WEC ENERGY GROUP, INC. (Form: 10-K, Received: 02/28/2017 19:33:43)

AMERICAN TRANSMISSION COMPANY LLC Financial Statements and Independent Auditors’ Report As of December 31, 2016 and 2015 and for the Years Ended December 31, 2016, 2015 and 2014

2 American Transmission Company LLC Table of Contents Independent Auditors’ Report………………………………..………………...……………….………...... 3 Financial Statements Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014…………….. 4 Balance Sheets as of December 31, 2016 and 2015 ……..…………….…………….………….…... 5 Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014………….... 6 Statements of Changes in Members’ Equity for the Years Ended December 31, 2016, 2015 and 2014………………………………………………………………………………………….……………… 7 Notes to Financial Statements as of December 31, 2016 and 2015 and for the Years Ended December 31, 2016, 2015 and 2014 ……………………….………………………………………..…. 8-33 Management’s Discussion and Analysis of Financial Condition and Results of Operations…... 34-53 Qualitative Disclosures about Market Risks ……………….……………………………..……..………. 53-54

INDEPENDENT AUDITORS’ REPORT To the Board of Directors of ATC Management Inc., Corporate Manager of American Transmission Company LLC Waukesha, Wisconsin We have audited the accompanying balance sheets of American Transmission Company LLC (the “Company”) as of December 31, 2016 and 2015, and the related statements of operations, members’ equity, and cash flows for each of the three years ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of American Transmission Company LLC as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Milwaukee, Wisconsin February 8, 2017 3

4 American Transmission Company LLC Statements of Operations For the Years Ended December 31, 2016, 2015 and 2014 The accompanying notes are an integral part of these financial statements. (In Thousands) 2016 2015 2014 Operating Revenues Transmission Serv ice Revenue $649,136 $614,277 $633,550 Other Operating Revenue 1,670 1,559 1,483 Total Operating Revenues 650,806 615,836 635,033 Operating Expenses Operations and Maintenance 157,791 162,840 162,902 Depreciation and Amortization 141,724 133,265 124,074 Taxes Other than Income 23,002 23,216 20,475 Total Operating Expenses 322,517 319,321 307,451 Operating Income 328,289 296,515 327,582 Other Income, Net Other Income (Expense), Net 177 (584) (1,881) Equity in Earnings of Unconsolidated Subsidiary 3,048 1,760 1,998 Total Other Income, Net 3,225 1,176 117 Earnings Before Interest and Members' Income Taxes 331,514 297,691 327,699 Net Interest Expense 98,758 97,250 88,970 Earnings Before Members' Income Taxes $232,756 $200,441 $238,729

5 American Transmission Company LLC Balance Sheets As of December 31, 2016 and 2015 The accompanying notes are an integral part of these financial statements. (In Thousands) December 31, December 31, ASSETS 2016 2015 Property, Plant and Equipment Transmission Plant $4,941,372 $4,655,719 General Plant 161,289 122,745 Less- Accumulated Depreciation (1,193,603) (1,100,828) 3,909,058 3,677,636 Construction Work in Progress 359,458 229,824 Net Property , Plant and Equipment 4,268,516 3,907,460 Current Assets Accounts Receivable 66,430 59,694 Prepaid Expenses 5,486 6,707 Current Portion of Regulatory Assets 395 10,772 Other Current Assets 3,479 3,347 Total Current Assets 75,790 80,520 Regulatory and Other Assets Equity Investment in Unconsolidated Subsidiary 41,625 37,077 Regulatory Assets - 393 Other Assets 2,752 3,335 Total Regulatory and Other Assets 44,377 40,805 Total Assets $4,388,683 $4,028,785 CAPITALIZATION AND LIABILITIES Capitalization Members’ Equity (See Note 3 for redemption provisions) $1,756,760 $1,662,828 Long-term Debt 1,865,302 1,790,718 Total Capitalization 3,622,062 3,453,546 Current Liabilities Accounts Payable 28,115 16,947 Distribution Payable to Members 54,680 - Accrued Interest 24,327 23,947 Other Accrued Liabilities 53,890 50,424 Current Portion of Regulatory Liabilities 71,473 12,617 Short-term Debt 262,641 226,313 Total Current Liabilities 495,126 330,248 Regulatory and Other Long-term Liabilities Regulatory Liabilities 250,056 236,551 Other Long-term Liabilities 21,439 8,440 Total Regulatory and Other Long-term Liabilities 271,495 244,991 Commitments and Contingencies (See Note 7) - - Total Capitalization and Liabilities $4,388,683 $4,028,785

6 American Transmission Company LLC Statements of Cash Flows For the Years Ended December 31, 2016, 2015 and 2014 The accompanying notes are an integral part of these financial statements. (In Thousands) 2016 2015 2014 Cash Flows from Operating Activities Earnings Before Members' Income Taxes $232,756 $200,441 $238,729 Adjustments to Reconcile Earnings Before Members' Income Taxes to Net Cash Prov ided by Operating Activ ities- Depreciation and Amortization 141,724 133,265 124,074 Bond Discount and Debt Issuance Cost Amortization 603 582 537 Equity Earnings in Unconsolidated Subsidiary Investment (3,048) (1,760) (1,998) Change in- Accounts Receivable (6,446) (3,710) 9,795 Other Current Assets 11,859 (4,134) 5,325 Accounts Payable 4,652 69 (2,545) Accrued Liabilities 56,945 (713) 3,735 Regulatory Liabilities (6,170) 71,918 12,759 Other, Net 3,174 (7,020) (2,550) Total Adjustments 203,293 188,497 149,132 Net Cash Provided by Operating Activities 436,049 388,938 387,861 Cash Flows from Investing Activities Capital Expenditures for Property , Plant and Equipment (463,069) (339,159) (334,731) Investment in Unconsolidated Subsidiary (1,500) - (1,600) Insurance Proceeds Received for Damaged Property , Plant and Equipment - - 646 Net Cash Used in Investing Activities (464,569) (339,159) (335,685) Cash Flows from Financing Activities Distribution of Earnings to Members (154,144) (174,815) (204,125) Issuance of Membership Units for Cash 70,000 20,000 50,000 Issuance (Repayment) of Short-term Debt, Net 36,335 106,390 (160,541) Issuance of Long-term Debt, Net of Issuance Costs 73,974 98,099 249,752 Repayment of Long-term Debt - (100,000) - Advances Received Under Interconnection Agreements 2,010 - - Advances Received for Construction 345 440 12,797 Other, Net - 10 38 Net Cash Provided by (Used in) Financing Activities 28,520 (49,876) (52,079) Net Change in Cash and Cash Equivalents - (97) 97 Cash and Cash Equivalents, Beginning of Period - 97 - Cash and Cash Equivalents, End of Period $ - $ - $ 97 Supplemental Disclosures of Cash Flows Information Cash Paid for Interest (Net of Amounts Capitalized) $92,952 $92,529 $85,556 Significant Non-cash Investing or Financing Transactions- Accruals and Payables Related to Construction Costs $48,481 $36,208 $24,771

7 American Transmission Company LLC Statements of Changes in Members’ Equity For the Years Ended December 31, 2016, 2015 and 2014 The accompanying notes are an integral part of these financial statements. (In Thousands) 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 Issuance of Membership Units $ 70,000 Earnings Before Members' Income Taxes 232,756 Distribution of Earnings to Members (154,144) Distribution Payable to Members (54,680) Members’ Equity as of December 31, 2016 $1,756,760 Membership Units Outstanding at December 31, 2016 92,662

8 American Transmission Company LLC Notes to Financial Statements as of December 31, 2016 and 2015 and for the Years Ended December 31, 2016, 2015 and 2014 (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 in order to provide an adequate and reliable transmission system that meets the needs of all users on the system and provides transmission service to support 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 8, 2017, 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. incurred on behalf of the Company 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.

