory liabilities included the following amounts (in thousands):

	2012		2011
2010 Regional Cost-sharing Revenue True-up Refunded in 2012, Including Interest	$	—	$	5,393
2011 Network Revenue True-up to be Refunded, Including Interest	1,276		9,073
2011 Regional Cost-sharing Revenue True-up to be Refunded, Including Interest	6,199		6,007
2012 Regional Cost-sharing Revenue True-up to be Refunded, Including Interest	1,486		—
Non-ARO Removal Costs Recovered through Rates	79,794		66,355
Cumulative Difference between ARO Costs Recovered through Rates and ARO Recognition under ASC Topic 410	1,860		955
Total Regulatory Liabilities	$	90,615	$	87,783

As of December 31, these amounts were classified in the balance sheets as follows (in thousands):

	2012		2011
Current Portion of Regulatory Liabilities	$	7,475	$	13,230
Regulatory Liabilities (long term)	83,140		74,553
Total Regulatory Liabilities	$	90,615	$	87,783

The Company continually assesses whether regulatory assets continue to meet the criteria for probability of future recovery. This assessment includes consideration of factors such as changes in the regulatory environment, recent rate orders to other regulated entities under the same jurisdiction and the status of any pending or potential deregulation legislation.  If the likelihood of future recovery of any regulatory asset

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becomes less than probable, the affected assets would be written off in the period in which such determination is made.

(i)Other Assets

As of December 31, other assets included the following (in thousands):

	2012		2011
Unamortized Debt Issuance Costs	$	8,694	$	8,124
Deferred Project Costs	198		2,173
Other	1,697		1,391
Total Other Assets	$	10,589	$	11,688

Deferred project costs are expenditures directly attributable to the construction of transmission assets.  These costs are recorded as other assets in the balance sheets until all required regulatory approvals are obtained and construction begins, at which time the costs are transferred to CWIP.  In accordance with its FERC-approved settlement agreement, the Company is allowed to expense and recover in rates, in the year incurred, certain preliminary survey and investigation costs related to study and planning work performed in the early stages of construction projects.  Other costs, such as advance equipment purchases and expenditures related to generator interconnection projects, continue to be deferred as described above.  Approximately $14.9 million, $10.9 million and $5.2 million of preliminary survey and investigation costs were included in operations and maintenance expense for 2012, 2011 and 2010, respectively.

(j)Impairment of Long-lived Assets

The Company reviews the carrying values of long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying values may not be recoverable under ASC Topic 360, “Property, Plant and Equipment”.  Impairment would be determined based upon a comparison of the undiscounted future operating cash flows to be generated during the remaining life of the assets to their carrying amounts.  An impairment loss would be measured as the amount that an asset’s carrying amount exceeds its fair value.  As long as its assets continue to be recovered through the ratemaking process, the Company believes that such impairment is unlikely.

(k)Income Taxes

The Company is a limited liability company that has elected to be treated as a partnership under the Internal Revenue Code and applicable state statutes.  The Company’s members (except certain tax-exempt members) report their share of the Company’s earnings, gains, losses, deductions and tax credits on their respective federal and state income tax returns.  Earnings before members’ income taxes reported in the statements of operations are the net income of the Company.  Accordingly, these financial statements do not include a provision for federal income tax expense and only include a provision for income taxes for the state of Michigan for the twelve months ended December 31, 2011 and 2010, since limited liability companies like the Company were considered taxable entities under the Michigan Business Tax (MBT) during those years.

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However, effective January 1, 2012, the MBT was replaced by a corporate income tax (CIT), which was signed into law on May 25, 2011. Pass-through entities, such as the Company, which were taxed at the entity level under the MBT, are not required to pay taxes or file returns under the CIT.  The Company’s taxable members, not the Company, are subject to the CIT.  The income tax provision reported in the statements of operations is derived in accordance with ASC Topic 740, “Income Taxes.”  As such, deferred income taxes have been recorded using current enacted tax rates for the differences between the tax basis of the Company’s assets and liabilities and the basis reported in the financial statements.  See note (6) for further discussion of income taxes, the CIT and the MBT.

(l)Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to apply policies and make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Estimates are used for items such as depreciable lives of property, plant and equipment, removal costs associated with asset retirements, tax provisions included in rates, actuarially determined benefit costs, accruals for construction costs and operations and maintenance expenses.  As additional information becomes available, or actual amounts are determined, the recorded estimates are revised.  Consequently, operating results can be affected by revisions to prior accounting estimates.

