WEC Energy 10K 2015 Annual report | WEC Filing

Exhibit 99.1

AMERICAN TRANSMISSION COMPANY LLC

Financial Statements and Independent Auditors’ Report

As of December 31, 2015 and 2014

and for the Years Ended December 31, 2015, 2014 and 2013

Exhibit 99.1



American Transmission Company LLC

Table of Contents

Independent Auditors' Report .............................................................................................................		3

Financial Statements

	Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013 .................	4

	Balance Sheets as of December 31, 2015 and 2014 ..................................................................	5

	Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 ................	6

	Statements of Changes in Members' Equity for the Years Ended December 31, 2015, 2014 and 2013 .............................................................................................................................................	7

	Notes to Financial Statements as of December 31, 2015 and 2014 and for the Years Ended December 31, 2015, 2014 and 2013 ...........................................................................................	8-33

Management's Discussion and Analysis of Financial Condition and Results of Operations ............		34-53

Qualitative Disclosures about Market Risks ...........................................................................................		53

Exhibit 99.1

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of ATC Management Inc.,

Corporate Manager of American Transmission Company LLC Pewaukee, Wisconsin

We have audited the accompanying financial statements of American Transmission Company LLC (the “Company”), which comprise the balance sheets as of December 31, 2015 and 2014, 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, 2015, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America and 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 from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design 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. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of American Transmission Company LLC as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in accordance with accounting principles generally accepted in the United States of America.

Milwaukee, Wisconsin

February 2, 2016

Exhibit 99.1

American Transmission Company LLC

Statements of Operations

For the Years Ended December 31, 2015, 2014 and 2013

(In Thousands)



	2015		2014		2013
Operating Revenues
Transmission Service Revenue	$	614,277	$	633,550	$	624,922
Other Operating Revenue	1,559		1,483		1,414
Total Operating Revenues	615,836		635,033		626,336

Operating Expenses
Operations and Maintenance	162,840		162,902		161,129
Depreciation and Amortization	133,265		124,074		114,808
Taxes Other than Income	23,216		20,475		19,132
Total Operating Expenses	319,321		307,451		295,069

Operating Income	296,515		327,582		331,267



Other Income, Net	1,176		117		831

Earnings Before Interest and Members' Income Taxes	297,691		327,699		332,098



Interest Expense	97,250		88,970		84,484

Earnings Before Members' Income Taxes	$	200,441	$	238,729	$	247,614

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

Exhibit 99.1

American Transmission Company LLC

Balance Sheets

As of December 31, 2015 and 2014

(In Thousands)



ASSETS	December 31, 2015			December 31, 2014
Property, Plant and Equipment
Transmission Plant	$	4,655,719		$	4,400,823
General Plant	122,745			108,902
Less-Accumulated Depreciation	(1,100,828		)	(1,022,123		)
	3,677,636			3,487,602
Construction Work in Progress	229,824			180,058
Net Property, Plant and Equipment	3,907,460			3,667,660


Current Assets
Cash and Cash Equivalents	—			97
Accounts Receivable	59,694			55,984
Prepaid Expenses	6,707			6,303
Current Portion of Regulatory Assets	10,772			719
Other Current Assets	3,347			3,307
Total Current Assets	80,520			66,410


Regulatory and Other Assets
Equity Investment in Unconsolidated Subsidiary	37,077			35,317
Regulatory Assets	393			9,343
Other Assets	12,646			16,355
Total Regulatory and Other Assets	50,116			61,015
Total Assets	$	4,038,096		$	3,795,085

CAPITALIZATION AND LIABILITIES
Capitalization
Members' Equity (See Note 3 for redemption provisions)	$	1,662,828		$	1,617,202
Long-term Debt (excluding current portion)	1,800,029			1,701,000
Total Capitalization	3,462,857			3,318,202


Current Liabilities
Accounts Payable	16,947			11,746
Accrued Interest	23,947			24,198
Other Accrued Liabilities	50,424			42,918
Current Portion of Regulatory Liabilities	12,617			14,299
Current Maturities of Long-term Debt	—			100,000
Short-term Debt	226,313			119,904
Total Current Liabilities	330,248			313,065


Regulatory and Other Long-term Liabilities
Regulatory Liabilities	236,551			146,525
Other Long-term Liabilities	8,440			17,293
Total Regulatory and Other Long-term Liabilities	244,991			163,818


Commitments and Contingencies (See Note 7)	—			—
Total Capitalization and Liabilities	$	4,038,096		$	3,795,085

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

Exhibit 99.1

American Transmission Company LLC

Statements of Cash Flows

For the Years Ended December 31, 2015, 2014 and 2013

(In Thousands)



	2015			2014			2013
Cash Flows from Operating Activities
Earnings Before Members' Income Taxes	$	200,441		$	238,729		$	247,614
Adjustments to Reconcile Earnings Before Members' Income Taxes to Net
Cash Provided by Operating Activities-
Depreciation and Amortization	133,265			124,074			114,808
Bond Discount and Debt Issuance Cost Amortization	582			537			488
Equity Earnings in Unconsolidated Subsidiary Investment	(1,760		)	(1,998		)	(1,842		)
Change in-
Accounts Receivable	(3,710		)	9,795			(9,260		)
Other Current Assets	(4,134		)	5,325			(3,010		)
Accounts Payable	69			(2,545		)	1,576
Accrued Liabilities	(713		)	3,735			6,076
Regulatory Liabilities	71,918			12,759			11,511
Other, Net	(7,020		)	(2,550		)	(1,745		)
Total Adjustments	188,497			149,132			118,602
Net Cash Provided by Operating Activities	388,938			387,861			366,216


Cash Flows from Investment Activities
Capital Expenditures for Property, Plant and Equipment	(339,159		)	(334,731		)	(328,414		)
Investment in Unconsolidated Subsidiary	—			(1,600		)	(32,800		)
Return of Capital from Unconsolidated Subsidiary	—			—			3,700
Insurance Proceeds Received for Damaged Property, Plant and Equipment	—			646			—
Net Cash Used in Investing Activities	(339,159		)	(335,685		)	(357,514		)


Cash Flows from Financing Activities
Distribution of Earnings to Members	(174,815		)	(204,125		)	(195,484		)
Issuance of Membership Units for Cash	20,000			50,000			40,000
Issuance (Repayment) of Short-term Debt, Net	106,390			(160,541		)	113,884
Issuance of Long-term Debt, Net of Issuance Costs	98,099			249,752			—
Repayment of Long-term Debt	(100,000		)	—			—
Advances Received for Construction	440			12,797			32,856
Other, Net	10			38			(75		)
Net Cash Used in Financing Activities	(49,876		)	(52,079		)	(8,819		)


Net Change in Cash and Cash Equivalents	(97		)	97			(117		)

Cash and Cash Equivalents, Beginning of Period	97			—			117
Cash and Cash Equivalents, End of Period	$	—		$	97		$	—

Supplemental Disclosures of Cash Flows Information
Cash Paid for-
Interest	$	92,529		$	85,556		$	83,489
Significant Non-cash Investing or Financing Transactions-
Accruals and Payables Related to Construction Costs	$	36,208		$	24,771		$	33,841

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

Exhibit 99.1

American Transmission Company LLC

Statements of Changes in Members' Equity

As of December 31, 2015, 2014 and 2013

(In Thousands)



Members' Equity as of December 31, 2012		$	1,440,468

Membership Units Outstanding at December 31, 2012	82,154



Issurance of Membership Units		$	40,000

Earnings Before Members' Income Taxes		247,614

Distribution of Earnings to Members		(195,484		)

Members' Equity as of December 31, 2013		$	1,532,598

Membership Units Outstanding at December 31, 2013	84,614



Issuance of Membership Units		$	50,000

Earnings Before Members' Income Taxes		238,729

Distribution of Earnings to Members		(204,125		)

Members' Equity as of December 31, 2014		$	1,617,202

Membership Units Outstanding at December 31, 2014	87,588



Issuance of Membership Units		$	20,000

Earnings Before Members' Income Taxes		200,441

Distribution of Earnings to Members		(174,815		)

Members' Equity as of December 31, 2015		$	1,662,828

Membership Units Outstanding at December 31, 2015	88,740

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

Exhibit 99.1

American Transmission Company LLC

Notes to Financial Statements as of December 31, 2015 and 2014 and for the Years Ended

December 31, 2015, 2014 and 2013

(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 currently owns and operates the electric transmission system, under the direction of the Midcontinent Independent 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 approximately 80 percent of the Company’s operating revenues. The rates for these transmission services are subject to review and approval by FERC. In addition, several members provide operational, 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 2, 2016, 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.

Exhibit 99.1

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



	2015		2014
Other Accrued Liabilities	$	15,054	$	14,300
Other Long-term Liabilities	490		9,436
Net Amount Payable to Management Inc.	$	15,544	$	23,736

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). The payable to Management Inc. is partially offset by a $15.1 million and $14.3 million receivable as of December 31, 2015 and 2014, 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.

Under the authority of the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (“MISO Tariff”), which is regulated by FERC, the Company provides wholesale electric transmission service to eligible entities within its service area. The Company charges for these services under FERC-approved rates. The MISO Tariff specifies the general terms and conditions of service on the Company’s transmission system and establishes the rates and 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 (“Company’s 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) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” Accordingly, the Company recognizes revenue for providing transmission system access to its customers during the rate year based on the revenue requirement formula in the Company’s 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, and projected revenues to be received from MISO. From this forecast, the Company computes an annual projected total revenue requirement for the rate year. 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 twelve 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 rate year. 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 the balance sheets. The Company is

Exhibit 99.1

required to refund any over-collected network 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 network amounts, plus interest, in annual network billings two fiscal years subsequent to the rate year. Under these true-up provisions, the Company refunded to network customers, through their monthly bills, $9.9 million in 2015, a net amount of $10.4 million in 2014, and $1.3 million in 2013. The Company also has FERC-approved true-up provisions for MISO regional cost-sharing revenues to refund over collections or receive under collections in the second year subsequent to the rate year. The Company refunded, inclusive of interest, a net amount of $3.9 million to regional customers in 2015, $6.3 million in 2013 and collected, inclusive of interest, a net amount of $2.8 million from regional customers in 2014. 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 FERC in 2004. The Company may elect to change, or intervenors may request a change to, the Company’s revenue requirement formula at any time. A change to the revenue requirement formula could result in reduced 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.

On November 12, 2013, MISO, the Company and numerous other MISO transmission owners were named as respondents in a complaint filed at FERC pursuant to Section 206 of the Federal Power Act (“Section 206”) by several customer groups located within the MISO service area. The complaint claims that the respondents’ transmission rates are no longer just and reasonable and seeks, among other things, to reduce the MISO base return on equity (ROE). The Company and the other MISO transmission owners responded to the complaint with a motion to dismiss and answer objecting to the claims of the complainants. On October 16, 2014, FERC determined that the complaint raises issues of material fact that cannot be resolved with the information in the record at this point. As a result, FERC put the matter of whether the MISO transmission owner base ROE is unjust and unreasonable to hearing and settlement procedures, and established a refund date of November 12, 2013. However, the settlement process was terminated in December 2014. FERC ordered hearing proceedings to begin in January 2015 and an initial decision in the complaint was received from the administrative law judge (ALJ) on December 22, 2015. FERC, which is not bound by the ALJ decision, is expected to rule on this complaint by October 2016.

In a related matter, on February 12, 2015, a group of public power entities filed a second Section 206 complaint against the base ROE of the Company and other MISO transmission owners, claiming that the current ROEs are no longer just and reasonable. The Company and the other transmission owners named in the complaint filed an answer with FERC on March 11, 2015, requesting that FERC deny the complaint. On June 18, 2015, FERC found that the complaint raises issues of material fact that cannot be resolved based upon the record. FERC set the matter for hearing procedures and set a refund effective date of February 12, 2015. On July 10, 2015, the ALJ set the schedule for the hearing procedures, which will conclude with the initial decision from the ALJ due June 30, 2016.