9 As of December 31, the following net payables to Management Inc. were included in the Company’s balance sheets (in thousands): 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 $16.4 million and $15.1 million receivable as of December 31, 2016 and 2015, respectively, for income taxes paid on Management Inc.’s behalf by the Company. The income taxes paid are due to temporary differences relating to the tax deductibility of certain employee-related costs. As these temporary differences reverse in future years, Management Inc. will receive cash tax benefits and will then repay the advances from the Company. (c) Revenue Recognition 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 and other sources. 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 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 and an accumulated under-collected true-up balance is classified as a regulatory asset in the balance sheets. The Company is required to refund any 2016 2015 Other Accrued Liabilities $11,971 $15,054 Other Long-term Liabilities 2,932 490 Net Amount Payable to Management Inc. $14,903 $15,544

10 over-collected network amounts, plus interest, within two 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 years subsequent to the rate year. Under these true- up provisions, the Company collected from network customers, inclusive of interest, through their monthly bills, a net amount of $2.6 million in 2016 and refunded to network customers, inclusive of interest, through their monthly bills, $9.9 million in 2015, and a net amount of $10.4 million in 2014. 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, net amounts of $4.7 million and $3.9 million to regional customers in 2016 and 2015, respectively, 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. The Company is currently involved in two complaints filed at FERC pursuant to Section 206 of the Federal Power Act (“Section 206”) by customer and public power groups located within the MISO service area. The primary complaint of these groups is that the base return on equity (ROE) for MISO transmission owners, including the Company, is no longer just and reasonable. On September 28, 2016, FERC issued an order on the first complaint reducing the base ROE to 10.32 percent for MISO transmission owners, including the Company. This base ROE is effective September 28, 2016 and for future periods until FERC rules in the second complaint, at which time the base ROE ordered by FERC in the second complaint will prospectively become the authorized base ROE for the Company. Further details related to these complaints are discussed in Note 7(a). (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

11 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 2.75 percent in 2016 and 2.74 percent in both 2015 and 2014. The Company completed a depreciation study during 2016 and filed with FERC on October 27, 2016 for an adjustment to its depreciation rates based on the findings of the study. FERC approved the Company’s revised rates in docket ER17-191 issued on December 15, 2016, effective January 1, 2017. 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 currently 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, 2016 and 2015 (in thousands): The 2016 revision to estimated cash flows was primarily due to changes in regulatory requirements by the Wisconsin Department of Natural Resources which resulted in increased requirements for the Company related to testing for lead-based paint on transmission structures. 2016 2015 Asset Retirement Obligations at January 1 $7,839 $7,552 Accretion 389 375 Liabilities Recognized 39 - Revision to Estimated Cash Flows 8,029 - Liabilities Settled (116) (88) Asset Retirement Obligations at December 31 $16,180 $7,839

12 (f) Interconnection Agreements The Company has entered into interconnection agreements with entities planning to build generation facilities. The Company will construct the interconnection facilities and 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. The Company has no obligation to reimburse the generator for costs incurred during construction if the generation facilities do not become operational. 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, 2016 there was $0.9 million included in CWIP related to generator interconnection agreements. The Company had no active projects related to these agreements at December 31, 2015. Similarly, other long-term liabilities included liabilities for generator advances, inclusive of accrued interest, of $2.3 million at December 31, 2016 and there were no outstanding liabilities for generator advances at December 31, 2015. (g) Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with original maturities of three months or less. The Company intends to maintain a zero cash balance by issuing short-term debt on a daily basis to cover its cash payments. Therefore, the Company had no cash or cash equivalents on the balance sheets at December 31, 2016 or 2015. (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 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.

13 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): As of December 31, these amounts were classified in the balance sheets as follows (in thousands): 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. The Company recorded regulatory liabilities of $140 million and $85.4 million at December 31, 2016 and 2015, respectively, related to the MISO transmission owner complaints discussed in Notes 1(c) and 7(a). 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 these amounts in future rates, a regulatory liability was established for an amount equal to the ASC Topic 715 asset. The Company recognized regulatory liabilities of $4.1 million and $5.7 million at December 31, 2016 and 2015, respectively, related to the over-funded position of its postretirement benefit plan at each year-end. 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. 2016 2015 Revenue True-ups, Including Interest 2014 Multi-Value Project Revenue Collected in 2016 $ - $ 1,490 2014 Scheduling Revenue Collected in 2016 - 4,887 2015 Scheduling Revenue to be Collected in 2017 395 393 Other Network Revenue Collected in 2016 - 4,395 Total Regulatory Assets $395 $11,165 2016 2015 Current Portion of Regulatory Assets $395 $10,772 Regulatory Assets (long term) - 393 Total Regulatory Assets $395 $11,165

14 As of December 31, regulatory liabilities included the following amounts (in thousands): As of December 31, these amounts were classified in the balance sheets as follows (in thousands): The increase in the current portion of regulatory liabilities from December 31, 2015 to December 31, 2016 was primarily due to FERC’s ruling on the first ROE complaint discussed in detail in Note 7(a). Refunds related to the first complaint must be completed by July 28, 2017. 2016 2015 Revenue True-ups, Including Interest 2014 Network Revenue Refunded in 2016 $ - $ 1,728 2014 Regional Cost-sharing Revenue Refunded in 2016 - 5,915 2015 Network Revenue to be Refunded in 2017 906 877 2015 Multi-Value Project Revenue to be Refunded in 2017 2,970 2,876 2015 Regional Cost-sharing Revenue to be Refunded in 2017 2,921 2,828 2016 Network Revenue to be Refunded in 2017 and 2018 7,478 - 2016 Regional Cost-sharing Revenue to be Refunded in 2018 1,929 - 2016 Multi-Value Project Revenue to be Refunded in 2018 590 - 2016 Scheduling Revenue to be Refunded in 2018 2,421 - Other Regional Cost-sharing Revenue Refunded in 2016 - 4,974 Return on Equity Refund Liability 139,678 85,380 Recognition of Over-funded Post Retirement Benefit Plan 4,085 5,714 Non-ARO Removal Costs Collected in Rates 157,448 137,940 1,103 936 Total Regulatory Liabilities $321,529 $249,168 Cumulative Difference between ARO Costs Collected in Rates and ARO Recognition under ASC Topic 410 2016 2015 Current Portion of Regulatory Liabilities $ 71,473 $ 12,617 Regulatory Liabilities (long term) 250,056 236,551 Total Regulatory Liabilities $321,529 $249,168