(m)New Accounting Pronouncements

In June 2011, the FASB issued Accounting Standards Update No. (ASU) 2011-05, “Comprehensive Income (Topic 220).”  ASU 2011-05 amends ASC Topic 220 on comprehensive income (1) to eliminate the current option to present the components of other comprehensive income (OCI) in the statement of changes in equity, (2) to require presentation of net income and OCI (and their respective components) either in a single continuous statement or in two separate but consecutive statements, and (3) to require presentation, on the face of the financial statements, reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented.  As the Company has no OCI, adoption of ASU 2011-05 did not have a material impact on the Company’s financial position, results of operations or cash flows.

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(2)Benefits

Management Inc. sponsors several benefit plans for its employees.  These plans include certain postretirement medical, dental, and life insurance benefits (“healthcare benefits”).  The weighted-average assumptions related to the postretirement healthcare benefits, as of the measurement date, are as follows:

	2012		2011		2010
Discount Rate	4.12	%	4.64	%	5.60	%
Medical Cost Trend:
Initial Range	7.00	%	7.80	%	8.20	%
Ultimate Range	4.00	%	5.00	%	5.00	%
Long-term Rate of Return on Plan Assets	6.00	%	6.00	%	6.00	%

The components of Management Inc.’s postretirement healthcare benefit costs for 2012, 2011 and 2010 are as follows (in thousands):

	2012			2011			2010
Service Cost	$	1,562		$	1,233		$	1,559
Interest Cost	977			881			1,039
Amortization of Prior Service Credit	(569		)	(569		)	(131		)
Amortization of Net Actuarial Loss	286			38			63
Expected Return on Plan Assets	(1,259		)	(1,102		)	(1,024		)
Net Periodic Postretirement Cost	$	997		$	481		$	1,506

To recognize the funded status of its postretirement healthcare benefit plans in accordance with ASC Topic 715, the Company recorded a long-term asset at December 31, 2012 of $0.8 million and a long-term liability at December 31, 2011 of $0.4 million. In addition, the Company had the following amounts not yet reflected in net periodic benefit cost and included in regulatory assets at December 31 (in thousands):

	2012			2011
Prior Service Credit	$	(4,154	)	$	(4,723	)
Accumulated Loss	5,054			6,638
Regulatory Asset for Amounts to be Collected in Future Rates	$	900		$	1,915

The assumed medical cost trend rates are critical assumptions in determining the service and interest cost and accumulated postretirement healthcare benefit obligation for the Company’s medical and dental plans. A one-percent change in the medical cost trend rates, holding all other assumptions constant, would have the following effects for 2012 (in thousands):

	One-Percent		One-Percent
	Increase		Decrease
Effect on Total of Service and Interest Cost Components	$	684	$	(507	)
Effect on Postretirement Benefit Obligation at the End of the Year	4,915		(3,811		)

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In 2013, the Company will recognize a $569 thousand prior service credit in its net periodic postretirement healthcare benefit cost related to a change made to the retiree cost-sharing provisions of the plan in 2010.

The funded status of the Company’s postretirement healthcare benefit plans as of December 31 is as follows (in thousands):

	2012			2011
Change in Projected Benefit Obligation:
Accumulated Postretirement Benefit Obligation at January 1	$	21,187		$	15,845
Service Cost	1,562			1,233
Interest Cost	977			881
Benefits Paid	(372		)	(455		)
Actuarial Losses	61			3,683
Benefit Obligation at December 31	$	23,415		$	21,187
Change in Plan Assets:
Fair Value of Plan Assets at January 1	$	20,783		$	19,200
Employer Contributions	1,136			2,320
Actual Return on Plan Assets (Net of Expenses)	2,619			(360		)
Net Benefits Paid	(294		)	(377		)
Fair Value at December 31	$	24,244		$	20,783
Funded Status at December 31	$	829		$	(404	)

The Company does not anticipate contributing to the plan for postretirement healthcare benefit obligations during 2013.

The Company anticipates net retiree healthcare benefit payments for the next 10 years to be as follows (in thousands):

2013	$	238
2014	331
2015	418
2016	481
2017	543
2018-2022	3,904
Total	$	5,915

To fund postretirement healthcare benefit obligations, the Company contributed to the Voluntary Employees’ Beneficiary Association (VEBA) trust in 2012 and 2011.  The VEBA trust, along with the 401(h) trust, are discretionary trusts with a long-term investment objective to preserve and enhance the post inflation value of the trusts’ assets, subject to cash flow requirements, while maintaining an acceptable level of volatility.

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The composition of the fair value of total plan assets held in the trusts as of December 31, along with targeted allocation percentages for each major category of plan assets in the trusts, is as follows:

	2012		2011		Target		Range
U.S. Equities	49	%	47	%	50	%	+/- 5	%
Non-U.S. Equities	11	%	10	%	15	%	+/- 4	%
Fixed Income	40	%	43	%	35	%	+/- 5	%
	100	%	100	%	100	%

The Company appoints a trustee to maintain investment discretion over trust assets.  The trustee is responsible for holding and investing plan assets in accordance with the terms of the Company’s trust agreement, including investing within the targeted allocation percentages.  The Company made a contribution to the VEBA trust on December 29, 2011, which was deposited in the VEBA trust’s Fixed Income asset class.  On January 3, 2012, the trustee reallocated the contribution within the trust to maintain the targeted allocation percentages shown above.