Further details related to these complaints are discussed in Note 7(a).

Exhibit 99.1

(d) Transmission and General Plant and Related Depreciation

Transmission plant is recorded at the original cost of construction which 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 removal costs are included in regulatory liabilities in the balance sheets, as described in Note 1(h). Costs that the Company incurs to remove an asset when not under a legal obligation to do so are charged against the regulatory liability. Depreciation expense on transmission assets, including a provision for removal costs, as a percentage of average transmission plant was 2.74 percent in both 2015 and 2014 and 2.73 percent in 2013.

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 60 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 years ended December 31, 2015 and 2014 (in thousands):



	2015			2014
Asset Retirement Obligations at January 1	$	7,552		$	7,242
Accretion	375			361
Liabilities Settled	(88		)	(51		)
Asset Retirement Obligations at December 31	$	7,839		$	7,552

Exhibit 99.1

(f) Interconnection Agreements

The Company routinely enters into interconnection agreements with entities planning to build generation facilities. The Company will construct the interconnection 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 facilities become operational and will reimburse the generator for construction costs plus interest. If the generation facilities 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 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, 2015 and 2014 the Company had no active projects related to these agreements. Therefore, at December 31, 2015 and 2014 there were no amounts included in CWIP or liabilities related to cash advances from generator interconnection agreements.

(g) Cash and Cash Equivalents

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

(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 and do not earn a current return. 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 funded 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.

Exhibit 99.1

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 included the following amounts (in thousands):



	2015		2014
Revenue True-ups, Including Interest
2013 Regional Cost-sharing Revenue Collected in 2015	$	—	$	719
2014 Multi-Value Projects Revenue to be Collected in 2016	1,490		1,486
2014 Scheduling Revenue to be Collected in 2016	4,887		4,877
2015 Scheduling Revenue to be Collected in 2017	393		—
Other Network Revenue to be Collected in 2016	4,395		—
Postretirement Benefit Plan Amounts to be Recovered through Future Rates	—		2,980
Total Regulatory Assets	$	11,165	$	10,062

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



	2015		2014
Current Portion of Regulatory Assets	$	10,772	$	719
Regulatory Assets (long term)	393		9,343
Total Regulatory Assets	$	11,165	$	10,062

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

The Company recorded regulatory liabilities of $85.4 million and $18.3 million at December 31, 2015 and 2014, respectively, related to the MISO transmission owner complaints discussed in Notes 1(c) and 7(a).

Exhibit 99.1

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



	2015		2014
Revenue True-ups, Including Interest
2013 Network Revenue Refunded in 2015	$	—	$	4,739
2013 Scheduling Revenue Refunded in 2015	—		128
2013 Multi-Value Projects Revenue Refunded in 2015	—		4,469
2014 Network Revenue to be Refunded in 2016	1,728		6,638
2014 Regional Cost-sharing Revenue to be Refunded in 2016	5,915		5,733
2015 Network Revenue to be Refunded in 2017	877		—
2015 Multi-Value Projects Revenue to be Refunded in 2017	2,876		—
2015 Regional Cost-sharing Revenue to be Refunded in 2017	2,828		—
Other Regional Cost-sharing Revenue to be Refunded in 2016	4,974		—
Return on Equity Refund Liability	85,380		18,348
Recognition of Over-funded Post Retirement Benefit Plan	5,714		—
Non-ARO Removal Costs Collected in Rates	137,940		119,047
Cumulative Difference between ARO Costs Collected in Rates and ARO
Recognition under ASC Topic 410	936		1,722
Total Regulatory Liabilities	$	249,168	$	160,824

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



	2015		2014
Current Portion of Regulatory Liabilities	$	12,617	$	14,299
Regulatory Liabilities (long term)	236,551		146,525
Total Regulatory Liabilities	$	249,168	$	160,824

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

Exhibit 99.1

(i) Other Assets

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



	2015		2014
Unamortized Debt Issuance Costs	$	9,311	$	8,993
Deferred Project Costs	551		5,155
Other	2,784		2,207
Total Other Assets	$	12,646	$	16,355

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, continue to be deferred as described above. Approximately $8.3 million, $15.5 million and $19.0 million of preliminary survey and investigation costs were included in operations and maintenance expense for 2015, 2014 and 2013, 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 or state income tax expense. See Note (6) for further discussion of income taxes.

Exhibit 99.1

(l) Construction Agreement

In December 2012, the Company entered into an agreement with the Wisconsin Department of Transportation (WisDOT) to relocate seven overhead 138 kilovolt (kV) transmission lines as part of the WisDOT’s expansion of the interchange between Interstate Highway 894-94 and U.S. Highway 45 in Milwaukee, Wisconsin, known as the Zoo Interchange. Under the agreement, the WisDOT began making the first of its periodic advances to the Company in January 2013, which the Company used to offset its costs to relocate the seven lines. The Company received approximately $12.2 million and $32.8 million in advances under the agreement during 2014 and 2013, respectively. The Company’s obligation under this agreement was completed in 2014 and no additional payments were received during 2015. The Company will not receive any additional payments from the WisDOT related to this agreement.

(m) 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.

(n) New Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update No. (ASU) 2014-09, Revenue from Contracts with Customers (ASC Topic 606). The new recognition and measurement rules introduced by ASU 2014-09 will replace nearly all existing revenue guidance, including most industry-specific guidance, and will, with a few exceptions, apply to all contracts with customers.

Under the guidance in ASU 2014-09, the selling entity is required to perform the following recognition and measurement steps in order to recognize revenue:

1) Identify the contract with a customer

2) Identify the separate performance obligations within a contract

3) Determine the transaction price


4)	Allocate the transaction price to the separate performance obligations, typically on the basis of the relative standalone selling prices of each distinct good or service


5)	Recognize revenue when, or as, each performance obligation is satisfied, either over a period of time or at a point in time.

In July 2015, FASB voted in favor of a one-year delay in the implementation of ASU 2014-09. A final ASU was issued by FASB in August 2015 making ASU 2014-09 effective for the Company for the annual reporting period ending December 31, 2019 and interim reporting periods within 2019; but the Company

Exhibit 99.1

may, at its discretion, adopt ASU 2014-09 effective for the annual reporting period ending December 31, 2018, and interim reporting periods within 2018, in order to align its accounting methods with those of its members who are public companies. The Company is currently evaluating the impacts of the new standard but does not believe it will have a material impact to its current revenue recognition and measurement practices.

In April 2015, FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs (ASC Topic 835), which changes the presentation of debt issuance costs in financial statements. Under the guidance in ASU 2015-03, the Company will present such costs in the balance sheets as a direct deduction from the related debt liability, rather than as an asset. Amortization of the costs will be reported as interest expense. ASU 2015-03 is required to be applied retrospectively to all prior periods and will become effective for the Company for the annual reporting period ending December 31, 2016, and interim periods beginning in 2017. However, the Company may, at its discretion, adopt ASU 2015-03 for interim periods beginning in 2016. ASU 2015-03 requires an entity to disclose in the first fiscal year after the entity’s adoption date, and in the interim periods within the first fiscal year, the following:

1) The nature of and reason for the change in accounting principle

2) The transition method

3) A description of the prior-period information that has been retrospectively adjusted


4)	The effect of the change on the financial statement line item (i.e. the debt issuance cost asset and the debt liability).

The Company, which intends to adopt ASU 2015-03 for interim and annual periods beginning in 2016, does not expect the adoption of ASU 2015-03 to have a material effect on its financial position, results of operations or cash flows.

In April 2015, FASB issued ASU 2015-05, Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (ASC Topic 350), which provides guidance to customers about whether a cloud computing arrangement includes a software license. Under the guidance in ASU 2015-05, if a cloud computing arrangement includes a software license, the Company would account for the software license portion of the arrangement consistent with the acquisition of other software licenses, whereas if the arrangement does not include a software license, the Company would account for the arrangement consistent with a service contract. ASU 2015-05 may be applied prospectively or retrospectively, at the Company’s discretion, with certain differences in disclosure requirements. ASU 2015-05 will become effective for the Company for the annual reporting period ending December 31, 2016, and interim periods beginning in 2017. However, the Company may, at its discretion, adopt ASU 2015-05 for interim periods beginning in 2016. The Company does not expect the adoption of ASU 2015-05 to have a material effect on its financial position, results of operations or cash flows.

Exhibit 99.1

(2) Benefits

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



	2015	2014	2013
Discount Rate	4.57%	4.12%	4.95%
Medical Cost Trend:
Immediate Range	6.10%	6.60%	7.50%
Ultimate Range	4.50%	4.00%	4.00%
Long-term Rate of Return on Plan Assets	5.00%	5.00%	6.00%

The components of Management Inc.’s postretirement healthcare benefit costs for 2015, 2014 and 2013 are as follows (in thousands):



	2015			2014			2013
Service Cost	$	1,447		$	1,111		$	1,426
Interest Cost	1,173			1,049			960
Amortization of Prior Service Credit	(569		)	(569		)	(569		)
Amortization of Net Actuarial Loss (Gain)	276			(11		)	308
Expected Return on Plan Assets	(1,291		)	(1,200		)	(1,375		)
Net Periodic Postretirement Cost	$	1,036		$	380		$	750

To recognize the funded status of its postretirement healthcare benefit plans in accordance with ASC Topic 715, Management Inc. recorded a long-term asset of $5.7 million at December 31, 2015, and a long-term liability of $3.0 million at December 31, 2014. In addition, the Company had the following amounts not yet reflected in net periodic benefit cost and included in its regulatory accounts, which the Company believes will be refunded or recovered as a component of operating expense in future rates, at December 31 (in thousands):



	2015			2014
Prior Service Credit	$	(8,941	)	$	(3,016	)
Accumulated Loss	3,227			5,996
Regulatory Asset (Liability) for Amounts to be Included in Future Rates	$	(5,714	)	$	2,980

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-

Exhibit 99.1

percent change in the medical cost trend rates, holding all other assumptions constant, would have the following effects for 2015 (in thousands):



	One-Percent		One-Percent
	Increase		Decrease
Effect on Total of Service and Interest Cost Components	$	227	$	(165	)
Effect on Postretirement Benefit Obligation at the End of the Year	4,222		(3,221		)

In 2016, the Company will recognize a $1.3 million prior service credit in its net periodic postretirement healthcare benefit cost.

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



	2015			2014
Change in Projected Benefit Obligation:
Accumulated Postretirement Benefit Obligation at January 1	$	28,695		$	21,356
Amendments	(6,493		)	—
Service Cost	1,447			1,111
Interest Cost	1,173			1,049
Benefits Paid	(597		)	(276		)
Actuarial Losses (Gains)	(4,430		)	5,455
Benefit Obligation at December 31	$	19,795		$	28,695

Change in Plan Assets:
Fair Value of Plan Assets at January 1	$	25,715		$	25,355
Employer Contributions	973			290
Actual Return (Loss) on Plan Assets (Net of Expenses)	(905		)	306
Net Benefits Paid	(274		)	(236		)
Fair Value at December 31	$	25,509		$	25,715

Funded Status at December 31	$	5,714		$	(2,980	)

The benefit obligation at December 31, 2015, decreased due to plan amendments that reduced the Company’s expected future costs and changes in the assumptions used to calculate the benefit obligation. These changes in assumptions include the use of a higher discount rate, a lower medical cost trend rate as shown in the weighted average assumptions table above and updated mortality assumptions based on mortality tables issued by the Society of Actuaries.

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

2016.