15 (i) Other Assets As of December 31, other assets included the following (in thousands): 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 2004 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 $5.5 million, $8.3 million and $15.5 million of preliminary survey and investigation costs were included in operations and maintenance expense for 2016, 2015 and 2014, respectively. Additional amounts reported as Other Assets in the balance sheets consist primarily of unamortized credit facility fees, non-current portion of prepaid expenses, and cash deposits. On January 1, 2016, the Company adopted Accounting Standards Update No. (ASU) 2015-03, Simplifying the Presentation of Debt Issuance Costs (ASC Topic 835) issued by FASB in April 2015. ASU 2015-03 changes the presentation of debt issuance costs in financial statements. Under the guidance in ASU 2015- 03, the Company retrospectively reports unamortized debt issuance costs in the balance sheets as a direct reduction to the related long-term debt, rather than as an asset. Amortization of the costs continues to be reported as interest expense in the statements of operations and the statements of cash flows remain unchanged. Upon adoption of ASU 2015-03, the Company restated its December 31, 2015 balance sheet with reductions to both Other Assets and Long-term Debt of $9.3 million related to the change in presentation of unamortized debt issuance costs per the guidance. At December 31, 2016, the Company reported $9.7 million of unamortized debt issuance costs as a reduction to Long-term Debt in the balance sheet. (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. 2016 2015 Deferred Project Costs $ 815 $ 551 Other 1,937 2,784 Total Other Assets $2,752 $3,335

16 (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. (l) Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to apply policies and make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are used for items such as depreciable lives of property, plant and equipment, removal costs associated with asset retirements, tax provisions included in rates, actuarially-determined benefit costs, accruals for construction costs and operations and maintenance expenses. As additional information becomes available, or actual amounts are determined, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. (m) New Accounting Pronouncements In May 2014, FASB issued 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 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

17 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 February 2015, FASB issued ASU 2015-02, Consolidation (ASC Topic 810): Amendments to the Consolidation Analysis, which changes the analysis requirements when evaluating whether or not certain types of entities must be consolidated. There was no material change to the Company’s financial position, results of operations or cash flows as a result of the Company’s January 1, 2016 adoption of ASU 2015-02. In April 2015, FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs (ASC Topic 835). As discussed in Notes 1(i) and 4(c), the Company adopted ASU 2015-03 on January 1, 2016. ASU 2015-03 changes the presentation of debt issuance costs in financial statements. Under the guidance in ASU 2015-03, the Company retrospectively reports unamortized debt issuance costs in the balance sheets as a direct reduction to the related long-term debt, rather than as an asset. Amortization of the costs continues to be reported as interest expense in the statements of operations and the statements of cash flows remain unchanged. 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. The Company elected to adopt and apply ASU 2015-05 on a prospective basis beginning on January 1, 2016. The Company’s adoption of ASU 2015-05 did not have a material effect on its financial position, results of operations or cash flows. In May 2015, FASB issued ASU 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASC Topic 820). ASU 2015-07 removes the requirement to include investments in the fair value hierarchy for which fair value is measured using the NAV per share practical expedient under ASC Topic 820. ASU 2015-07 requires retrospective application and is effective for the Company for years beginning after December 15, 2016 with early adoption permitted. ASU 2015-07 was adopted by the Company on January 1, 2016 and applied retrospectively. There was no effect on the Company’s financial position, results of operations or cash flows. In February 2016, FASB issued ASU 2016-02, Leases (ASC Topic 840), which requires transition of most leases to the balance sheet and eliminates the prior tests used in determining lease classifications. ASU 2016-02 becomes effective for the Company on a retrospective basis for the annual reporting period ending December 31, 2020 and interim periods beginning in 2021. However, the Company may, at its discretion, adopt ASU 2016-02 on a retrospective basis for the annual reporting period ending December 31, 2019, and interim periods within 2019. The Company is evaluating the impacts of ASU 2016-02. In August 2016, FASB issued ASU 2016-15, Statement of Cash Flows (ASC Topic 230), Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). ASU 2016- 15 provides guidance on eight cash flow items that have historically caused diversity in practice due to either unclear or non-existing guidance under the current guidelines. ASU 2016-15 becomes effective for

18 the Company on a retrospective basis for the annual reporting period ending December 31, 2019 and interim periods beginning in 2020, with early adoption permitted. However, the Company does not expect the adoption of ASU 2016-15 to have an impact on the Company’s cash flows. (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: The components of Management Inc.’s postretirement healthcare benefit (credit) costs for 2016, 2015 and 2014 are as follows (in thousands): The decreases in service and interest cost and the increase in amortization of prior service credit during 2016 compared to 2015 are related to 2015 plan amendments that reduced the Company’s expected future costs and changes in the assumptions used to calculate the benefit obligation at December 31, 2015. To recognize the funded status of its postretirement healthcare benefit plans in accordance with ASC Topic 715, Management Inc. recorded long-term assets of $4.1 million and $5.7 million at December 31, 2016 and 2015, respectively. In addition, the Company had the following amounts not yet reflected in net periodic benefit cost 2016 2015 2014 Discount Rate 4.42% 4.57% 4.12% Medical Cost T rend: Immediate Range 6.00% 6.10% 6.60% Ultimate Range 4.50% 4.50% 4.00% Long-term Rate of Return on Plan Assets 5.00% 5.00% 5.00% 2016 2015 2014 Service Cost $ 822 $ 1,447 $ 1,111 Interest Cost 893 1,173 1,049 Amortization of Prior Service Credit (1,324) (569) (569) Amortization of Net Actuarial Loss (Gain) (37) 276 (11) Expected Return on Plan Assets (1,342) (1,291) (1,200) Net Periodic Postretirement (Credit) Cost $ (988) $ 1,036 $ 380

19 and included in regulatory liabilities, which will be refunded as an offset to operating expense in future rates, at December 31 (in thousands): The assumed medical cost trend rates are critical assumptions in determining the service and interest cost and accumulated postretirement healthcare benefit obligation for the Company’s medical and dental plans. A one- percent change in the medical cost trend rates, holding all other assumptions constant, would have the following effects for 2016 (in thousands): In 2017, 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): 2016 2015 Prior Service Credit $(7,616) $(8,941) Accumulated Loss 3,531 3,227 Regulatory Liability for Amounts to be Refunded in Future Rates $(4,085) $(5,714) One-Percent One-Percent Increase Decrease Effect on Total of Service and Interest Cost Components $ 426 $ (317) Effect on Postretirement Benefit Obligation at the End of the Year 4,697 (3,568) 2016 2015 Change in Projected Benefit Obligation: Accumulated Postretirement Benefit Obligation at January 1 $19,795 $28,695 Amendments - (6,493) Service Cost 822 1,447 Interest Cost 893 1,173 Benefits Paid (290) (597) Actuarial Losses (Gains) 385 (4,430) Benefit Obligation at December 31 $21,605 $19,795 Change in Plan Assets: Fair Value of Plan Assets at January 1 $25,509 $25,715 Employer Contributions - 973 Actual Return (Loss) on Plan Assets (Net of Expenses) 1,460 (905) Net Benefits Paid (1,259) (274) Fair Value at December 31 $25,710 $25,509 Funded Status at December 31 $ 4,105 $ 5,714