The asset classes designated above and described below serve as guides for the selection of individual investment vehicles by the trustee:

·U.S. Equities — Strategy of achieving long-term growth of capital and dividend income through investing primarily in common stock of companies in the U.S. stock market with the Wilshire 5000 Index (or a comparable broad U.S. stock index) as the investment benchmark.

·Non-U.S. Equities — Strategy of achieving long-term growth of capital and dividend income through investing primarily in common stock of companies in the non-U.S. stock markets with the Morgan Stanley Capital Index All Country World ex-U.S Index (or a comparable broad non-U.S. stock index) as the investment benchmark.

·Fixed Income — Strategy of achieving total return from current income and capital appreciation by investing in a diversified portfolio of fixed-income securities with the Barclays Capital Aggregate Index (or a comparable broad bond index) as the investment benchmark.

The objective of the investment vehicles is to minimize risk of large losses by effective diversification.  The investment vehicles will attempt to rank better than the median vehicle in their respective peer group.  However, these investments are intended to be viewed over the long term; during the short term, there will be fluctuations in rates of return characteristic of the securities markets.

The Company measures its plan assets at fair value according to the hierarchy set forth in ASC Topic 715.  The three levels of the fair value hierarchy under ASC Topic 715 are:

Level 1Inputs to the valuation methodology are unadjusted quoted prices for identical assets in active markets that the Company’s postretirement healthcare benefit plans have the ability to access.

Level 2Inputs to the valuation methodology include:

·Quoted prices for similar assets in active markets

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·Quoted prices for identical or similar assets or liabilities in inactive markets

·Inputs other than quoted prices that are observable for the asset or liability

·Inputs that are derived principally from, or corroborated by, observable market data by correlation or other means

If the asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.

Level 3Inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The asset’s or liability’s fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.  Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

At December 31, 2012 and 2011 a description of the valuation methodologies used for investments measured at fair value is as follows:

·Money Market Fund:  Valued at cost plus accrued interest, which approximates the fair value of the net asset value of the shares held by the plan at year-end.

·Mutual Funds: Valued at the net asset value of shares held by the plan at year-end.

The following table contains, by level within the fair value hierarchy, the Company’s postretirement healthcare benefit account investments at fair value as of December 31 (in thousands):

2012	Level 1		Level 2		Level 3		Total
U.S. Equity Mutual Funds	$	11,875	$	—	$	—	$	11,875
Non-U.S. Equity Mutual Fund	2,785		—		—		2,785
Fixed Income Mutual Funds	9,288		—		—		9,288
Money Market Fund	—		296		—		296
Total	$	23,948	$	296	$	—	$	24,244

2011	Level 1		Level 2		Level 3		Total
U.S. Equity Mutual Funds	$	9,700	$	—	$	—	$	9,700
Non-U.S. Equity Mutual Fund	2,135		—		—		2,135
Fixed Income Mutual Funds	6,510		—		—		6,510
Money Market Fund	—		2,438		—		2,438
Total	$	18,345	$	2,438	$	—	$	20,783

During 2012 and 2011, the Company had no transfers between Level 1 and Level 2 measurements and no transfers into or out of Level 3 measurements.  Measurements for the Company’s Level 2 inputs are based on inputs other than quoted prices that are observable for these assets.

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Management Inc. sponsors a defined contribution money-purchase pension plan, in which substantially all employees participate, and makes contributions to the plan for each participant based on several factors.  Contributions made by Management Inc. to the plan and charged to expense totaled $2.8 million in 2012 and $2.6 million in both 2011 and 2010.

Management Inc. also provides a deferred compensation plan for certain employees.  The plan allows for the elective deferral of a portion of an employee’s base salary and incentive compensation and also contains a supplemental retirement and 401(k) component.  Deferred amounts are taxable to the employee when paid, but the Company recognizes compensation expense in the period earned.  As of December 31, 2012 and 2011, $14.8 million and $13.3 million, respectively, were included in other long-term liabilities related to this deferred compensation plan.  Amounts charged to expense, including interest accruals, were $2.0 million in both 2012 and 2011 and $1.7 million in 2010.

(3)Members’ Equity

The Company’s members include investor-owned utilities, municipalities, municipal electric companies, and electric cooperatives.