Exhibit 99.1

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



2016	$	492
2017	546
2018	589
2019	588
2020	580
2021-2025	3,909
Total	$	6,704

To fund postretirement healthcare benefit obligations, the Company periodically contributes to its Voluntary Employees’ Beneficiary Association (VEBA) trust. The VEBA trust, along with the 401(h) trust previously established by the Company to fund postretirement healthcare benefits, 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.

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:



	2015	2014	Target	Range
U.S. Equities	34.1%	38.3%	32.5%	+/-5%
Non-U.S. Equities	32.3%	28.2%	32.5%	+/-5%
Fixed Income	33.6%	33.5%	35.0%	+/-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. In late 2014, the Company updated the targeted allocation percentages for the plan assets. As of December 31, 2014, the trustee was in the process of updating the portfolio to reflect these new targets.

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.

Exhibit 99.1


•	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 1 Inputs 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 2 Observable market-based inputs or unobservable inputs that are corroborated by market data.

Inputs to the valuation methodology include:

• Quoted prices for similar assets in active markets

• Quoted prices for identical or similar assets in inactive markets

• Inputs other than quoted prices that are observable for the asset


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

Level 3 Inputs to the valuation methodology that are unobservable and not corroborated by market data.

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.

There have been no changes to the methodologies used at December 31, 2015 and 2014. The following are descriptions of the valuation methodologies used for investments measured at fair value:


•	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.

Exhibit 99.1

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):



2015	Level 1		Level 2		Level 3		Total
U.S. Equity Mutual Funds	$	8,703	$	—	$	—	$	8,703
Non-U.S. Equity Mutual Fund	8,245		—		—		8,245
Fixed Income Mutual Funds	8,329		—		—		8,329
Money Market Fund	—		232		—		232
Total	$	25,277	$	232	$	—	$	25,509



2014	Level 1		Level 2		Level 3		Total
U.S. Equity Mutual Funds	$	9,848	$	—	$	—	$	9,848
Non-U.S. Equity Mutual Fund	7,243		—		—		7,243
Fixed Income Mutual Funds	8,376		—		—		8,376
Money Market Fund	—		248		—		248
Total	$	25,467	$	248	$	—	$	25,715

During 2015 and 2014, 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.

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 $3.5 million, $3.3 million and $3.1 million in 2015, 2014 and 2013, respectively.

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. As of December 31, 2015 and 2014, $18.1 million and $17.7 million, respectively, were included in other long-term liabilities related to this deferred compensation plan. Deferred amounts are taxable to the employee when paid, but the Company recognizes compensation expense in the period earned. Amounts charged to expense, including interest accruals, were $1.4 million, $2.0 million and $2.1 million in 2015, 2014 and 2013, respectively.

(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 percent of annual earnings before members’ income taxes.

Exhibit 99.1

During 2015, 2014 and 2013, the Company distributed $175 million, $204 million and $195 million, respectively, of its earnings to its members. On January 27, 2016, the board of directors of Management Inc. approved a distribution for the fourth quarter of 2015, in the amount of $22.8 million, that was paid on January 29, 2016, bringing the total distributions related to 2015 earnings to 80 percent 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 2015, the Company issued 1,152,328 units to members in exchange for $20.0 million in cash. During

2014 and 2013 the Company issued members 2,974,510 units for $50.0 million in cash and 2,459,468 units for

$40.0 million in cash, respectively.

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.

(4) Debt

(a) Credit Facility

The Company’s $350 million, five-year revolving credit facility, which had a termination date of December 7, 2017, was amended and restated on June 12, 2015. The amended credit facility is $400 million and has a five-year term which expires on June 12, 2020. The facility provides backup liquidity to the Company’s commercial paper program. The Company has not borrowed under the revolving credit facility. However, 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 percent.

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 percent at any given time. The Company was not in violation of any financial covenants under its credit facility during the periods included in these financial statements.

The Company had no outstanding balance under its credit facility as of December 31, 2015 or 2014.

Exhibit 99.1

(b) Commercial Paper

The Company currently has a $400 million unsecured, private placement, commercial paper program. 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 $226 million of commercial paper outstanding as of December 31, 2015 at an average rate of 0.40 percent and $120 million of commercial paper outstanding as of December 31, 2014 at an average rate of 0.23 percent. Commercial paper is included in short-term debt in the balance sheets. As defined by the commercial paper program, no customary events of default took place during the periods covered by the accompanying financial statements.

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



	2015		2014
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%, matured and paid April 15, 2015	—		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		150,000
Senior Notes at stated rate of 3.74%, due January 22, 2029	50,000		50,000
Senior Notes at stated rate of 4.67%, due January 22, 2044	50,000		50,000
Senior Notes at stated rate of 3.35%, due December 11, 2024	75,000		75,000
Senior Notes at stated rate of 3.60%, due December 11, 2029	29,000		29,000
Senior Notes at stated rate of 4.31%, due December 11, 2044	47,000		47,000
Senior Notes at stated rate of 3.45%, due April 14, 2025	50,000		—
Senior Notes at stated rate of 3.70%, due April 14, 2030	21,000		—
Senior Notes at stated rate of 4.41%, due April 14, 2045	28,000		—
Other Long-term Notes Payable	29		—
Total Long-term Debt	$	1,800,029	$	1,801,000
Less: Current Maturities	—		(100,000		)
Net Long-term Debt	$	1,800,029	$	1,701,000

Exhibit 99.1

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.

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



2016	$	—
2017	—
2018	200
2019	150
202	—
Thereafter	1,450
	$	1,800

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 percent 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 November 2014, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $250 million of senior notes to be funded in two tranches. Closing of the notes and funding of the first $151 million took place on December 11, 2014 with interest due semiannually on June 11 and December 11, beginning on June 11, 2015. The $151 million is comprised of $75 million of 10-year, unsecured 3.35 percent senior notes; $29 million of 15-year, unsecured 3.60 percent senior notes; and $47 million of 30-year, unsecured 4.31 percent senior notes. The notes will mature on December 11, 2024, 2029 and 2044, respectively.

Funding of the remaining $99 million took place on April 14, 2015 and is comprised of $50 million of 10-year, unsecured 3.45 percent senior notes; $21 million of 15-year, unsecured 3.70 percent senior notes; and $28 million of 30-year, unsecured 4.41 percent senior notes. Interest is due semiannually on April 14 and October 14, beginning on October 14, 2015, and the notes will mature on April 14, 2025, 2030 and 2045, respectively. The Company used the proceeds of these notes to repay $100 million of long-term debt that matured on April 15, 2015.

During November 2013, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $50 million of 15-year, unsecured 3.74 percent senior notes and $50 million of 30-year, unsecured 4.67 percent senior notes. The closing and funding of the notes occurred on January 22, 2014. The notes pay interest semiannually on January 22 and July 22, beginning on July 22, 2014. The notes will mature on January 22, 2029 and January 22, 2044, respectively.

Exhibit 99.1

(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 issuances or upon the quoted market prices of U.S. Treasury issues having a similar term to maturity, adjusted for the Company’s credit ratings.

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



	2015		2014
Carrying Amount	$	1,800	$	1,801

Estimated Fair Value	2,030		2,152

(6) Income Taxes

The Company is allowed to recover in rates, as a component of its cost of service, 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 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 $614 million, $568 million and $498 million in 2015, 2014 and 2013, respectively, and are primarily related to accelerated tax depreciation and other plant-related differences. The 2015, 2014 and 2013 revenues include recovery of $107 million, $103 million and $98.9 million, respectively, of income tax expense.

On January 2, 2013, President Obama signed the American Taxpayer Relief Act of 2012 (“2012 Tax Act”), which extended the 50 percent bonus depreciation through 2013. The 2012 Tax Act also allowed a transitional 50 percent bonus depreciation for self-constructed assets that had started construction before December 31, 2013, and were in service by December 31, 2014. On December 19, 2014, the Tax Increase Prevention Act of 2014 (“2014 Tax Act”) was signed in to law extending the 50 percent bonus depreciation through 2014. The 2014 Tax Act allowed a transitional 50 percent bonus depreciation for self-constructed assets that had started construction before December 31, 2014, and are placed in service by December 31, 2015. On December 18, 2015, the Protecting Americans from Tax Hikes Act of 2015 (“2015 Tax Act”) was passed by Congress extending the 50 percent bonus depreciation through 2017 and allowing bonus depreciation on qualified assets of 40 percent in 2018 and 30 percent in 2019. The 2015 Tax Act allows for a transitional 30 percent bonus depreciation for self- constructed assets that start construction before December 31, 2019, and are placed in service by December 31, 2020.

ASC Topic 740, “Income Taxes,” 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

Exhibit 99.1

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 material amounts of interest or penalties during 2015, 2014 or 2013. The Company is no longer subject to examination by the Internal Revenue Service for tax years prior to 2013 or any state jurisdiction for tax years prior to 2011. 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.

(7) Commitments and Contingencies

(a) MISO Return on Equity Complaints

As mentioned above, on November 12, 2013, MISO, the Company and numerous other MISO transmission owners were named as respondents in a complaint filed at FERC pursuant to Section 206 by several customer groups located within the MISO service area. These complainants claimed that the following aspects of the respondents’ transmission rates were no longer just and reasonable: the base 12.38 percent ROE in MISO and the Company’s 12.2 percent ROE; hypothetical capital structures that have an equity component greater than 50 percent; and certain incentive ROE adders used by a limited number of MISO transmission owners, of which the Company is not one. The Company currently uses a hypothetical 50 percent debt, 50 percent equity capital structure, as approved by FERC, in calculating its revenue requirement. The complainants requested FERC to order the base MISO ROE reset to 9.15 percent, equity components of hypothetical capital structures be restricted to 50 percent and that relevant incentive ROE adders be discontinued. The complainants requested that FERC establish expedited hearing and settlement procedures to address the issues raised, and that FERC grant the effective date of any refund as the date of the complainants filing. During the first quarter of 2014, the Company and the other MISO transmission owners responded to the complaint with a motion to dismiss and answer objecting to the claims of the complainants, and filed an answer in response to pleadings of the complainants and certain other parties.

On October 16, 2014, FERC issued an order which:


•	denied the portion of the complaint seeking to restrict the use of capital structures that include more than 50 percent common equity;

•

addressed the base ROE of the MISO transmission owners and the Company, determining that the complaint regarding the transmission owner base ROE raises issues of material fact that cannot be resolved with the information in the record at this point. As a result, FERC put the matter of whether the MISO transmission owner base ROE is unjust and unreasonable to hearing and settlement procedures, and established a refund period for the complaint of November 12, 2013 to February 11, 2015. The settlement process, however, was terminated in December 2014 and FERC ordered formal hearing proceedings to begin in January 2015;


•	denied the portion of the complaint requesting the termination of the incentive ROE adders used by certain transmission owners other than the Company;

Exhibit 99.1

•

indicated that it expects the parties’ evidence and discounted cash flow (DCF) analysis to be guided by its June 19, 2014, order regarding the Section 206 complaint against ISO New England (ISO-NE) transmission owners, which set the precedent for using a two-step DCF analysis for establishing ROEs for electric transmission. This new method is similar to that used for natural gas pipelines, and incorporates a two-step process utilizing both short- and long-term growth projections to establish an ROE. FERC previously used only short-term growth projections.

FERC also issued an order on October 16, 2014, addressing the ISO-NE transmission owner ROE complaint, confirming that the U.S. gross domestic product growth rate is the appropriate long-term growth rate to use in the two-step DCF methodology.

On April 6, 2015, the Company and the other transmission owners named in the complaint filed testimony with FERC in response to the complainants’ February 23, 2015 testimony, which supported a reduced ROE, as discussed above. The April 6, 2015, testimony analyzes and critiques the evidence filed by the complainants and offers evidence, which follows FERC precedent for establishing ROEs for electric transmission, supporting a higher ROE than requested by the complainants. On May 15, 2015, FERC trial staff filed its testimony in response to the testimonies previously filed by both parties. In August 2015 the transmission owners and other parties involved in the proceeding participated in a hearing at FERC and filed briefs on September 21, 2015.