20 The benefit obligation at December 31, 2016, increased primarily due to the service and interest costs shown above and changes in the assumptions used to calculate the benefit obligation. The changes in assumptions that increased the benefit obligation include the use of a lower discount rate, updated census data and updated claims costs reflecting recent plan experience. The use of updated mortality assumptions based on mortality tables issued by the Society of Actuaries partially reduced the increase to the benefit obligation. The Company does not anticipate contributing to the plan for postretirement healthcare benefit obligations during 2017. The Company anticipates net retiree healthcare benefit payments for the next 10 years to be as follows (in thousands): 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: 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. 2017 $ 541 2018 581 2019 561 2020 527 2021 605 2022-2026 3,943 Total $6,758 2016 2015 Target Range U.S. Equities 34.8% 34.1% 32.5% +/- 5% Non-U.S. Equities 31.8% 32.3% 32.5% +/- 5% Fixed Income 33.4% 33.6% 35.0% +/- 5% 100% 100% 100%

21 The asset classes designated above and described below serve as guides for the selection of individual investment vehicles by the trustee:  U.S. Equities – Strategy of achieving long-term growth of capital and dividend income through investing primarily in common stock of companies in the U.S. stock market with the Wilshire 5000 Index (or a comparable broad U.S. stock index) as the investment benchmark.  Non-U.S. Equities – Strategy of achieving long-term growth of capital and dividend income through investing primarily in common stock of companies in the non-U.S. stock markets with the Morgan Stanley Capital Index All Country World ex-U.S Index (or a comparable broad non-U.S. stock index) as the investment benchmark.  Fixed Income – Strategy of achieving total return from current income and capital appreciation by investing in a diversified portfolio of fixed-income securities with the Barclays Capital Aggregate Index (or a comparable broad bond index) as the investment benchmark. The objective of the investment vehicles is to minimize risk of large losses by effective diversification. The investment vehicles will attempt to rank better than the median vehicle in their respective peer group. However, these investments are intended to be viewed over the long term; during the short term, there will be fluctuations in rates of return characteristic of the securities markets. The Company measures its plan assets at fair value according to the hierarchy set forth in ASC Topic 820. The three levels of the fair value hierarchy under ASC Topic 820 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, 2016 and 2015. 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.

22  Mutual Funds: Valued at the net asset value of shares held by the plan at year-end. The following table contains, by level within the fair value hierarchy, the Company’s postretirement healthcare benefit account investments at fair value as of December 31 (in thousands): During 2016 and 2015, 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 $3.6 million, $3.5 million and $3.3 million in 2016, 2015 and 2014, 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, 2016 and 2015, $18.5 million and $18.1 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 $1.1 million, $1.2 million and $1.1 million in 2016, 2015 and 2014, 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. During 2016, 2015 and 2014, the Company distributed $154 million, $175 million and $204 million, respectively, of its earnings to its members. In December 2016, the board of directors of Management Inc. approved a 2016 Level 1 Level 2 Level 3 Total Money Market Fund $ - $465 $ - $ 465 Mutual Funds 25,245 - - 25,245 Total $25,245 $465 $ - $25,710 2015 Level 1 Level 2 Level 3 Total Money Market Fund $ - $232 $ - $ 232 Mutual Funds 25,277 - - 25,277 Total $25,277 $232 $ - $25,509

23 distribution for the fourth quarter of 2016, in the amount of $54.7 million, that was paid on January 31, 2017, bringing the total distributions related to 2016 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 2016, the Company issued 3,921,491 units to members in exchange for $70 million in cash. During 2015 and 2014 the Company issued members 1,152,328 units for $20 million in cash and 2,974,510 units for $50 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 has a $400 million, five-year revolving credit facility, 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 ratings of A+/A+/A2, 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, 2016 or 2015. (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 $262 million of

24 commercial paper outstanding as of December 31, 2016 at an average rate of 0.77 percent and $226 million of commercial paper outstanding as of December 31, 2015 at an average rate of 0.40 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. (c) Long-term Debt The following table summarizes the Company’s long-term debt outstanding as of December 31 (in thousands): 2016 2015 Senior Notes at stated rate of 7.02%, due August 31, 2032 $ 50,000 $ 50,000 100,000 100,000 Senior Notes at stated rate of 5.59%, due December 1, 2035 100,000 100,000 Senior Notes at stated rate of 5.91%, due August 1, 2037 250,000 250,000 Senior Notes at stated rate of 5.58%, due April 30, 2018 200,000 200,000 Senior Notes at stated rate of 5.40%, due May 15, 2019 150,000 150,000 Senior Notes at stated rate of 4.59%, due February 1, 2022 100,000 100,000 Senior Notes at stated rate of 5.72%, due April 1, 2040 50,000 50,000 Senior Notes at stated rate of 4.17%, due March 14, 2026 75,000 75,000 Senior Notes at stated rate of 4.27%, due March 14, 2026 75,000 75,000 Senior Notes at stated rate of 5.17%, due March 14, 2041 150,000 150,000 Senior Notes at stated rate of 4.37%, due April 18, 2042 150,000 150,000 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 50,000 Senior Notes at stated rate of 3.70%, due April 14, 2030 21,000 21,000 Senior Notes at stated rate of 4.41%, due April 14, 2045 28,000 28,000 Senior Notes at stated rate of 3.97%, due January 26, 2047 75,000 - Other Long-term Notes Payable 36 29 Total Long-term Debt $1,875,036 $1,800,029 Less: Unamortized Debt Issuance Costs (9,734) (9,311) Long-term Debt, Net of Unamortized Debt Issuance Costs $1,865,302 $1,790,718 Senior Notes at stated rate of 6.79%, due on dates ranging from August 31, 2024 to August 31, 2043

25 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): 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 October 2016, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $150 million of 30-year, unsecured 3.97 percent senior notes to be funded in two tranches. Closing of the transaction and funding of the first $75 million of notes took place on November 15, 2016 with interest due semiannually on January 26 and July 26, beginning on July 26, 2017. The notes will mature on January 26, 2047. Funding of the remaining $75 million took place on January 26, 2017. These notes will also pay interest semiannually on January 26 and July 26, beginning on July 26, 2017, and will mature on January 26, 2047. 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. 2017 $ - 2018 200 2019 150 2020 - 2021 - Thereafter 1,525 $1,875