Distribution of earnings to members is at the discretion of Management Inc.  The operating agreement of the Company established a target for distribution of 80% of annual earnings before members’ income taxes.  During 2012, 2011 and 2010, the Company distributed $188.2 million, $177.6 million, and $176.1 million, respectively, of its earnings to its members.  On January 25, 2013, the board of directors of Management Inc. approved a distribution for the fourth quarter of 2012, in the amount of $47.6 million, that was paid on January 31, 2013, bringing the total distributions for 2012 to 80% of earnings before members’ income taxes.

Each of the Company’s members has the right to require the Company to redeem all or a portion of its membership interests, so long as such interests have been outstanding for at least 12 months.  However, the Company is not required to effect the redemption by non-managing members if Management Inc., in its sole discretion as the corporate manager, elects to purchase, in lieu of redemption, such membership interests for either a specified amount of cash or a specified number of shares of its common stock.  After such purchase, Management Inc. shall be deemed the owner of such membership interests.

During 2012, the Company issued 3,829,479 units to members in exchange for $60.0 million in cash.

Management Inc. has issued shares of its common stock to each of the Company’s members or their affiliates in proportion to their ownership interests in the Company.  Holders of Management Inc. common stock have the rights of shareholders under Wisconsin law, including the right to elect directors of the corporate manager in accordance with the Company’s operating agreement.

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(4)Debt

(a)Credit Facility

The Company’s $300 million, three-year revolving credit facility, which had a termination date of January 31, 2014, was amended on December 7, 2012.  The amended credit facility is $350 million and has a five-year term, which expires on December 7, 2017.  The facility provides backup liquidity to the Company’s commercial paper program.  While the Company does not intend to borrow under the revolving credit facility, interest rates on outstanding borrowings under the facility would be based on a floating rate plus a margin.  The applicable margin, which is based on the Company’s debt rating of A1/A+ or equivalent, is currently 0.8%.

The revolving credit facility contains restrictive covenants, including restrictions on liens, certain mergers, sales of assets, acquisitions, investments, transactions with affiliates, change of control, conditions on prepayment of other debt, and the requirement of the Company to meet certain financial reporting obligations.  The revolving credit facility provides for certain customary events of default, including a targeted total-debt-to-total-capitalization ratio that is not permitted to exceed 65% at any given time.  The Company was not in violation of any restrictive covenants under its credit facility during the periods covered by these financial statements.

The Company had no outstanding balance under its credit facility as of December 31, 2012 or 2011.

(b)Commercial Paper

The Company currently has a $350 million unsecured, private placement, commercial paper program, which was increased from $300 million in conjunction with the increase in the Company’s credit facility.  Investors are limited to qualified institutional buyers and institutional-accredited investors.  Maturities may be up to 364 days from date of issue, with proceeds to be used for working capital and other capital expenditures.  Pricing is par, less a discount or, if interest-bearing, at par.  The Company had $166.6 million of commercial paper outstanding as of December 31, 2012 at an average rate of 0.22% and $184.3 million of commercial paper outstanding as of December 31, 2011 at an average rate of 0.24%.  As defined by the commercial paper program, no customary events of default took place during the periods covered by the accompanying financial statements.

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(c)Long-term Debt

The following table summarizes the Company’s long-term debt commitments as of December 31 (in thousands):

	2012		2011
Senior Notes at stated rate of 7.02%, due August 31, 2032	$	50,000	$	50,000
Senior Notes at stated rate of 6.79%, due on dates ranging from August 31, 2024 to August 31, 2043	100,000		100,000
Senior Notes at stated rate of 4.992%, due April 15, 2015	100,000		100,000
Senior Notes at stated rate of 5.59%, due December 1, 2035	100,000		100,000
Senior Notes at stated rate of 5.91%, due August 1, 2037	250,000		250,000
Senior Notes at stated rate of 5.58%, due April 30, 2018	200,000		200,000
Senior Notes at stated rate of 5.40%, due May 15, 2019	150,000		150,000
Senior Notes at stated rate of 4.59%, due February 1, 2022	100,000		100,000
Senior Notes at stated rate of 5.72%, due April 1, 2040	50,000		50,000
Senior Notes at stated rate of 4.17%, due March 14, 2026	75,000		75,000
Senior Notes at stated rate of 4.27%, due March 14, 2026	75,000		75,000
Senior Notes at stated rate of 5.17%, due March 14, 2041	150,000		150,000
Senior Notes at stated rate of 4.37%, due April 18, 2042	150,000		—
Other Long-term Notes Payable	—		5
Total Long-term Debt	$	1,550,000	$	1,400,005

The senior notes rank equivalent in right of payment with all of the Company’s existing and future unsubordinated, unsecured indebtedness and senior in right of payment to all subordinated indebtedness of the Company.