The ALJ issued an initial decision on the complaint on December 22, 2015, with a base ROE recommendation of 10.32 percent. FERC is expected to rule on this proceeding by October 2016 and is not bound by the ALJ decision and could set the ROE higher or lower than the ALJ recommendation.

In a related matter, on February 12, 2015, a group of public power entities filed a second Section 206 complaint against the base ROE of the Company and other MISO transmission owners, claiming that they are no longer just and reasonable. The complainants proposed an ROE of 8.67 percent, which they claimed was derived using FERC’s new DCF methodology for establishing electric transmission base ROEs. The Company and the other transmission owners named in the complaint filed an answer with FERC on March 11, 2015, requesting that FERC deny the complaint. On June 18, 2015, FERC found that the complaint raises issues of material fact that cannot be resolved based upon the record. FERC set the matter for hearing procedures and set a refund effective date of February 12, 2015. On July 10, 2015, the ALJ set the schedule for the hearing procedures, which will conclude with the initial decision from the ALJ due June 30, 2016. On September 2, 2015, the complainants and intervenors filed testimony. The Company and the other transmission owners named in the complaint filed testimony on October 20, 2015, and FERC trial staff filed its testimony on November 23, 2015. The Company and the other respondents in the complaint filed cross-answering testimony on December 30, 2015. During January 2016, the complainants and intervenors supporting the complainants filed rebuttal testimony and the parties involved in the proceeding provided updates of ROE studies used in prior testimony. The hearing is scheduled to commence February 16, 2016.

As a result of the second complaint, it is possible that FERC will order an ROE that is different than the ultimate outcome of the first complaint. In that event, it is expected that the ROE decision from the second complaint would supersede the ROE decision in the first complaint. Therefore, the new ROE would be applied to the February 12, 2015 to May 11, 2016, refund period for the second complaint and from the date of the order going forward.

Exhibit 99.1

The Company believes it is probable that a refund will be required upon ultimate resolution of this matter and has recorded regulatory liabilities, inclusive of interest, of $85.4 million and $18.3 million as of December 31, 2015 and 2014, respectively. The Company also recorded $63.8 million and $18.3 million as reductions to transmission service revenue in the statements of operations at December 31, 2015 and 2014, respectively, related to this liability. The Company is unable to make a better estimate of probable losses or estimate the range of reasonably possible losses in excess of the amount recorded. FERC’s ultimate decision could have a material impact to the Company’s financial position, results of operations and cash flows.

In a separate, but related matter, on November 6, 2014, a large group of transmission-owning members of MISO, including the Company, asked FERC to approve a 50 basis-point incentive ROE adder for participating in MISO and voluntarily relinquishing functional control of their transmission facilities to the Regional Transmission Organization. On January 5, 2015, FERC accepted the proposal of the Company and the other transmission owners. FERC approved the adder subject to it being applied to a base ROE shown to be just and reasonable based on an updated DCF analysis resulting from the first ROE complaint proceeding, and subject to the resulting ROE being within the zone of reasonableness determined in the first ROE complaint proceeding. The adder became effective January 6, 2015, subject to refund, and FERC accepted the transmission owners’ request to defer collection of the adder pending the outcome of the first complaint proceeding.

(b) Operating Leases

The Company leases both office and data center space and certain transmission-related equipment under non-cancelable operating leases. Amounts incurred were approximately $6.5 million annually during 2015, 2014 and 2013.

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



2016	$	6.5
2017	6.4
2018	6.4
2019	5.8
2020	5.8
Thereafter	34.0
	$	64.9

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 percent of the cost of the related projects. The grants, totaling $12.7 million, were used to invest in smart grid technologies incorporated into the Company’s transmission system. The funds the Company received from the DOE under the grant award agreements reduced the

Exhibit 99.1

amount of investment in such projects upon which the Company earns a return. During construction, which was completed in October 2013, the Company invoiced the DOE and received payments under these agreements. Per the terms of these agreements, the Company completed independent audits of the smart grid projects during 2012, 2013 and 2014, the results of which were submitted to the DOE. The reports were concluded with no audit findings and, per the Smart Grid agreements, the Company has no further audit requirements related to these projects.

(d) 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.

(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 related to utility activities 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 $125 million of additional capital through voluntary additional capital calls (VACCs) during 2016, including $15 million it received in January 2016. The Company received a total of $20 million, $50 million and $40 million through VACCs in 2015, 2014 and 2013, respectively. The increase in the VACC for 2016 is primarily due to higher expected capital spending than the previous years. The participating members receive additional membership units at the current book value per unit at the time of each contribution. Contributions from capital calls are recognized when received.

Exhibit 99.1

(b) Corporate Restructuring

During 2016, ATC Management Inc. plans to undertake a corporate restructuring whereby certain owners will exchange their interests in the Company for interests in a new holding company, ATC Holdco LLC (“Holdco”). Under this holding company structure, Holdco will own all investments outside of the Company’s traditional footprint, as well as interests in the Company matching the current aggregate ownership interests of the exchanging Company members. Those owners of the Company who wish to participate in investments outside of the traditional footprint are able to do so through Holdco, while those owners interested only in investing in the traditional footprint will continue to own the Company directly. The corporate restructuring, through the creation of a holding company, formally separates the Company’s development activities, including its interest in DATC, discussed in Note 8(c), from its traditional footprint activities. The Company currently has applications for approval of the corporate restructuring pending before FERC, the PSCW, and the Illinois Commerce Commission. The restructuring is contingent upon approvals of these applications which are anticipated to occur between February and November of 2016.

The Company and Duke Energy hold equal equity ownership in the Duke-American Transmission Company LLC (DATC), which was created to seek opportunities to acquire, build, own and operate new transmission projects that meet potential customers’ capacity and voltage requirements and future needs. DATC continues to evaluate new projects and opportunities, and participates in the competitive bidding process on projects it considers to be viable.

DATC owns the Zephyr Power Transmission Project (“Zephyr”) and is continuing the design and development of the proposed transmission line, which 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”). The 500 kV high-voltage direct-current transmission line, which will be between 500 miles and 850 miles long, has an estimated cost of $2.5 billion to $3.5 billion. 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. 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 for a period of time to be specified during 2016 by the parties to the agreement; however, DATC has the right to terminate the project between December 15, 2016 and January 15, 2017. DATC has received FERC approval to charge negotiated rates consistent with FERC approvals for Zephyr’s previous owners.

Path 15 is an existing 84-mile, 500 kV transmission line in central California. DATC owns 72 percent of the transmission rights of Path 15, which it purchased from Atlantic Power Corporation in April 2013 for approximately $56 million cash and the assumption of approximately $137 million of debt. Pacific Gas & Electric has an 18 percent interest in the transmission rights to Path 15 through its ownership and operation of the connecting Los Banos and Gates substations. The remaining 10 percent interest in the transmission rights to Path 15 is owned by the Western Area Power Administration, which operates and maintains the line. On February 18, 2014, Path 15 filed its rate case with FERC. On May 29, 2015, FERC approved a negotiated settlement for an annual revenue requirement of $25.9 million for the rate period of 2014 through 2016. Path 15 expects to file its next rate case in February 2017 utilizing 2016 as the test year.

Exhibit 99.1

On July 18, 2013, DATC secured a $30 million, five-year credit facility from U.S. Bank N.A. As a stipulation of that facility, the Company and Duke Energy executed a guarantee agreement on that same date with U.S. Bank N.A. to each guarantee 50 percent of the obligations under the credit facility agreement. Currently, there is no outstanding balance under the credit facility.

The balance in the Company’s investment in DATC was $37.1 million and $35.3 million at December 31,

2015 and 2014, respectively, and is accounted for under the equity method of accounting.

(d) Operations and Maintenance, Project Services and Common Facilities Agreements

The Company operates under Operation and Maintenance Agreements whereby certain contributing utilities, municipalities and cooperatives provide operational, maintenance and construction services to the Company at a fully-allocated cost.

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 orders that have been approved by the PSCW. To prevent cross-subsidization between affiliated entities, the PSCW ordered that services be performed at a fully-allocated cost of the party providing services, and reported annually to the PSCW.

Some operation and maintenance agreements require the Company to utilize a minimum level of service. The amount of services utilized by the Company has exceeded the minimum in each year.

Under these agreements, the Company was billed approximately $38.0 million, $32.8 million and $35.5 million in 2015, 2014 and 2013, respectively. Accounts payable and other accrued liabilities include amounts payable to these companies of $3.1 million and $2.4 million at December 31, 2015 and 2014, respectively.

(e) Transmission Service

Revenues from the Company’s members were approximately 90 percent of the Company’s transmission service revenue for the years ended December 31, 2015, 2014 and 2013.

(f) Management Inc.

As discussed in Note 1(b), Management Inc. manages the Company. Management Inc. charged the Company approximately $106 million, $101 million and $96.6 million in 2015, 2014 and 2013, 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.

Exhibit 99.1

(9) Quarterly Financial Information (unaudited)



	Three Months Ended

	2015
	March 31		June 30			September 30		December 31			Total

Operating Revenues	$	152,357	$	165,171		$	164,515	$	133,793		$	615,836
Operating Expenses	79,951		80,326			78,059		80,985			319,321
Operating Income	72,406		84,845			86,456		52,808			296,515

Operating Income (Expense, Net)	62		(81		)	585		610			1,176
Interest Expense, Net	24,483		24,172			23,655		24,940			97,250

Earnings Before Members' Income Taxes	$	47,985	$	60,592		$	63,386	$	28,478		$	200,441


	2014
	March 31		June 30			September 30		December 31			Total

Operating Revenues	$	163,337	$	159,990		$	163,643	$	148,063		$	635,033
Operating Expenses	78,623		74,405			76,561		77,862			307,451
Operating Income	84,714		85,585			87,082		70,201			327,582

Operating Income (Expense, Net)	388		322			693		(1,286		)	117
Interest Expense, Net	21,996		22,242			22,204		22,528			88,970

Earnings Before Members' Income Taxes	$	63,106	$	63,665		$	65,571	$	46,387		$	238,729

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. All of 2015 and the fourth quarter of 2014 decreased as a result of the revenue refund liability recorded as a result of the MISO transmission owner base ROE complaints, discussed in Note 7(a).

Exhibit 99.1

American Transmission Company LLC

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

The management of ATC Management Inc. (“Management Inc.”), corporate manager of American Transmission Company LLC (the “Company”), believes the following discussion provides information that is relevant to an assessment and understanding of the Company’s results of operations and financial condition. This discussion should be read in conjunction with the financial statements and notes to those statements.

The Company and Management Inc. have common ownership and operate as a single functional unit. All employees who serve the Company are employees of Management Inc. The Company pays the expenses of Management Inc. 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.

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 currently owns and operates the electric transmission system in parts of Wisconsin, Illinois, Minnesota and the Upper Peninsula of Michigan. Since it was established, the Company has invested and placed into service $3.8 billion in transmission projects within its service area. Management believes that it is necessary to continue to strengthen and expand the Company’s transmission system to deliver electricity to its current customer base. Further expansion of the Company’s transmission system will relieve constraints, allow additional generation capacity to be connected to the system, enhance wholesale competition and permit entry by new competitors in electricity generation. While the Company’s initial focus was to expand import capability and improve the reliability of the transmission infrastructure, the Company continues to seek partnerships and review opportunities to build new transmission beyond its current service area.