26 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. As discussed in Notes 1(i) and 1(m), the Company adopted ASU 2015-03 on January 1, 2016. Under the guidance in ASU 2015-03, the Company retrospectively reports unamortized debt issuance costs in the balance sheets as a direct reduction to the related long-term debt, rather than as an asset. Upon adoption of ASU 2015-03, the Company restated its December 31, 2015 balance sheet with reductions to both Other Assets and Long-term Debt of $9.3 million related to the change in presentation of unamortized debt issuance costs per the guidance. At December 31, 2016, the Company reported $9.7 million of unamortized debt issuance costs as a reduction to Long-term Debt in the balance sheet. (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, excluding unamortized debt issuance costs, and the estimated fair value of the Company’s long-term debt at December 31 are as follows (in millions): (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 $681 million, $614 million and $568 million in 2016, 2015 and 2014, respectively, and are primarily related to accelerated tax depreciation and other plant-related differences. The 2016, 2015 and 2014 revenues include recovery of $111 million, $107 million and $103 million, respectively, of income tax expense. 2016 2015 Carrying Amount $ 1,875 $ 1,800 Estimated Fair Value 2,097 2,030

27 On December 19, 2014, the Tax Increase Prevention Act of 2014 (“2014 Tax Act”) was signed in to law extending bonus depreciation from previous legislation 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 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 2016, 2015 or 2014. 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 2012. 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, the Company is currently involved in two Section 206 complaints filed at FERC by customer and public power groups located within the MISO service area. The primary complaint of these groups is that the base ROE for MISO transmission owners, including the Company, is no longer just and reasonable. The first complaint covers the period from November 12, 2013 through February 11, 2015. The administrative law judge (ALJ) issued an initial decision on the first complaint with a base ROE recommendation of 10.32 percent. On September 28, 2016, FERC issued a final order on the first complaint affirming the ALJ’s base ROE recommendation of 10.32 percent. The second complaint covers the period from February 12, 2015 through May 11, 2016. The ALJ issued an initial decision on the second complaint in June 2016, recommending a base ROE of 9.7 percent. FERC is expected to rule on this proceeding by mid-2017 and is not bound by the ALJ decision. FERC could set the base ROE higher or lower than the ALJ recommendation. The base ROE ordered by FERC in the first complaint is effective prospectively as the authorized base ROE for the Company until FERC rules in the second complaint. At that time the base ROE ordered by FERC in the second complaint will be effective prospectively from the date of the order. During February 2016, the complainants filed a joint motion with FERC for partial summary disposition and interim relief (the “Motion”). The Motion requested that FERC extend the MISO transmission owners’ base

28 ROE of 10.32% recommended by the ALJ in the first complaint prospectively from May 11, 2016 until such time as FERC rules in the second complaint. FERC has not ruled on the Motion. Based on a request made by the Company and other MISO transmission owners, FERC approved a 50 basis-point incentive ROE adder for participation in MISO, effective January 6, 2015. Inclusion of the adder in the Company’s overall ROE was confirmed as the resulting ROE is within the zone of reasonableness established in the first ROE complaint proceeding. Therefore, beginning on September 28, 2016, the Company’s allowed rate of return on equity is 10.82 percent, inclusive of the 50 basis-point adder. FERC accepted the transmission owners’ request to defer collection of the adder pending the outcome of the first complaint proceeding. Collection of the adder will partially offset the refund resulting from the first complaint proceeding and any refund that may be ordered related to the second complaint. The Company and other MISO transmission owners are working with MISO on the process to issue the net refund related to the first complaint. On October 28, 2016 FERC granted the request of the Company and other MISO transmission owners for an extension of time to complete refunds and issue refund reports to July 28, 2017. The Company began refunding these amounts to customers in January 2017 and expects to complete its refunds related to the first complaint by the end of June 2017. Additionally, the Company believes it is probable that a refund will be required upon ultimate resolution of the second complaint. The Company has recorded regulatory liabilities, inclusive of interest, of $140 million and $85.4 million as of December 31, 2016 and 2015, respectively, related to these complaints. The Company also recorded reductions to operating revenue of $50.1 million, $63.8 million and $18.3 million in the statements of operations at December 31, 2016, 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 in the second complaint could have a material impact to the Company’s financial position, results of operations and cash flows. (b) Operating Leases The Company leases both office and data center space under non-cancelable operating leases. Amounts incurred were approximately $6.5 million annually during 2016, 2015 and 2014. Future minimum lease payments under non-cancelable operating leases for the years ending December 31 are as follows (in millions): 2017 $ 6.5 2018 6.4 2019 5.8 2020 5.8 2021 5.8 Thereafter 28.1 $58.4

29 (c) MISO Revenue Distribution Periodically, the Company receives adjustments to revenues that were allocated to it by MISO in prior periods. Some of these adjustments may result from disputes filed by transmission customers. The Company does not expect any such adjustments to have a significant impact on its financial position, results of operations or cash flows since adjustments of this nature are typically offset by its true-up provision in the revenue requirement formula. (d) Interconnection Agreements The Company has entered into interconnection agreements with entities planning to build generation facilities. The Company will construct the facilities and 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 operation and will reimburse the generator for construction costs plus interest. The Company has no obligation to reimburse the generator for costs incurred during construction if the generation facilities do not become operational. The current estimate of the Company’s commitments under these agreements, if the generation facilities become operational, is approximately $5.6 million at completion, with expected completion at the end of 2017 and repayment in early 2018. In addition, there may be transmission service requests that require the Company to construct additional, or modify existing, transmission facilities to accommodate such requests. Whether such additions or upgrades to the Company’s transmission system are required depends on the state of the transmission system at the time the transmission service is requested. The Company has not reimbursed any amounts to generators under these agreements during the periods covered by these financial statements and does not expect to reimburse any amounts to generators in 2017 under such agreements. (e) Potential Adverse Legal Proceedings The Company has been, and will likely in the future become, party to lawsuits, potentially including suits that may involve claims for which it may not have sufficient insurance coverage. The Company’s liability 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.

30 (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 $155 million of additional capital through voluntary additional capital calls (VACCs) during 2017, including $40 million it received in January 2017. The Company received a total of $70 million, $20 million and $50 million through VACCs in 2016, 2015 and 2014, respectively. The increase in the VACC for 2017 was 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. (b) Corporate Restructuring A new sister entity, ATC Development LLC (“Development LLC”), was created in 2016 to formally separate the Company's development activities from its operations in its traditional footprint. Those owners of the Company who wish to participate in investments outside the traditional footprint will be able to do so through Development LLC, while the remaining owners will have the opportunity to continue to invest only in the traditional footprint. Effective in 2016, the Company no longer bears the costs of such external development activities; Management Inc. now charges such costs to Development LLC, which is not a subsidiary of either the Company or Management, Inc. The Company incurred $5.6 million in 2015 and $4.7 million in 2014 for such costs which were not recovered through the Company’s rate formula. The Company expects to transfer its interest in DATC, discussed in Note 8(c) below, to Development LLC in 2017. This transfer requires FERC approval, for which the Company expects to file during the first quarter of 2017. (c) Duke-American Transmission Company LLC The Company and Duke Energy hold equal equity ownership in 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 kilovolt (kV) high-voltage direct-current transmission line, which will be approximately 525 miles long, has an estimated cost of $2.6 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 regulatory phase project costs up to a current, budgeted amount of approximately $119 million; however, DATC has the right to terminate its involvement in the project in January 2019, and will have additional opportunities for