The senior notes contain restrictive covenants, which include restrictions on liens, certain mergers and sales of assets, and the requirement of the Company to meet certain financial reporting obligations.  The senior notes also provide for certain customary events of default, none of which occurred during the periods covered by the accompanying financial statements.

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Future maturities of the Company’s senior notes are as follows (in millions):

2013	$	—
2014	—
2015	100
2016	—
2017	—
Thereafter	1,450
	$	1,550

The senior notes contain an optional redemption provision whereby the Company is required to make the note holders whole on any redemption prior to maturity.  The notes may be redeemed at any time, at the Company’s discretion, at a redemption price equal to the greater of 100% of the principal amount of the notes plus any accrued interest or the present value of the remaining scheduled payments of principal and interest from the redemption date to the maturity date discounted to the redemption date on a semiannual basis at the then-existing Treasury rate plus 30 to 50 basis points, plus any accrued interest.

During February 2012, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $150 million of 30-year, unsecured 4.37% senior notes.  The closing and funding of the notes occurred on April 18, 2012.  The notes pay interest semiannually on April 18 and October 18 and will mature on April 18, 2042.

During December 2010, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $75 million of 15-year, unsecured 4.17% senior notes, $75 million of 15-year, unsecured 4.27% senior notes and $150 million of 30-year, unsecured 5.17% senior notes.  The closing and funding of the $75 million, 4.17% issuance occurred on December 15, 2010 and the funding of the remaining issuances occurred on March 14, 2011.  The notes pay interest semiannually on March 15 and September 15.  The 15-year notes will mature on March 14, 2026 and the 30-year notes will mature on March 14, 2041.  The Company used the proceeds of these issuances to repay $300 million of long-term debt that matured on March 15, 2011.

(5)Fair Value of Financial Instruments

The carrying amount of the Company’s financial instruments included in current assets and current liabilities approximates fair value due to the short maturity of such financial instruments.  The fair value of the Company’s long-term debt is estimated based upon quoted market values for the same or similar issues or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the Company’s credit ratings.

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The carrying amount and the estimated fair value of the Company’s long-term debt at December 31 are as follows (in millions):

	2012		2011
Carrying Amount	$	1,550.0	$	1,400.0
Estimated Fair Value	1,836.2		1,660.7

(6)Income Taxes

As mentioned in note 1(k), the Company was considered a taxable entity under the MBT until the MBT was replaced with the CIT effective January 1, 2012.  The Company was subject to the MBT, which was accounted for as an income tax under the provisions of ASC Topic 740 and recovered as a component of the Company’s revenue requirement.  During 2010, the Company’s financial statements included a provision of $1.5 million for the MBT.  As a result of the CIT, which was signed into law on May 25, 2011, the Company recorded a non-cash credit of $2.1 million to income tax expense of ATC LLC during the second quarter of 2011 to reverse net deferred income taxes related to the MBT for periods beyond 2011.  Partially offsetting this credit was a $0.3 million current provision for MBT recorded in 2011, which resulted in a net credit amount of $1.8 million in income tax expense of ATC LLC in the statement of operations for the twelve months ended December 31, 2011.  During the third quarter of 2012, the Company filed its 2011 tax return with the state of Michigan and requested a refund of $0.3 million. As such, the Company recorded a credit of that same amount to income tax expense of ATC LLC in 2012.

As of December 31, 2012 and 2011, the Company had no deferred tax amounts related to the MBT in other long-term liabilities in its statements of financial position.

The Company is allowed to recover in rates, as a component of its cost of service, its income taxes, as well as the amount of income taxes that are the responsibility of its members.  Accordingly, the Company includes a provision for its members’ federal and state current and deferred income tax expenses and amortization of the excess deferred tax reserves and deferred investment tax credits associated with assets transferred to the Company by its members in its regulatory financial reports and rate filings.  For purposes of determining the Company’s revenue requirement under FERC-approved rates, rate base is reduced by an amount equivalent to members’ net accumulated deferred income taxes, including excess deferred income tax reserves.  Such amounts were approximately $422.1 million, $364.1 million and $287.9 million in 2012, 2011 and 2010, respectively, and are primarily related to accelerated tax depreciation and other plant-related differences.  The 2012, 2011 and 2010 revenues include recovery of $95 million, $86.4 million, and $87.8 million, respectively, of income tax expense.

On December 17, 2010, President Obama signed the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (“2010 Tax Act”) into law.  One of the elements of the 2010 Tax Act increased bonus depreciation from 50% to 100% on assets placed in service after September 8, 2010 and before January 1, 2012.  The 2010 Tax Act also allowed a transitional 100% bonus depreciation for self-constructed assets that had started construction before December 31, 2011 and were in service by December 31, 2012.  On January 2, 2013, President Obama signed the American Taxpayer Relief Act of 2012, which extended the current 50% bonus depreciation through 2013.