The Company is a transmission-owning member of the Midcontinent Independent System Operator, Inc. (MISO) and is required to seek MISO’s direction for certain operational actions it plans to perform within its system. The Company is also required to coordinate planning activities for new projects or system upgrades with MISO, and certain projects may require review and approval by MISO before implementation. MISO has operational control over the Company’s system and directs the manner in which the Company performs operations. MISO also monitors and controls congestion, approves transmission maintenance outages and negotiates with generators on the timing of generator maintenance outages.

Under the authority of the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (“MISO Tariff”), which is regulated by the Federal Energy Regulatory Commission (FERC), the Company provides wholesale electric transmission service to eligible entities within its service area. The MISO Tariff specifies the general terms and conditions of service on the Company’s transmission system and establishes the rates and amounts to be paid for those services. The Company does not take ownership of the electricity that it transmits.

The Company’s revenue requirement is designed to reimburse it for all reasonable operating expenses, as well as to provide a return on assets employed in the provision of transmission services. In accordance with FERC policy, the Company’s revenue requirement also includes an estimate of income taxes payable by the Company’s taxable members on the equity portion of the return on rate base. The Company’s rate base consists of the original cost of assets in service,

Exhibit 99.1

reduced by accumulated depreciation and deferred income taxes associated with those assets, in addition to other components authorized by the MISO Tariff. The weighted-average cost of capital, or return rate, applied to rate base is intended to cover the cost of debt financing and provide equity holders a reasonable return on their investment. Since 2001, the Company’s allowed after-tax rate of return on common equity has been 12.2 percent.

The Company’s FERC-approved formula rate tariff (“Company’s Tariff”) allows the Company to use a hypothetical 50 percent debt, 50 percent equity capital structure and calculate and collect its revenue requirement on a forecasted basis, subject to true-up. Additionally, the Company’s Tariff allows the Company to include construction work in progress for new transmission in rate base, and expense preliminary survey and investigation (PSI) costs for new transmission in the current year. 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, and projected revenues to be received from MISO. From this forecast, the Company computes an annual projected total revenue requirement for the rate year. 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 twelve 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 the requirements of an alternative revenue program as defined in the Financial Accounting Standards Board’s Financial Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” the Company accrues or defers revenues that are higher or lower, respectively, than the amounts collected during the rate year. In accordance with ASC Topic 980, the Company classifies an accumulated over-collected true-up balance as a regulatory liability and an accumulated under-collected true-up balance as a regulatory asset in 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. During 2015, the Company refunded to network customers, through their monthly bills, $9.9 million, inclusive of interest. The Company also has FERC-approved true-up provisions for MISO regional cost-sharing revenues to refund over collections or receive under collections in the second year subsequent to the rate year. During 2015, the Company refunded, inclusive of interest, a net amount of $3.9 million to regional customers related to prior years under these true-up provisions.

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

Exhibit 99.1

Pending Regulatory Matters

MISO Return on Equity Complaints

On November 12, 2013, MISO, the Company and numerous other MISO transmission owners were named as respondents in a complaint filed at FERC pursuant to Section 206 of the Federal Power Act (“Section 206”) by several customer groups located within the MISO service area. These complainants claimed that the following aspects of the respondents’ transmission rates were no longer just and reasonable: the base 12.38 percent return on equity (ROE) in MISO and the Company’s 12.2 percent ROE; hypothetical capital structures that have an equity component greater than 50 percent; and certain incentive ROE adders used by a limited number of MISO transmission owners, of which the Company is not one. The Company currently uses a hypothetical 50 percent debt, 50 percent equity capital structure, as approved by FERC, in calculating its revenue requirement. The complainants requested FERC to order the base MISO ROE reset to 9.15 percent, equity components of hypothetical capital structures be restricted to 50 percent and that relevant incentive ROE adders be discontinued. The complainants requested that FERC establish expedited hearing and settlement procedures to address the issues raised, and that FERC grant the effective date of any refund as the date of the complainants filing. During the first quarter of 2014, the Company and the other MISO transmission owners responded to the complaint with a motion to dismiss and answer objecting to the claims of the complainants, and filed an answer in response to pleadings of the complainants and certain other parties.

On October 16, 2014, FERC issued an order which:


•	denied the portion of the complaint seeking to restrict the use of capital structures that include more than 50 percent common equity;

•

addressed the base ROE of the MISO transmission owners and the Company, determining that the complaint regarding the transmission owner base ROE raises issues of material fact that cannot be resolved with the information in the record at this point. As a result, FERC put the matter of whether the MISO transmission owner base ROE is unjust and unreasonable to hearing and settlement procedures, and established a refund period of November 12, 2013 to February 11, 2015. The settlement process, however, was terminated in December 2014. FERC ordered formal hearing proceedings to begin in January 2015;


•	denied the portion of the complaint requesting the termination of the incentive ROE adders used by certain transmission owners other than the Company;

•

indicated that it expects the parties’ evidence and discounted cash flow (DCF) analysis to be guided by FERC’s June 19, 2014, order regarding the Section 206 complaint against ISO New England (ISO-NE) transmission owners, which set the precedent for using a two-step DCF analysis for establishing ROEs for electric transmission. This new method is similar to that used for natural gas pipelines, and incorporates a two-step process utilizing both short-term and long-term growth projections to establish an ROE. FERC previously used only short-term growth projections.

FERC also issued an order on October 16, 2014, in the ISO-NE transmission owner ROE complaint, confirming that the U.S. gross domestic product growth rate is the appropriate long-term growth rate to use in the two-step DCF methodology.

Exhibit 99.1

On April 6, 2015, the Company and the other transmission owners named in the complaint filed testimony with FERC in response to the complainants’ February 23, 2015 testimony, which supported a reduced ROE as discussed above. On May 15, 2015, FERC trial staff filed its testimony in response to the testimonies previously filed by both parties. In August 2015 the transmission owners and other parties involved in the proceeding participated in a hearing at FERC and filed briefs on September 21, 2015.

The administrative law judge (ALJ) issued an initial decision on the complaint on December 22, 2015, with a base ROE recommendation of 10.32 percent. FERC is expected to rule on this proceeding by October 2016 and is not bound by the ALJ decision and could set the ROE higher or lower than the ALJ recommendation.

In a related matter, on February 12, 2015, a group of public power entities filed a second Section 206 complaint against the base ROE of the Company and other MISO transmission owners, claiming that they are no longer just and reasonable. The complainants proposed an ROE of 8.67 percent, which they claimed was derived using FERC’s new DCF methodology for establishing electric transmission base ROEs. The Company and the other transmission owners named in the complaint filed an answer with FERC on March 11, 2015, requesting that FERC deny the complaint. On June 18, 2015, FERC found that the complaint raises issues of material fact that cannot be resolved based upon the record. FERC set the matter for hearing procedures and set a refund effective date of February 12, 2015. On July 10, 2015, the ALJ set the schedule for the hearing procedures, which will conclude with the initial decision from the ALJ due June 30, 2016. On September 2, 2015, the complainants and intervenors filed testimony. The Company and the other transmission owners named in the complaint filed testimony on October 20, 2015, and FERC trial staff filed its testimony on November 23, 2015. The Company and the other respondents in the complaint filed cross-answering testimony on December 30, 2015. During January 2016, the complainants and intervenors supporting the complainants filed rebuttal testimony and the parties involved in the proceeding provided updates of ROE studies used in prior testimony. The hearing is scheduled to commence February 16, 2016.

Exhibit 99.1

ROE being within the zone of reasonableness determined in the first ROE complaint proceeding. The adder became effective January 6, 2015, subject to refund, and FERC accepted the transmission owners’ request to defer collection of the adder pending the outcome of the first complaint proceeding.

FERC Order No. 1000

With respect to transmission planning, FERC Order No. 1000 (“Order 1000”) requires that public utility transmission providers, such as MISO, participate in a regional transmission planning process which produces a single regional transmission plan, and that adjoining transmission planning regions must coordinate their efforts with respect to efficient and cost-effective transmission solutions. In addition, each transmission provider must amend its tariff to include procedures for considering transmission needs driven by public policy requirements, which include duly enacted laws or regulations passed by a local governmental entity, and to consider transmission needs driven by federal or state laws or regulations. Order 1000 also calls for the removal of federal rights of first refusal from FERC-approved tariffs and agreements, subject to certain limitations. The Company cannot predict with certainty the impact of Order 1000; however, the Company believes that the transmission planning requirements, combined with the removal of the federal rights of first refusal will, in most instances, assist the Company in expansion outside of its original service area and in seeking opportunities to develop, construct, own and operate transmission facilities throughout North America, including through the activities of Duke-American Transmission Company LLC (DATC). Further details related to DATC are outlined in the Capital Resources and Requirements section below.

Results of Operations

Revenues

The Company’s operating revenues for 2015, 2014, and 2013, which include reductions in both 2015 and 2014 for the revenue refund liability related to the MISO transmission owner base ROE complaints, discussed above in Pending Regulatory Matters, are outlined in the following table:



(In Thousands)							2015 vs. 2014					2014 vs. 2013
							Increase			Percentage		Increase			Percentage
	2015		2014		2013		(Decrease)			Change		(Decrease)			Change

Network Service Revenue	$	500,653	$	516,335	$	514,462	$	(15,682	)	(3.0	)%	$	1,873		0.4	%
Regional Cost-Sharing Revenue	82,718		82,681		84,168		37			0.0	%	(1,487		)	(1.8	)%
Multi-Value Projects Revenue	6,586		9,438		4,976		(2,852		)	(30.2	)%	4,462			89.7	%
Point-to-Point Revenue	8,168		9,063		9,572		(895		)	(9.9	)%	(509		)	(5.3	)%
Other Transmission Service Revenue	16,152		16,033		11,744		119			0.7	%	4,289			36.5	%
Transmission Service Revenue	614,277		633,550		624,922		(19,273		)	(3.0	)%	8,628			1.4	%
Other Operating Revenue	1,559		1,483		1,414		76			5.1	%	69			4.9	%
Total Operating Revenues	$	615,836	$	635,033	$	626,336	$	(19,197	)	(3.0	)%	$	8,697		1.4	%

Exhibit 99.1

The revenue requirement for each year represents the total amount that the Company is entitled to collect from all revenue sources, which include the following:

Network Service Revenue consists of charges paid by the Company’s network customers to reserve transmission capacity on the Company’s system. The annual network revenue requirement is divided among all of the Company’s network customers based on their historic usage of the system, known as load-ratio share. The charges for an individual customer are billed in even monthly installments during the year and are not dependent upon actual usage. Thus, the Company’s network service billings during a given year will not vary once the revenue requirement and rates are determined for each year. In the event new network customers join the Company’s network during the year, the load-ratio share and monthly charges of each customer are adjusted prospectively. Although network service is provided under the MISO Tariff, the Company bills and collects its own network service revenue, subject to true-up as discussed above in the Executive Overview, under a billing agreement with MISO.

Regional Cost-Sharing Revenue is related to projects that meet the criteria for cost-sharing under MISO’s Regional Expansion Criteria and Benefits (RECB) plan. Revenue related to RECB projects is calculated according to the appropriate MISO methodology and excluded from the Company’s network service billings. Instead, such revenues are billed, on behalf of the Company, by MISO across its footprint according to its FERC-approved cost allocation methodology. Regional cost-sharing revenues are also trued up on an annual basis.

Multi-Value Projects (MVP) Revenue is related to projects that meet the criteria for MVP cost-sharing under MISO’s Tariff. Upon meeting certain criteria, these projects are eligible to have 100 percent of their costs allocated regionally. MVPs are designed to support energy policy mandates, provide multiple economic benefits, or provide a combination of reliability and economic benefits, and revenue related to such projects is calculated according to the appropriate MISO methodology. Similar to regional cost-sharing revenues, MISO bills these amounts on behalf of the Company, across the MISO footprint according to its FERC-approved cost allocation methodology. As a result, the Company excludes these amounts from its network service billings. Like network and RECB revenues, MVP revenues are trued up on an annual basis.