31 termination in the future. DATC has received FERC approval to charge negotiated rates consistent with FERC approvals for Zephyr’s previous owners. The area of Path 15 is an 84-mile stretch containing three existing 500 kV transmission lines in central California. Path 15, as used in these financial statements, refers to the third of the three 500 kV transmission lines in the corridor. 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. Path 15 has a FERC-approved 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. 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 $41.6 million and $37.1 million at December 31, 2016 and 2015, 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 in both 2016 and 2015 and $32.8 million in 2014. Accounts payable and other accrued liabilities include amounts payable to members of the Company of $3.8 million and $3.1 million at December 31, 2016 and 2015, respectively. (e) Transmission Service Accounts receivable includes amounts due from the Company’s members of $45.9 million and $44.8 million primarily related to transmission service at December 31, 2016 and 2015, respectively. Revenues from the

32 Company’s members were approximately 90 percent of the Company’s transmission service revenue for the years ended December 31, 2016, 2015 and 2014. (f) Management Inc. As discussed in Note 1(b), Management Inc. manages the Company. Management Inc. charged the Company approximately $111 million, $106 million and $101 million in 2016, 2015 and 2014, 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. (g) Interconnection Agreements As discussed in Notes 1(f) and 7(d), the Company has interconnection agreements related to the capital improvements required to connect new generation equipment to the grid. Some of these agreements are with members or affiliates of members of the Company. Liabilities at December 31, 2016 included $0.9 million of amounts received related to these agreements from entities that are also members of the Company. No amounts were included in liabilities at December 31, 2015 as there were no active projects under these agreements. The Company made no reimbursements to such members during the periods covered by these financial statements and does not expect to make any such reimbursements during 2017.

33 (9) Quarterly Financial Information (unaudited) Because of seasonal factors impacting the Company’s business, particularly the maintenance and construction programs, and the timing of when the Company recorded the revenue refund liability related to the MISO transmission owner base ROE complaints, discussed above in Note 7(a), 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. (In Thousands) Three Months Ended 2016 March 31 June 30 September 30 December 31 Total Operating Revenues $164,240 $154,225 $158,126 $174,215 $650,806 Operating Expenses 79,065 81,698 80,271 81,483 322,517 Operating Income 85,175 72,527 77,855 92,732 328,289 Other Income, Net 127 1,308 1,128 662 3,225 Interest Expense, Net 24,208 24,882 24,624 25,044 98,758 Earnings Before Members' Income Taxes $ 61,094 $ 48,953 $ 54,359 $ 68,350 $232,756 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 Other 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

34 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. incurred on behalf of the Company. 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 in order to provide an adequate and reliable transmission system that meets the needs of all users on the system and provides transmission service to support 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 $4.1 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 transmission system 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.

35 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, 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. On September 28, 2016, FERC issued an order which effectively reduced the Company’s return on equity (ROE) from 12.2 percent to 10.82 percent, effective on that date. Further discussion related to the MISO return on equity complaint resulting in this decrease is included in the Pending Regulatory Matters section below. 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 and other sources. 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 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 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 years subsequent to the rate year. During 2016, the Company collected from network customers, through their monthly bills, a net amount of $2.6 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 2016, the Company refunded a net amount of $4.7 million, inclusive of interest, 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. 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

36 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. Pending Regulatory Matters MISO Return on Equity Complaints The Company is currently involved in two complaints filed at FERC pursuant to Section 206 of the Federal Power Act by customer and public power groups located within the MISO service area. The primary complaint of these groups is that the base ROE for MISO transmission owners, including the Company, is no longer just and reasonable. The first complaint covers the period from November 12, 2013 through February 11, 2015. The administrative law judge (ALJ) issued an initial decision on the first complaint with a base ROE recommendation of 10.32 percent. On September 28, 2016, FERC issued a final order on the first complaint affirming the ALJ’s base ROE recommendation of 10.32 percent. The second complaint covers the period from February 12, 2015 through May 11, 2016. The ALJ issued an initial decision on the second complaint in June 2016, recommending a base ROE of 9.7 percent. FERC is expected to rule on this proceeding by mid-2017 and is not bound by the ALJ decision. FERC could set the base ROE higher or lower than the ALJ recommendation. The base ROE ordered by FERC in the first complaint is effective prospectively as the authorized base ROE for the Company until FERC rules in the second complaint. At that time the base ROE ordered by FERC in the second complaint will be effective prospectively from the date of the order. During February 2016, the complainants filed a joint motion with FERC for partial summary disposition and interim relief (the “Motion”). The Motion requested that FERC extend the MISO transmission owners’ base ROE of 10.32% recommended by the ALJ in the first complaint prospectively from May 11, 2016 until such time as FERC rules in the second complaint. FERC has not ruled on the Motion. Based on a request made by the Company and other MISO transmission owners, FERC approved a 50 basis-point incentive ROE adder for participation in MISO, effective January 6, 2015. Inclusion of the adder in the Company’s overall ROE was confirmed as the resulting ROE is within the zone of reasonableness established in the first ROE complaint proceeding. Therefore, beginning on September 28, 2016, the Company’s allowed rate of return on equity is 10.82 percent, inclusive of the 50 basis-point adder. FERC accepted the transmission owners’ request to defer collection of the adder pending the outcome of the first complaint proceeding. Collection of the adder will partially offset the refund resulting from the first complaint proceeding and any refund that may be ordered related to the second complaint. The Company and other MISO transmission owners are working with MISO on the process to issue the net refund related to the first complaint. On October 28, 2016 FERC granted the request of the Company and other MISO transmission owners for an extension of time to complete refunds and issue refund reports to July 28, 2017. The Company began refunding these amounts to customers in January 2017 and expects to complete its refunds related to the first complaint by the end of June 2017. Additionally, the Company believes it is probable that a