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ASC Topic 740 provides guidance on recognition thresholds and measurement of a tax position taken or expected to be taken in a tax return, including whether an entity is taxable in a particular jurisdiction.  This guidance applies to all entities, including pass-through entities such as the Company.  The Company does not consider any of its tax positions to be uncertain, including the Company’s position that it qualifies as a pass-through entity in the federal and Wisconsin tax jurisdictions.  Additionally, the Company had no unrecognized tax benefits and was assessed no interest or penalties during 2012, 2011 or 2010.  The Company is no longer subject to examination by the Internal Revenue Service for tax years prior to 2009 or any state jurisdiction for tax years prior to 2008.  In the event the Company would be assessed interest or penalties by a taxing authority related to income taxes, interest would be recorded in interest expense and penalties would be recorded in other expense in the statements of operations.

Under an existing federal program, many entities, including the Company, received tax-free reimbursements under the Medicare Part D retiree drug subsidy (RDS) program to encourage them to provide retiree prescription drug coverage.  The tax advantage of the reimbursements under the RDS program has been eliminated by the Patient Protection and Affordable Care Act (H.R. 3590), including modifications included in the Health Care and Education Reconciling Act of 2010 (“the Act”) passed by Congress on March 25, 2010, and signed into law by President Obama on March 30, 2010.  Although the elimination of this tax advantage does not take effect until 2013 under the Act, the Company is required to recognize the full accounting impact in its financial statements in the period in which the Act was signed.  Management Inc. allocates the tax benefit or expense of permanent differences such as the Medicare Part D subsidy to the Company in the form of a higher or lower management fee.  Because Management Inc. had already recognized future retiree healthcare liabilities and related tax impacts in its financial statements, the change in the tax treatment under the Act resulted in a reduction of the value of Management Inc.’s deferred tax asset related to the RDS program.  The reduction in value of the deferred tax asset was passed through to the Company in the form of an increased management fee.  As a result, the Company recorded a non-cash charge of approximately $1.5 million in taxes other than income in the statement of income in the first quarter of 2010, which the Company recovered through its revenue requirement.

(7)Commitments and Contingencies

(a)Operating Leases

The Company leases office space and certain transmission-related equipment under non-cancelable operating leases.  Amounts incurred during 2012, 2011 and 2010 totaled approximately $5.9 million, $6.5 million and $7.0 million, respectively.

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Future minimum lease payments under non-cancelable operating leases for the years ending December 31 are as follows (in millions):

2013	$	6.2
2014	5.7
2015	5.7
2016	5.6
2017	5.3
Thereafter	47.0
	$		75.5

(b)Smart Grid Agreements

On April 20, 2010, the Company entered into two agreements with the U.S. Department of Energy (DOE), accepting investment grants for up to 50% of the cost of the related projects.  The grants, totaling $12.7 million, are to invest in smart grid technologies to be incorporated into the Company’s transmission system.  Any funds the Company receives from the DOE under the grant award agreements will reduce the amount of investment in such projects upon which the Company will earn a return.  The Company continues to invoice the DOE and receive payments under these agreements, and expects to complete construction on these projects by April 2013.  Per the terms of these agreements, the Company completed an independent audit of the smart grid projects, the result of which was submitted to the DOE.  The report was concluded with no audit findings.

(c)MISO Revenue Distribution

Periodically, the Company receives adjustments to revenues that were allocated to it by MISO in prior periods.  Some of these adjustments may result from disputes filed by transmission customers. The Company does not expect any such adjustments to have a significant impact on its financial position, results of operations or cash flows since adjustments of this nature are typically offset by its true-up provision in the revenue requirement formula.

(d)Interconnection Agreements

The Company has entered into interconnection agreements with entities planning to build generation plants.  The Company will construct the facilities; however, the generator will finance and bear all financial risk of constructing the interconnection facilities under these agreements.  The Company will own and operate the interconnection facilities when the generation plants become operational and will reimburse the generator for construction costs plus interest.  If the generation plants do not become operational, the Company has no obligation to reimburse the generator for costs incurred during construction.

The estimate of the Company’s commitments under these agreements, if the generation plants become operational, is approximately $5.2 million at completion, with expected completion during 2016.  In addition, there may be transmission service requests that require the Company to construct additional, or modify existing, transmission facilities to accommodate such requests.  Whether such additions or upgrades to the

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Company’s transmission system are required depends on the state of the transmission system at the time the transmission service is requested.  Under these agreements, the Company reimbursed, inclusive of interest, $13.0 million, $3.0 million and $3.3 million to generators during 2012, 2011 and 2010, respectively.  The Company does not expect to make any reimbursements to generators in 2013 under such agreements.