Point-to-Point Revenue relates to charges for delivering energy from specific points on the transmission system to other specific points on the transmission system. All point-to-point transactions are administered and billed by MISO; the Company receives a portion of the revenue from each transaction based on the MISO revenue allocation methodology. The point-to-point service revenue that the Company will realize each year depends on the length, duration and other terms of the firm contracts MISO has for point-to-point service and the volume of electricity transmitted as non-firm service. Variations in point-to-point service revenues do not affect the Company’s results of operations, however, because, under the true-up mechanism described above, any over- collection or under-collection as measured against the Company’s point-to-point service revenue projected in the current revenue requirement would be a component of any true-up adjustment recorded for network service revenue.

Other Transmission Service Revenue consists of control area service revenue, such as scheduling, system control and dispatch services.

Other Operating Revenue is derived from other transmission-related services provided to third parties that are not provided under regulated tariffs and rental of certain transmission and administrative property and equipment by third parties.

Revenue Requirement and True-up

Exhibit 99.1

The revenue requirement calculations for 2015, 2014 and 2013, excluding the revenue refund liability related to the MISO transmission owner base ROE complaints in both 2015 and 2014, discussed above in Pending Regulatory Matters, are outlined in the table below:



(In Thousands)										2015 vs. 2014					2014 vs. 2013
										Increase			Percentage		Increase			Percentage
	2015			2014			2013			(Decrease)			Change		(Decrease)			Change

Return on Rate Base
Average Rate Base	$	3,050,267		$	2,907,879		$	2,774,342		$	142,388		4.9	%	$	133,537		4.8	%
Weighted-Average Rate of Return	8.49		%	8.47		%	8.49		%	0.02		%			(0.02		)%
Return on Rate Base	259,008			246,303			235,586			12,705			5.2	%	10,717			4.5	%

Provision for Income Taxes	107,445			103,489			98,922			3,956			3.8	%	4,567			4.6	%
Total Return and Income Taxes	366,453			349,792			334,508			16,661			4.8	%	15,284			4.6	%

Recoverable Operating Expenses
Recoverable Operations and Maintenance Expenses	156,848			159,109			157,936			(2,261		)	(1.4	)%	1,173			0.7	%
Depreciation and Amortization	133,265			124,074			114,808			9,191			7.4	%	9,266			8.1	%
Taxes Other than Income	23,104			20,406			19,084			2,698			13.2	%	1,322			6.9	%
Total Recoverable Operating Expenses	313,217			303,589			291,828			9,628			3.2	%	11,761			4.0	%

Total Revenue Requirement	679,670			653,381			626,336			26,289			4.0	%	27,045			4.3	%
Less: Total Revenue Billed	685,753			659,197			646,571			26,556			4.0	%	12,626			2.0	%
Trup-up Refund	$	(6,083	)	$	(5,816	)	$	(20,235	)	$	(267	)			$	14,419

The Company continues to make significant investments in the transmission system, constructing new transmission lines, as well as rebuilding existing lines and replacing aging equipment, in order to improve the reliable performance of the system. This ongoing construction activity results in additional rate base upon which the Company is allowed to earn a return. Accordingly, average net plant in rate base increased approximately $189 million during 2015. Partially offsetting this increase in rate base was an increase in average deferred income taxes of approximately $46.6 million, which are included as an offset to the Company’s rate base. As such, average rate base increased approximately $142 million.

During December 2014, the Company issued $151 million of long-term debt which was primarily used to reduce the amount of short-term debt outstanding. The long-term debt, which was issued at a higher rate than the short- term debt, increased the debt rate component of the weighted-average rate of return during 2015 compared to 2014. Partially offsetting this increase was the April 2015 issuance of $99 million of long-term debt used to repay $100 million of higher interest long-term debt. The net increase in the weighted-average rate of return and the increase in average rate base resulted in a 5.2 percent increase in return on rate base in 2015 compared to 2014.

During 2014, the Company’s average net plant in rate base increased approximately $201 million primarily as a result of its construction program described above. Partially offsetting this increase in rate base was an increase in average deferred income taxes of approximately $69.7 million. Due to these and other factors, average rate base increased approximately $134 million.

Partially offsetting the 2014 increase to average rate base is a decrease in the weighted debt rate, which is a component of the weighted-average rate of return used to determine the Company’s return on rate base. During

Exhibit 99.1

January and December 2014, the Company issued a total of $251 million of long-term debt which was primarily used to reduce the amount of short-term debt outstanding. This long-term debt was issued at lower rates than the existing long-term debt and reduced the debt rate component of the weighted-average rate of return during 2014 as compared to 2013. These changes resulted in a 4.5 percent net increase in return on rate base during 2014.

The provision for income taxes collected in rates generally increases in proportion to the increase in equity return on rate base. Partially offsetting this increase in 2015 was an additional $1.3 million of excess deferred income taxes that the Company amortized during the year, which reduced the amount of income taxes the Company collected from its customers through its rate formula.

Recoverable operating expenses increased 3.2 percent during 2015 compared to 2014, and 4.0 percent during 2014 compared to 2013, described in detail below.

The above changes resulted in overall increases of 4.0 percent in the Company’s 2015 revenue requirement as compared to 2014, and 4.3 percent in the Company’s 2014 revenue requirement as compared to 2013.

Earnings Overview

The Company’s earnings and operating income for 2015, 2014 and 2013 are shown in the table below:



(In Thousands)							2015 vs. 2014					2014 vs. 2013
							Increase			Percentage		Increase			Percentage
	2015		2014		2013		(Decrease)			Change		(Decrease)			Change

Operating Income	$	296,515	$	327,582	$	331,267	$	(31,067	)	(9.5	)%	$	(3,685	)	(1.1	)%

Earnings Before Members' Income Taxes	$	200,441	$	238,729	$	247,614	$	(38,288	)	(16.0	)%	$	(8,885	)	(3.6	)%

The decrease in operating income in both 2015 and 2014 was primarily due to the revenue refund liability the Company recorded each year related to the MISO transmission owner base ROE complaints, discussed above in Pending Regulatory Matters, and increased costs related to the Company’s business development activities as the Company continues to pursue opportunities for expansion beyond its current service area. Partially offsetting these decreases were increases in the Company’s return on rate base, discussed above.

In addition to these changes in operating income, earnings before members’ income taxes decreased in 2015 due to an increase in interest expense which is not recoverable through the Company’s rate formula discussed below.

Exhibit 99.1

Operating Expenses

The Company’s operating expenses for 2015, 2014 and 2013 are outlined in the table below:



(In Thousands)							2015 vs. 2014					2014 vs. 2013
							Increase			Percentage		Increase			Percentage
	2015		2014		2013		(Decrease)			Change		(Decrease)			Change

Operations and Maintenance	$	154,558	$	147,428	$	142,117	$	7,130		4.8	%	$	5,311		3.7	%
Preliminary Survey & Investigation (PSI)	8,282		15,474		19,012		(7,192		)	(46.5	)%	(3,538		)	(18.6	)%
Total Operations and Maintenance	162,840		162,902		161,129		(62		)	(0.0)%		1,773			1.1	%

Depreciation and Amortization	133,265		124,074		114,808		9,191			7.4	%	9,266			8.1	%
Taxes Other than Income	23,216		20,475		19,132		2,741			13.4	%	1,343			7.0	%
Total Operating Expenses	$	319,321	$	307,451	$	295,069	$	11,870		3.9	%	$	12,382		4.2	%

The net increase in operations and maintenance expenses during 2015 compared to 2014 was mainly related to the following areas:


•	Employee-related costs increased $2.8 million, which was primarily due to a lower portion of capitalized labor, increased staffing for system protection and information technology, and increased post-retirement healthcare costs.


•	Costs related to the Company’s business development activities, which are not recovered through the Company’s rate formula, increased $2.3 million as the Company continues to pursue opportunities for expansion beyond its current service area.


•	Asset maintenance costs increased $1.3 million primarily related to transformer repair work, transmission line inspections, vegetation management activities and bushing replacements across a portion of the system. These costs were partially offset by a decrease in substation maintenance activities such as snow plowing and corrective maintenance due to favorable weather conditions during 2015.


•	Information technology costs increased $0.7 million, primarily related to software maintenance and telecommunication costs.


•	Fees paid for jointly-owned substation facilities increased $0.3 million due to the Company’s increased transmission investment at those facilities.

The above increases were partially offset by a higher allocation of administrative and general costs to capital during 2015, resulting in an estimated $0.5 million decrease to operations and maintenance costs.

The net increase in operations and maintenance expenses during 2014 compared to 2013 was mainly related to the following areas:


•	Employee-related costs increased $2.7 million, which was primarily due to increases in operations, infrastructure, compliance, and asset management, as well as increased medical costs.


•	Certain construction costs that are not related to the addition of new units of transmission property are accounted for as maintenance expense; such costs increased by $1.3 million.


•	Costs related to the Company’s business development activities, which are not recovered through the Company’s rate formula, increased $0.8 million as the Company continues to pursue opportunities for expansion beyond its current service area.


•	Information technology costs increased $1.5 million, primarily related to software installations and upgrades, software maintenance and licensing fees, and telecommunication costs.

Exhibit 99.1


•	Substation utility usage fees increased $0.2 million.


•	Outside consulting and employee training and recruiting costs increased $0.6 million.


•	Other fees and expenses increased $0.7 million.

The above increases were partially offset by the following decreases:


•	The Company had a higher allocation of administrative and general costs to capital during 2014, resulting in an estimated $0.5 million decrease to operations and maintenance costs.


•	Maintenance costs decreased by $2.0 million primarily related to accelerated inspection and review initiatives in 2013, including aerial and ground inspections of transmission equipment which did not continue at the accelerated pace during 2014. Additionally, reduced vegetation management and equipment repair activities during 2014 contributed to the decrease.

The decrease in PSI costs incurred by the Company during 2015 compared to 2014 was mainly related to the Cardinal – Hickory Creek, Badger Coulee, Bay Lake, Branch River, and various line rebuild projects. Further details related to the Cardinal – Hickory Creek, Badger Coulee, and Bay Lake projects are discussed below in the Major Projects update section.

The decrease in PSI costs incurred by the Company during 2014 compared to 2013 was mainly related to decreases in the Bay Lake project, partially offset by increases in the Badger Coulee, Branch River and various line rebuild projects. Further details related to the Bay Lake and Badger Coulee projects are discussed in the Major Projects update section below.

Depreciation and amortization expense increased during each year presented in these financial statements, mainly due to additional assets placed in service as a result of the Company’s construction program discussed above.

Taxes other than income taxes increased in each year presented in these financial statements primarily due to increases in property taxes.

Interest Expense

Components of the Company’s net interest expense for 2015, 2014 and 2013 are shown below:



(In Thousands)							2015 vs. 2014					2014 vs. 2013
							Increase			Percentage		Increase			Percentage
	2015		2014		2013		(Decrease)			Change		(Decrease)			Change

Interest Expense on Long-term Debt	$	92,498	$	87,811	$	83,495	$	4,687		5.3	%	$	4,316		5.2	%
Interest Expense on Commercial Paper	362		447		482		(85		)	(19.0	)%	(35		)	(7.3	)%
Other Interest Expense	4,390		712		507		3,678			516.6	%	205			40.4	%
Interest Expense	$	97,250	$	88,970	$	84,484	$	8,280		9.3	%	$	4,486		5.3	%

Interest expense on long-term debt increased in 2015 primarily due to the issuance of $151 million of senior notes in December 2014, partially offset by the refinancing of $100 million of senior notes with lower interest senior notes in April 2015. These debt issuances are discussed below in Capital Resources and Requirements.