37 refund will be required upon ultimate resolution of the second complaint. The Company has recorded regulatory liabilities, inclusive of interest, of $140 million and $85.4 million as of December 31, 2016 and 2015, respectively, related to these complaints. The Company also recorded reductions to operating revenue of $50.1 million, $63.8 million, and $18.3 million in the statements of operations at December 31, 2016, 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 in the second complaint could have a material impact to the Company’s financial position, results of operations and cash flows. FERC Income Tax Policy On July 1, 2016, the D.C. Circuit of the U.S. Court of Appeals (the “Court”) issued an order on appeal of a series of FERC orders related to a rate proceeding involving a pipeline company. The case involved complaints filed by the pipeline’s customers regarding issues related to its tariff, including FERC’s assessment of the pipeline’s recovery of income taxes as a component of the pipeline’s cost of service. The pipeline was formed as a non-taxable limited partnership. In its cost of service, FERC has allowed the pipeline to recover the income taxes paid by the partnership's partner-investors on their respective shares of partnership earnings. Specifically, the complainants claim that because FERC’s ratemaking methodology already ensures a sufficient after-tax rate of return to attract investment capital, and partnership pipelines do not incur entity-level income taxes, FERC’s tax allowance policy permits partners in a partnership pipeline to “double-recover” their income taxes. The Court found that FERC has not adequately justified, in the record, its tax allowance policy in its May 4, 2005 Policy Statement on Income Taxes and vacated FERC’s orders on the issue, remanding it to FERC for further consideration and proceedings. On December 15, 2016, FERC issued a Notice of Inquiry (NOI) regarding how to address any double recovery of income tax costs resulting from FERC’s current income tax allowance and rate of return policies. The NOI proposes to allow regulated entities to earn a sufficient return that does not result in the double recovery of investor-level tax costs for partnerships. Although the Company does not believe that it double recovers income taxes under the current policy, a change to the current FERC income tax policy could have a material effect on the Company’s financial position, revenues, results of operations and cash flows. Accordingly, the Company continues to closely monitor developments in this case. Depreciation Study The Company completed a depreciation study during 2016 and filed with the FERC on October 27, 2016 for an adjustment to its depreciation rates based on the findings of the study. FERC approved the Company’s revised rates on December 15, 2016, effective January 1, 2017. The depreciation study determined estimated useful lives to range from five to 70 years which are reflected in the revised rates. The Company estimates that its annual depreciation expense for 2017 will increase by approximately $0.9 million as a result of implementing the adjusted rates.

38 Results of Operations Revenues The Company’s operating revenues for 2016, 2015, and 2014, which include reductions each year 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: Network and other revenues related to regional and multi-value projects for September 28, 2016 through the end of 2016 were adjusted to reflect the reduced ROE ordered by FERC in the first ROE complaint, discussed above in Pending Regulatory Matters. 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 (In Thousands) 2016 vs. 2015 2015 vs. 2014 2016 2015 2014 Increase (Decrease) Percentage Change Increase (Decrease) Percentage Change Network Serv ice Revenue $526,287 $500,653 $516,335 $ 25,634 5.1% $(15,682) (3.0)% Regional Cost-Sharing Revenue 88,365 82,718 82,681 5,647 6.8% 37 0.0% Multi-Value Projects Revenue 10,666 6,586 9,438 4,080 61.9% (2,852) (30.2)% Point-to-Point Revenue 7,733 8,168 9,063 (435) (5.3)% (895) (9.9)% Other Transmission Serv ice Revenue 16,085 16,152 16,033 (67) (0.4)% 119 0.7% Transmission Serv ice Revenue 649,136 614,277 633,550 34,859 5.7% (19,273) (3.0)% Other Operating Revenue 1,670 1,559 1,483 111 7.1% 76 5.1% Total Operating Revenues $650,806 $615,836 $635,033 $34,970 5.7% $(19,197) (3.0)%

39 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.

40 Revenue Requirement and True-up The revenue requirement calculations for 2016, 2015 and 2014, excluding the revenue refund liability related to the MISO transmission owner base ROE complaints, discussed above in Pending Regulatory Matters, are outlined in the table below: 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 $273 million during 2016. Partially offsetting this increase in rate base was an increase in average deferred income taxes of approximately $67.1 million, which are included as an offset to the Company’s rate base. As such, average rate base increased approximately $205 million. During April 2015, the Company issued $99 million of long-term debt and used the proceeds to repay $100 million of higher interest long-term debt. Additionally, the Company had a lower proportion of higher interest long-term debt to total debt and greater monthly average short-term debt issuances issued at higher rates in 2016 than 2015. These changes resulted in a 10 basis point net decrease in the debt rate component of the weighted-average rate of return for 2016 compared to 2015. As discussed above in Pending Regulatory Matters, FERC’s September 28, 2016 order in the first MISO ROE complaint decreased the equity rate component of the weighted-average rate of return during 2016 compared to 2015. These decreases in the components of the overall weighted-average rate of return and the increase in average annualized rate base resulted in a 3.2 percent increase in return on rate base for 2016 compared to 2015. During 2015, the Company’s average net plant in rate base increased approximately $189 million primarily as a result of its construction program described above. Partially offsetting this increase in rate base was an increase in 2016 vs. 2015 2015 vs. 2014 (In Thousands) 2016 2015 2014 Increase (Decrease) Percentage Change Increase (Decrease) Percentage Change Return on Rate Base Average Rate Base $3,255,119 $3,050,267 $2,907,879 $204,852 6.7% $142,388 4.9% Weighted-Average Rate of Return 8.21% 8.49% 8.47% (0.28)% 0.02% Return on Rate Base 267,396 259,008 246,303 8,388 3.2% 12,705 5.2% Provision for Income Taxes 111,462 107,445 103,489 4,017 3.7% 3,956 3.8% Total Return and Income Taxes 378,858 366,453 349,792 12,405 3.4% 16,661 4.8% Recoverable Operating Expenses Recoverable Operations and Maintenance Expenses 157,322 156,848 159,109 474 0.3% (2,261) (1.4)% Depreciation and Amortization 141,724 133,265 124,074 8,459 6.3% 9,191 7.4% Taxes Other than Income 23,002 23,104 20,406 (102) (0.4)% 2,698 13.2% Total Recoverable Operating Expenses 322,048 313,217 303,589 8,831 2.8% 9,628 3.2% Total Revenue Requirement 700,906 679,670 653,381 21,236 3.1% 26,289 4.0% Less: Total Revenue Billed 713,116 685,753 659,197 27,363 4.0% 26,556 4.0% True-up Refund $ (12,210) $ (6,083) $ (5,816) $ (6,127) $(267)

41 average deferred income taxes of approximately $46.6 million. Due to these and other factors, 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. The provision for income taxes collected in rates generally increases in proportion to the increase in equity return on rate base. The Company’s equity return on rate base was 3.6 percent and 4.9 percent during 2016 and 2015, respectively. Partially offsetting the 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 2.8 percent during 2016 compared to 2015, and 3.2 percent during 2015 compared to 2014, described in detail below. The above changes resulted in overall increases of 3.1 percent in the Company’s 2016 revenue requirement as compared to 2015, and 4.0 percent in the Company’s 2015 revenue requirement as compared to 2014. Earnings Overview The Company’s earnings and operating income for 2016, 2015 and 2014 are shown in the table below: The increases in operating income and earnings before members’ income taxes for 2016 compared to 2015 were primarily due to the increase in the Company’s return on rate base discussed above and decreased amounts recorded to the revenue refund liability the Company recorded related to the MISO transmission owner base ROE complaints, discussed above in Pending Regulatory Matters. Also contributing to the increases were decreased expenses recorded by the Company related to business development activities. Throughout 2016, the Company has no longer included business development expenses in its operating income or earnings before members’ income taxes. Such costs are now billed to the newly-created ATC development entity discussed below in Related-Party Transactions. The decrease in operating income in 2015 compared to 2014 was primarily due to the revenue refund liability the Company recorded related to the MISO transmission owner base ROE complaints, discussed above in Pending 2016 vs. 2015 2015 vs. 2014 (In Thousands) 2016 2015 2014 Increase (Decrease) Percentage Change Increase (Decrease) Percentage Change Operating Income $328,289 $296,515 $327,582 $31,774 10.7% $(31,067) (9.5)% Earnings Before Members' Income Taxes $232,756 $200,441 $238,729 $32,315 16.1% $(38,288) (16.0)%