(e)Potential Adverse Legal Proceedings

The Company has been, and will likely in the future become, party to lawsuits, potentially including suits that may involve claims for which it may not have sufficient insurance coverage.  The Company’s liability is limited by FERC-approved provisions of the MISO tariff that limit potential damages to direct damages caused by the Company’s gross negligence or intentional misconduct.

(f)Environmental  Matters

In the future, the Company may become party to proceedings pursuant to federal and/or state laws or regulations related to the discharge of materials into the environment. Such proceedings may involve property the Company acquired from the contributing utilities. Pursuant to the asset purchase agreements executed with the contributing utilities beginning January 1, 2001, the contributing utilities will indemnify the Company for 25 years from such date for any environmental liability resulting from the previous ownership of the property.

(8)Related-Party Transactions

(a)Membership Interests

To maintain its targeted debt-to-capitalization ratio, the Company was authorized by Management Inc.’s board of directors to request up to $25 million of additional capital through voluntary additional capital calls during 2013, including $5 million it received in January 2013.  The Company also received a total of $60 million through voluntary additional capital calls in 2012 and $25 million through capital calls in 2011.  The participating members received additional membership units at the current book value per unit at the time of each contribution.  Contributions from capital calls are recognized when received.

(b)Duke-American Transmission Company LLC

In April 2011, the Company announced that it had entered into a joint venture with Duke Energy to create the Duke-American Transmission Company LLC (DATC).  DATC will own all of the transmission assets it builds and operates. Equity ownership of DATC will be split equally between Duke Energy and the Company.  DATC has begun identifying opportunities to build, own and operate new transmission projects that meet potential customers’ capacity, voltage requirements and future needs.  During the third quarter of 2011, DATC released its first set of transmission projects that include a portfolio of seven new transmission line projects in five Midwestern states. This portfolio, referred to as the DATC Midwest Portfolio, will fill gaps in the existing transmission grid, improve electric system reliability and market efficiency, provide economic benefits to local utilities and enable increased delivery of high-quality renewable resources. The DATC Midwest Portfolio includes more than 1,200 circuit miles of 345 kilovolt (kV) lines and 550 miles of 500 kV

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high-voltage direct-current lines. The individual circuits range from 65 to 696 miles and have a total estimated cost of approximately $4 billion.  Construction of this portfolio is not expected to begin until 2015 or later.  DATC has been working with MISO to include the projects in their regional transmission plans.  On April 20, 2012, DATC filed an application with the FERC for acceptance of a proposed formula rate treatment and approval of transmission rate incentives for the projects under Docket No. ER12-1593-000.  On June 19, 2012, the FERC:

a)granted DATC’s request for transmission rate incentives, conditioned on the projects’ approval in the MISO Transmission Expansion Plan,

b)authorized certain ratemaking proposals and accepted and nominally suspended the proposed formula rate template, subject to refund, and established hearing and settlement judge procedures,

c)accepted the formula rate protocols, subject to outcome of another proceeding.

The basic rate proposal, while modified slightly as a result of the settlement discussions, was included in a settlement that was filed with the FERC on November 9, 2012 and the FERC staff filed comments in support of the settlement on November 29, 2012.  The settlement is awaiting certification from the settlement judge.

On December 19, 2011, the Company announced that DATC acquired the Zephyr Power Transmission Project (“Zephyr”) and will continue the design and development of the proposed 950 mile transmission line that would deliver wind energy generated in eastern Wyoming to California and the southwestern United States.  DATC acquired Zephyr from a subsidiary of Pathfinder Renewable Wind Energy LLC (“Pathfinder”).  Pathfinder is developing a wind power project on more than 100,000 acres near Chugwater, Wyoming, and has committed to use at least 2,100 megawatts (MW) of the Zephyr project’s 3,000 MW capacity.  The 500 kV high-voltage direct-current project, estimated at approximately $3.5 billion, will include an AC/DC converter station at each terminus.  DATC paid Pathfinder a nominal amount for the acquisition of Zephyr.  If certain milestones materialize under the project agreement, DATC would be required to pay, directly or indirectly, Pathfinder’s share of regulatory phase project costs of up to $5 million incurred throughout 2012 and 2013; however, DATC has the right to terminate the project at any time prior to January 15, 2014.  On April 6, 2012 DATC received FERC approval in Docket No. EL12-22-000 to charge previously negotiated rates and requested waivers approved by FERC under Zephyr’s previous ownership.

The balance in the Company’s investment in DATC account, which was not material at December 31, 2011, was $0.8 million at December 31, 2012.