Exhibit 99.1

Interest expense on long-term debt increased in 2014 due to the issuance of $100 million of senior notes in January 2014, and $151 million of senior notes in December 2014, discussed in Capital Resources and Requirements below.

Interest expense on commercial paper decreased during both 2015 and 2014 primarily due to a lower volume of commercial paper issuances each year.

Other interest expense, which is not recoverable through the Company’s rate formula, increased during 2015 compared to 2014 primarily due to accrued interest on the revenue refund liability the Company recorded related to the MISO transmission owner base ROE complaints, discussed above in Pending Regulatory Matters, and increased interest expense on revenue over-collections in accordance with the Company’s true-up provision in its tariff.

Other interest expense, which is not recoverable through the Company’s rate formula, increased during 2014 compared to 2013 primarily due to increased interest expense on 2013 and 2014 revenue over-collections, in accordance with the Company’s true-up provision in its tariff.

Liquidity and Capital Resources

Cash Flows

Net cash provided by operating activities was $389 million during 2015 compared to $388 million during 2014 and $366 million during 2013. The increases in both 2015 and 2014 were primarily related to increases in cash collected from customers, partially offset by increases in the amount of cash paid for operating expenses and interest, discussed above.

During 2015 net cash used in investing activities was $339 million compared to $336 million during 2014 and $358 million during 2013. These changes were primarily related to the Company’s construction activity and investment in DATC. In April 2013 the Company invested additional funds in DATC related to the purchase of Path 15, described in detail below, which caused net cash used in investing activities to be higher during 2013 compared to

2014 and 2015.

Changes in net cash used in financing activities during 2015, 2014 and 2013 are outlined in the following table:



										2015 vs. 2014			2014 vs. 2013
(In Thousands)	2015			2014			2013			Change			Change

Distribution of Earnings to Members	$	(174,815	)	$	(204,125	)	$	(195,484	)	$	29,310		$	(8,641	)
Issuance of Membership Units for Cash	20,000			50,000			40,000			(30,000		)	10,000
Issuance (Repayment) of Short-term Debt, Net	106,390			(160,541		)	113,884			266,931			(274,425		)
Issuance of Long-term Debt, Net of Issuance Costs	98,099			249,752			—			(151,653		)	249,752
Repayment of Long-term Debt	(100,000		)	—			—			(100,000		)	—
Advances Received for Construction	440			12,797			32,856			(12,357		)	(20,059		)
Other, Net	10			38			(75		)	(28		)	113
Net Cash Used in Financing Activities	$	(49,876	)	$	(52,079	)	$	(8,819	)	$	2,203		$	(43,260	)

Exhibit 99.1

Since its inception, the Company has distributed 80 percent of its earnings before members’ income taxes to its owners and intends to continue to do so in the future. Actual cash distributions to members for each year relate to earnings for the twelve months ended September 30 each year. The revenue refund liability recorded in 2014 related to the first MISO transmission owner base ROE complaint, discussed above in Pending Regulatory Matters, was recorded during the fourth quarter of 2014, reducing earnings paid to members on January 30, 2015. Additional revenue refund liability amounts recorded during the first three quarters of 2015 reduced current year earnings paid to members during 2015. The revenue refund liability recorded during the fourth quarter of 2015 reduced earnings paid to members on January 29, 2016. Partially offsetting the 2015 decrease in distributions caused by the revenue refund liability is the Company’s growth in earnings resulting from its investments in rate base, discussed above.

The change in cash provided by issuance of member units is a function of funding requirements for construction and investments in DATC.

The Company issued $99 million of long-term debt during 2015 and used the proceeds to repay $100 million of long-term debt that matured on April 15, 2015. During 2014 the Company issued $251 million of long-term debt and used the proceeds to pay down short-term debt balances.

Advances received for construction were related to contributions the Company received to aid construction of various projects driven by customer need. These contributions offset the costs the Company incurs and places into rate base related to these projects. During 2014 these advances were primarily related to cash the Company received from the Wisconsin Department of Transportation related to construction of the Zoo Interchange project in Milwaukee. This project was completed at the end of 2014. Therefore, no further advances were received related to this project during 2015.

Major Projects

The Badger Coulee transmission line project (“Badger Coulee”) is owned by five utilities and cooperatives: the Company, Northern States Power Company (NSP) which is an affiliate of Xcel Energy Services, Inc., Dairyland Power Cooperative, WPPI Energy, and SMMPA Wisconsin, LLC. The Company holds 50 percent interest in Badger Coulee, which has an estimated total cost of $580 million. The project is a 180-mile, 345 kilovolt (kV) electric transmission line connecting the Company’s facilities near Madison, Wisconsin to a substation owned by NSP near La Crosse, Wisconsin. Badger Coulee was approved by MISO in 2011 and designated as an MVP under the terms of the MISO tariff. Therefore, the costs of the project will be shared across the entire MISO region. The project received a Certificate of Public Convenience and Necessity (CPCN) from the Public Service Commission of Wisconsin (PSCW) in April 2015 and the Company is preparing for the start of construction.

The Cardinal – Hickory Creek project (Cardinal – Hickory Creek) is being developed jointly by the Company, ITC Midwest LLC which is an affiliate of ITC Holdings Corp., and Dairyland Power Cooperative. The Company holds a 45.5 percent interest in the project. Cardinal – Hickory Creek is a planned 125-mile, 345 kV electric transmission line which would connect the Company’s Cardinal substation near Madison, Wisconsin to facilities to be constructed by ITC Midwest near Dubuque, Iowa. Like Badger Coulee, Cardinal – Hickory Creek has also been designated as an MVP, with its costs to be shared across the entire MISO region. The project will require, at a minimum, a CPCN from the PSCW, similar approval from the Iowa Utilities Board and federal approval to cross the Mississippi River.

Exhibit 99.1

The Company’s Bay Lake Project (“Bay Lake”) will reinforce the electrical transmission grid in the Upper Peninsula of Michigan and northeastern Wisconsin. The Michigan portion of Bay Lake was approved by the Michigan Public Service Commission in 2014 and is currently under construction. It includes a 58-mile, 138 kV line between the Holmes substation in Menominee County, Michigan and the Old Mead Road substation in Escanaba, Michigan and is estimated to cost $120 million. The Wisconsin portion will include a 345 kV line and a 138 kV line, each approximately 40 miles in length, between the North Appleton substation in the Green Bay, Wisconsin area to the Morgan substation in Oconto Falls, Wisconsin. The Wisconsin portion of the project was approved by the PSCW in May 2015 with an estimated cost of $328 million. The Company is currently preparing for construction of this portion of the project. Much of Bay Lake has been designated as a regionally cost-shared project under MISO’s RECB plan.

Capital Resources and Requirements

The Company has plans for approximately $471 million in new transmission construction projects and other capital spending in 2016. During the fourth quarter of 2015 the Company released its new ten-year transmission assessment and expects that it could incur between $3.7 billion and $4.5 billion in capital expenditures over the next ten years, most of which will not be subject to the provisions of Order 1000. These estimates are based on the Company’s current capital forecast and projected ten-year transmission planning and needs assessment, much of which remains subject to regulatory approval and continuing analysis of system needs. Wisconsin and surrounding states have introduced renewable portfolio standards which target higher future levels of generation from renewable resources. As the utilities in and surrounding the Company’s transmission system implement plans to address existing or future state and federal renewable goals, there may be significant additional transmission construction required to support such plans. Future retirements of generation units in response to U.S. Environmental Protection Agency standards could also result in additional transmission requirements.

The Company and Duke Energy hold equal equity ownership in DATC, which was created to seek opportunities to acquire, build, own and operate new transmission projects that meet potential customers’ capacity and voltage requirements and future needs. DATC continues to evaluate new projects and opportunities, and participates in the competitive bidding process on projects it considers to be viable.

DATC owns the Zephyr Power Transmission Project (“Zephyr”) and is continuing the design and development of the proposed transmission line, which 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”). The 500 kV, high-voltage, direct-current transmission line, which will be between 500 miles and 850 miles long, has an estimated cost of $2.5 billion to $3.5 billion. 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. 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 for a period of time to be specified during 2016 by the parties to the agreement; however, DATC has the right to terminate the project between December 15, 2016 and January 15, 2017. DATC has received FERC approval to charge negotiated rates consistent with FERC approvals for Zephyr’s previous owners.

Exhibit 99.1

$56 million cash and the assumption of approximately $137 million of debt. Pacific Gas & Electric has an 18 percent interest in the transmission rights to Path 15 through its ownership and operation of the connecting Los Banos and Gates substations. The remaining 10 percent interest in the transmission rights to Path 15 is owned by the Western Area Power Administration, which operates and maintains the line. On February 18, 2014, Path 15 filed its rate case with FERC. On May 29, 2015, FERC approved a negotiated settlement for an annual revenue requirement of $25.9 million for the rate period of 2014 through 2016. Path 15 expects to file its next rate case in February 2017 utilizing 2016 as the test year.

The ability to construct transmission assets is dependent upon the Company obtaining extensive regulatory approvals, including siting, from the PSCW and other regulatory bodies. Management believes regulatory and siting issues pose the key risks to completing and placing transmission assets in service because unlike the Company’s rates, which are under the jurisdiction of FERC, state regulatory bodies have jurisdiction over construction. Proceedings related to permit approvals provide a forum for public opposition, which can cause delays, prevent the Company from obtaining the approvals needed to construct transmission facilities, or in some instances, could lead to the cancellation of a project after construction has commenced and the Company has incurred costs. Generally, costs that the Company has incurred for uncompleted projects have not been significant; however, there is potential for higher costs to be incurred related to larger projects. The MISO Tariff contains provisions to recover costs if the project was included in MISO’s Transmission Expansion Plan, required by MISO, or otherwise approved by MISO. If recovery is not realized through the MISO Tariff, the Company will seek recovery of such costs through its FERC-regulated rate formula; however, there is no guarantee that such recovery will be allowed by FERC. If recovery is not realized through the MISO Tariff, or recovered through rates, these costs would be charged against earnings.

The Company is required to seek approval from FERC to issue short- and long-term notes and debt securities. Likewise, the Company must also receive FERC authorization to issue member equity interests and Management Inc. shares. Effective for a two-year period beginning July 1, 2014, the Company is authorized by FERC to issue, subject to certain restrictions, short- and long-term notes and debt securities such that the aggregate balance does not exceed $3.1 billion outstanding at any one time. The Company is also authorized to issue member interests and Management Inc. shares in an aggregate amount such that the balance does not exceed $2.6 billion outstanding at any one time. Pursuant to this authorization, the Company must report to FERC all issuances, guarantees, or assumptions of liabilities within 30 days. The Company has completed all filings as required.

In the short term, the Company intends to finance construction with commercial paper offerings. As its $400 million commercial paper borrowing capacity is utilized, the Company plans to refinance outstanding commercial paper through long-term debt offerings in the private placement and/or public debt markets, which it believes remain

Exhibit 99.1

accessible at attractive rates and terms. Information regarding the Company’s short-term borrowings for the periods ended December 31 is as follows (in millions):



	Three Months						Twelve Months
	2015			2014			2015			2014
Maximum Amount of Total Short-term Debt Outstanding
(based on daily outstanding balances)	$	236		$	304		$	236		$	304
Average Amount of Total Short-term Debt Outstanding
(based on daily outstanding balances)	$	201		$	227		$	151		$	219
Weighted-average Interest Rates	0.29		%	0.20		%	0.23		%	0.21		%

The timing and amount of construction requirements have a significant impact on the Company’s liquidity and cash requirements. Based on its ten-year capital expenditure forecast, management anticipates that, under the Company’s tariff, its credit ratings will remain at investment grade and the Company will continue to have access to the capital it needs to continue to fund business activities, including its investment in DATC, while also maintaining compliance with its debt covenants. Management intends to target a total-debt-to-total-capitalization ratio of 50 to 55 percent, consistent with the maintenance of an “A” credit rating and tier one commercial paper ratings.