(c)Operations and Maintenance and Transitional Services Agreements

From the Company’s inception until August 21, 2009, the Company operated under Transitional Services and Operation and Maintenance Agreements whereby contributing utilities, municipalities and cooperatives provided certain administrative, operational, maintenance and construction services to the Company at a fully-allocated cost.  On August 21, 2009, however, the PSCW ordered that work under the Transitional Services Agreements be completed and that the Company should not continue to use such agreements.  At that same time, the PSCW approved Project Services Agreements (PSAs) and Common Facilities Agreements (CFAs) for a two-year pilot period whereby the Company and certain of its affiliates may perform engineering and construction services for each other, subject to the restrictions and reporting requirements specified in the order.  On October 10, 2011, the Company and certain contributing utilities filed a request to extend the applicable PSAs and CFAs and the PSCW granted a one-year extension in

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December 2011.  To prevent cross-subsidization between affiliated interests, the PSCW ordered that services be performed at a fully-allocated cost of the party providing services.  On October 24, 2012, the PSCW issued an order granting a request the Company had made that it be allowed to continue the reporting requirements under PSAs and CFAs without the requirement to request renewal of such agreements every year.  The Company believes that the costs it must incur to procure engineering, construction, operations and maintenance services will be recoverable in future rates.

Several of the original operation and maintenance agreements continue in effect.  These original agreements automatically renew on a year-to-year basis unless terminated by either party.  Some new agreements have been executed with contributing and non-contributing entities and approved by the PSCW, as required.  Some agreements require the Company to utilize a specified percentage of the services performed in a previous representative year as a minimum level of service.  To date, the amounts utilized have exceeded the minimum in each year.

The Company was billed approximately $35.3 million, $39.8 million and $44.7 million in 2012, 2011 and 2010, respectively, under these agreements.  Accounts payable and other accrued liabilities include amounts payable to these companies of $3.7 million and $3.2 million at December 31, 2012 and 2011, respectively.

(d)Transmission Service

Revenues from the Company’s members were in excess of 95% of the Company’s transmission service revenue for the years ended December 31, 2012, 2011 and 2010.

(e)Agreement with Alliant Energy

The Company has an agreement with Alliant Energy (“Alliant”), under which it provides control center and operation services for Alliant’s 34.5 kV distribution system in the state of Wisconsin.  The agreement automatically renews every two years, unless terminated by either party.  Amounts the Company has received from Alliant for these services are not material to the financial statements.

(f)Management Inc.

As discussed in note 1(b), Management Inc. manages the Company.  Management Inc. charged the Company approximately $89.4 million, $82.6 million and $77.4 million in 2012, 2011 and 2010, respectively, primarily for employee-related expenses.  These amounts were charged to the applicable operating expense accounts, or capitalized as CWIP or other assets, as appropriate.  The amounts are recorded in the Company’s accounts in the same categories in which the amounts would have been recorded had the Company incurred the costs directly.

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(g)Interconnection Agreements

As discussed in notes 1(f) and 7(d), the Company has interconnection agreements related to the capital improvements required to connect new generation equipment to the grid.  Some of these agreements are with members or affiliates of members of the Company.  At December 31, 2011, liabilities included $5.3 million of amounts received related to these agreements from entities that are also members of the Company.  There were no outstanding liabilities at December 31, 2012, related to these agreements.  The Company reimbursed, inclusive of interest, $5.3 million and $0.9 million to members under such agreements in 2012 and 2011, respectively.  The Company does not expect to make any reimbursements to members in 2013 under such agreements.

(9)Quarterly Financial Information (unaudited)

	Three Months Ended
	2012
(In Thousands)	March 31		June 30		September 30		December 31		Total
Operating Revenues	$	147,662	$	152,171	$	150,303	$	153,118	$	603,254
Operating Expenses	69,566		71,760		68,813		70,860		280,999
Operating Income	78,096		80,411		81,490		82,258		322,255
Other Expense, Net	500		327		5		1,701		2,533
Interest Expense, Net	19,501		20,776		20,983		21,036		82,296
Earnings Before Members’ Income Taxes	$	58,095	$	59,308	$	60,502	$	59,521	$	237,426

	2011
	March 31		June 30		September 30		December 31		Total
Operating Revenues	$	139,617	$	138,204	$	142,741	$	146,612	$	567,174
Operating Expenses	63,126		62,952		66,413		69,077		261,568
Operating Income	76,491		75,252		76,328		77,535		305,606		��
Other Expense, Net	358		134		173		667		1,332
Interest Expense, Net	21,897		19,479		19,517		19,466		80,359
Earnings Before Members’ Income Taxes	$	54,236	$	55,639	$	56,638	$	57,402	$	223,915

Because of seasonal factors impacting the Company’s business, particularly the maintenance and construction programs, quarterly results are not necessarily comparable.  In general, due to the Company’s rate formula, revenues and operating income will increase throughout the year, as the Company’s rate base increases through expenditures for CWIP.

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