As of December 31, 2015 and 2014, the Company’s debt was rated as outlined in the table below:



	Fitch	Moody's	Standard & Poors

Commercial Paper	F-1	P-1	A-1

Senior Unsecured/Issuer	A+	A1	A+

If the Company cannot maintain its current credit rating, future financing costs could increase, future financing flexibility could be reduced, future access to capital could be difficult and future ability to finance capital expenditures demanded by the market could be impaired. Furthermore, management cannot provide assurance that the Company will be able to secure the additional sources of financing needed to fund the significant capital requirements associated with its ten-year capital expenditure forecast. If financing is unavailable, the Company may be forced to defer portions of its construction program, which would negatively impact the Company’s financial position, results of operations and cash flows. In addition, some expenditures may not result in assets on which the Company will earn a return, as discussed above.

As a backup to its commercial paper program, the Company’s $350 million, five-year revolving credit facility, which had a termination date of December 7, 2017, was amended and restated on June 12, 2015. The amended credit facility is $400 million and has a five-year term which expires on June 12, 2020. 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 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 percent at any given time. The

Exhibit 99.1

Company was not in violation of any financial covenants under its debt agreements during the periods included in these financial statements. It is the Company’s intent and past practice to increase the commercial paper program with any corresponding increase in its revolving credit facility.

During November 2014, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $250 million of senior notes to be funded in two tranches. Closing of the notes and funding of the first $151 million took place on December 11, 2014, with interest due semiannually on June 11 and December 11, beginning on June 11, 2015. The $151 million is comprised of $75 million of 10-year, unsecured 3.35 percent senior notes; $29 million of 15-year, unsecured 3.60 percent senior notes; and $47 million of 30-year, unsecured 4.31 percent senior notes. The notes will mature on December 11, 2024, 2029 and 2044, respectively.

Funding of the remaining $99 million took place on April 14, 2015 and is comprised of $50 million of 10-year, unsecured 3.45 percent senior notes; $21 million of 15-year, unsecured 3.70 percent senior notes; and $28 million of 30-year, unsecured 4.41 percent senior notes. Interest is due semiannually on April 14 and October 14, beginning on October 14, 2015, and will mature on April 14, 2025, 2030 and 2045, respectively. The proceeds of these notes were used to repay the $100 million of senior notes that matured on April 15, 2015.

The Company maintains its targeted debt-to-capitalization ratio through reinvested earnings and additional voluntary equity infusions from its members. The Company believes that its members will continue to fund its equity needs. Accordingly, the Company requested a voluntary capital call of $20 million, which it received in quarterly installments throughout 2015. The Company has been authorized by Management Inc.’s board of directors to request up to $125 million of additional capital through voluntary additional capital calls during 2016. The increase in the authorized capital call for 2016 is primarily due to higher expected capital spending than the previous year.

The Company’s operating agreement provides that the board of directors of its corporate manager, Management Inc., will determine the timing and amount of distributions to be made to the Company’s members. In this agreement, the corporate manager also declared its intent, subject to certain restrictions, to distribute an amount equal to 80 percent of the Company’s earnings before members’ income taxes. The Company’s operating agreement also provides that it may not pay, and no member is entitled to receive, any distribution that would generally cause the Company to be unable to pay its debts as they become due. Cash available for distribution for any period consists of cash from operations after provision for capital expenditures, debt service and reserves established by Management Inc. The Company has distributed 80 percent of its earnings before taxes to its members in each year since inception.

Exhibit 99.1

Long-term Contractual Obligations and Commercial Commitments

The Company’s contractual obligations and other commitments as of December 31, 2015, representing cash obligations that are considered to be firm commitments, are as follows (in thousands):



			Payment Due Within						Due After
	Total		1 Year		2 –3 Years		4 –5 Years		5 Years
Senior Notes	$	1,800,000	$	—	$	200,000	$	150,000	$	1,450,000
Interest Payments on Senior Notes	1,457,585		91,539		173,448		144,558		1,048,040
Operating Leases	64,888		6,483		12,833		11,588		33,984
Total Contractual Obligations and Other Commitments	$	3,322,473	$	98,022	$	386,281	$	306,146	$	2,532,024

The Company currently contracts with several vendors and utility providers for certain operations and maintenance services. Certain of the agreements contain minimum purchase requirements, as further discussed below. The Company met these obligations in all prior years and management believes it will continue to meet these obligations in the future.

Related-Party Transactions

In accordance with the Company’s operating agreement, a corporate manager, Management Inc., manages the Company and has complete discretion over the Company’s business. The Company and Management Inc. have common ownership and operate as a single functional unit. Accordingly, Management Inc. provides all management services to the Company at cost. The Company itself has no employees. The operating agreement states 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 expenses, and are recorded in the Company’s accounts as if they were direct charges of the Company.

The Company and certain of its affiliates may perform engineering and construction services for each other, subject to restrictions and reporting requirements specified in orders that have been approved by the PSCW. To prevent cross-subsidization between affiliated entities, the PSCW ordered that services be performed at a fully- allocated cost of the party providing services, and reported annually to the PSCW.

During 2016, ATC Management Inc. plans to undertake a corporate restructuring whereby certain owners will exchange their interests in the Company for interests in a new holding company, ATC Holdco LLC (“Holdco”). Under this holding company structure, Holdco will own all investments outside of the Company’s traditional footprint, as well as interests in the Company matching the current aggregate ownership interests of the exchanging Company members. Those owners of the Company who wish to participate in investments outside of the traditional footprint are able to do so through Holdco, while those owners interested only in investing in the traditional footprint will continue to own the Company directly. The corporate restructuring, through the creation of a holding company, formally separates the Company’s development activities, including its interest in DATC, from its traditional footprint activities. The Company currently has applications for approval of the corporate restructuring pending before FERC, the PSCW, and the Illinois Commerce Commission. The restructuring is contingent upon approvals of these applications which are anticipated to occur between February and November of 2016.

Exhibit 99.1

Regulatory and Operating Environment

MISO is the tariff administrator for all of its transmission-owning members. MISO and the Company made a joint filing with FERC that created a separate pricing zone for the Company within the MISO Tariff. The Company’s rates for service are administered under the MISO Tariff; however, the Company periodically files with FERC for approval of changes to the formula that determines its revenue requirements.

Under the provisions of the MISO Tariff, Network Integrated Transmission Service (NITS) provided by the Company is separately invoiced from charges incurred in the MISO energy markets. As a means to insulate transmission revenues from exposure to market risk associated with the MISO energy markets, all revenues for transmission service rendered under the provisions of the MISO Tariff are held in a trust which is an operating account for the benefit of the transmission owners. This account is separate from any other funds. Revenues derived by the Company for NITS, which comprise greater than 80 percent of the Company’s total revenue, are further insulated from market risk because the Company invoices and collects these amounts directly from its customers. As a result, the majority of the Company’s revenues are not collected by MISO or the trust.

Certain transmission projects that the Company may seek to construct are potentially entitled to regional cost- sharing rate treatment if such projects meet the criteria established under the provisions of the MISO Tariff. The Company has an increasing number of projects that meet the criteria of this regional cost-sharing arrangement. While the formula for determining the revenue requirement for projects subject to regional cost-sharing is different from the formula used for determining the Company’s network revenue requirement, it recovers the Company’s costs associated with such projects. While it is likely that a larger portion of the Company’s future revenues will be derived from transmission customers outside of the Company’s service area, as more of the Company’s transmission construction projects qualify for regional cost-sharing, the Company expects that it will continue to earn its allowed return on its assets under these cost allocation arrangements and will continue to pursue transmission projects that benefit its customers.

FERC is required by the Energy Policy Act of 2005 to implement mandatory electric transmission reliability standards, which are to be enforced by an electric reliability organization. Effective June 2007, FERC approved the mandatory adoption of certain reliability standards, along with enforcement actions for violators of those standards, including fines of up to $1 million per day per violation, which would not be recoverable through the Company’s revenue requirement and would be charged against earnings. The North American Electric Reliability Corporation (NERC) was assigned the responsibility of developing and enforcing these mandatory reliability standards. Through delegation agreements, NERC has authorized regional entities to provide regulatory oversight and monitoring of the Company’s reliability standards compliance program. Currently, both Midwest Reliability Organization and ReliabilityFirst Corporation are authorized by NERC to provide regulatory oversight of the Company. The Company administers a reliability standards compliance program, which is intended to assure compliance, and continually assesses its transmission system assets and operations against the mandatory reliability standards promulgated by NERC and those of the regional entities. The Company believes that it meets the applicable reliability standards in all material respects, although further investment in its transmission system and an increase in operations and maintenance activities will likely be required to maintain compliance, sustain and improve reliability, and assure conformance with any new reliability standards that may be issued by NERC and made mandatory through FERC approval.

Exhibit 99.1

On November 24, 2015, the Division of Audits and Accounting (DAA) within the Office of Enforcement of FERC notified the Company that it was commencing a periodic financial audit of the Company. Certain employees of Management Inc. met with FERC DAA staff in December 2015, and substantive audit field work is expected to commence in early 2016. At this time, the Company is unable to predict whether any findings will result from this audit.

Legal Matters

Environmental Matters

Critical Accounting Estimates

The preparation of financial statements requires the use of certain estimates, which involves judgments regarding future events. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions.

Regulatory Accounting

The Company operates on rates established in the Company’s Tariff, which are designed to recover the cost of service and provide a reasonable return to its owners. Under regulatory accounting, 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. 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. As discussed above in Pending Regulatory Matters, the Company recorded a regulatory liability to reflect the probable reduction in its ROE. This refund liability is based on estimates which could be materially different than the actual outcome of the proceeding.

The Company charges depreciation expense to build a reserve for the future cost to remove certain assets. This accrual is charged against depreciation expense in the statements of operations. These amounts are based on historical estimates, which the Company reviewed during a depreciation study in 2011. The Company will continue to review such estimates as it conducts future depreciation studies and expects the next study to occur in 2016.

Exhibit 99.1

As of December 31, 2015, the Company had $11.2 million in regulatory assets and $249 million in regulatory liabilities.

Property, Plant and Equipment

The Company develops estimates of capital, cost of removal and expense components for its construction projects and focuses on consistent application of capitalization policies in accordance with the FERC Uniform System of Accounts. As such, it allocates these costs based on estimates established during the planning phase of the projects. These estimates are reviewed and updated during the project and finalized upon completion of the projects. Although these estimates cause variation in the timing and amounts allocated between capital, cost of removal and expense, the Company strives to minimize variation between statement of operations and balance sheet accounts.

Qualitative Disclosures about Market Risks

The Company manages its interest rate risk by limiting its variable rate exposure and continually monitoring the effects of market changes on interest rates. Under the terms of the Company’s settlement agreement, variable- rate interest exposure is mitigated because interest on borrowed funds is included as a component of the Company’s capital structure used to determine its return on rate base in its revenue requirement formula. To the extent that lenders who hold commitments in the Company’s credit agreement become unable to meet those obligations, the Company intends to pursue other options to maintain its short-term borrowing capacity. These options may include requesting higher commitments from the remaining lenders in the Company’s existing credit agreement or adding additional lenders to the Company’s existing credit agreement. To the extent that any of these options result in increased borrowing costs, the Company believes such costs would be recoverable as a component of its revenue requirement.

The Company has a significant concentration of major customers; its five largest customers generate approximately 80 percent of its operating revenue on an ongoing basis. The Company closely monitors the business and credit risk associated with its major customers. These major customers all have investment-grade debt ratings.

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Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

WEC Energy (WEC) 10-K2015 FY Annual report

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