42 Regulatory Matters, and increased costs related to the Company’s business development activities. Partially offsetting these decreases were increases in the Company’s return on rate base, discussed above. In addition to the 2015 decrease in operating income compared to 2014, earnings before members’ income taxes decreased due to an increase in interest expense which is not recoverable through the Company’s rate formula discussed below. Operating Expenses The Company’s operating expenses for 2016, 2015 and 2014 are outlined in the table below: The net decrease in operations and maintenance expenses during 2016 compared to 2015 was mainly related to the following areas:  The Company is no longer including expenses related to business development activities in its operations and maintenance expenses as it has begun billing such costs to the newly-created ATC development entity discussed below in Related-Party Transactions. Accordingly, operations and maintenance costs related to the Company’s business development activities, which were not recovered through the Company’s rate formula, decreased $5.5 million in 2016 compared to 2015.  Certain construction costs that are not related to the addition of new units of transmission property are accounted for as maintenance expense; such costs decreased by $1.9 million. Partially offsetting the above decreases were the following increases in 2016:  Employee-related costs increased $3.4 million, which was primarily due to increases in compensation and benefits.  Maintenance costs had a net increase of $0.8 million primarily related to vegetation management activities on transmission right-of-ways which was partially offset by reduced requirements for corrective maintenance activities.  Information technology costs increased $0.7 million mainly due to software installations and upgrades, software licensing fees, and telecommunication costs.  Net other fees and expenses increased $0.3 million. 2016 vs. 2015 2015 vs. 2014 (In Thousands) 2016 2015 2014 Increase (Decrease) Percentage Change Increase (Decrease) Percentage Change Operations and Maintenance $152,319 $154,558 $147,428 $ (2,239) (1.4)% $ 7,130 4.8% Preliminary Survey and Investigation (PSI) 5,472 8,282 15,474 (2,810) (33.9)% (7,192) (46.5)% Total Operations and Maintenance 157,791 162,840 162,902 (5,049) (3.1)% (62) (0.0)% Depreciation and Amortization 141,724 133,265 124,074 8,459 6.3% 9,191 7.4% Taxes Other than Income 23,002 23,216 20,475 (214) (0.9)% 2,741 13.4% Total Operating Expenses $322,517 $319,321 $307,451 $3,196 1.0% $11,870 3.9%

43 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.  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 decrease in PSI costs incurred by the Company during 2016 compared to 2015 was mainly related to decreases in the Badger Coulee project, the Wisconsin portion of the Bay Lake project, and various transmission line projects. Both Badger Coulee and the Wisconsin portion of Bay Lake received regulatory approval in 2015. In 2016, the Public Service Commission of Wisconsin (PSCW) issued a new set of rules related to project approval requirements in Wisconsin. The new rules provide for filing exemptions if certain criteria are met for projects that would otherwise require a Certificate of Authority (CA) or Certificate of Public Convenience and Necessity (CPCN) from the PSCW. The Company met the filing exemption criteria on some of its projects and, as a result, recorded lower amounts of PSI during 2016 compared to 2015. Partially offsetting these decreases were increases in the Wisconsin – Illinois Reliability project and Cardinal – Hickory Creek. Further details related to the Cardinal – Hickory Creek, Badger Coulee, and Bay Lake projects are discussed in the Major Projects update section below. 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. 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. The 2016 decrease in taxes other than income compared to 2015 was primarily due to decreased gross receipts tax and prepaid environmental impact fees, partially offset by increased property taxes in the state of Michigan. Taxes other than income taxes increased in 2015 compared to 2014 primarily due to increases in property taxes in the state of Michigan.

44 Interest Expense Components of the Company’s net interest expense for 2016, 2015 and 2014 are shown below: Interest expense on long-term debt increased in 2015 compared to 2014 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. Interest expense on commercial paper increased during 2016 due to a higher volume of commercial paper issued at higher rates during 2016 compared to 2015. Interest expense on commercial paper decreased during 2015 primarily due to a lower volume of commercial paper issuances compared to 2014. Other interest expense, which is not recoverable through the Company’s rate formula, increased during both 2016 and 2015 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. The 2016 increase was partially offset by decreased interest expense on revenue over-collections in accordance with the Company’s true-up provision in its tariff while increased interest expense on these revenue over-collections contributed to the increase in 2015. Liquidity and Capital Resources Cash Flows Net cash provided by operating activities was $436 million during 2016 compared to $389 million during 2015 and $388 million during 2014. The increases in both 2016 and 2015 were primarily related to increases in cash collected from customers related to the increase in the Company’s revenue requirement and increases in recoverable operating expenses, described above. The Company billed and collected amounts from its customers during 2015 and for the first nine months of 2016 based on its prior FERC-authorized ROE of 12.2 percent. Effective September 28, 2016, the Company began billing and collecting amounts at the new FERC-authorized ROE of 10.82 percent. As discussed above in Pending Regulatory Matters, the Company and other MISO transmission owners are working with MISO on the process to issue the net refund related to the first complaint. The Company began refunding these amounts to customers in January 2017 and expects to complete its refunds related to the first complaint by the end of June 2017. The increase in 2015 was primarily related to increases in 2016 vs. 2015 2015 vs. 2014 (In Thousands) 2016 2015 2014 Increase (Decrease) Percentage Change Increase (Decrease) Percentage Change Interest Expense on Long-term Debt $92,524 $92,498 $87,811 $26 0.0% $4,687 5.3% Interest Expense on Commercial Paper 1,412 362 447 1,050 290.1% (85) (19.0)% Other Interest Expense 4,822 4,390 712 432 9.8% 3,678 516.6% Interest on Interconnection Agreements 21 - - 21 0.0% - N/A Capitalized Interest on Interconnection Agreements (21) - - (21) 0.0% - N/A Net Interest Expense $98,758 $97,250 $88,970 $1,508 1.6% $8,280 9.3%

45 cash collected from customers, partially offset by increases in the amount of cash paid for operating expenses and interest, discussed above. During 2016 net cash used in investing activities was $465 million compared to $339 million during 2015 and $336 million during 2014. These changes were primarily related to the Company’s construction activity and investment in Duke American Transmission Company LLC (DATC), discussed below in the Capital Requirements and Requirements section. Further details on a few of the Company’s larger transmission projects are discussed in the Major Projects section below. Changes in net cash provided by (used in) financing activities during 2016, 2015 and 2014 are outlined in the following table: 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 made to members in each calendar year relate to earnings for the twelve months ended September 30 each year. The distribution to earnings to members declined during 2015 and 2016 due to the revenue refund liabilities recorded related to the ROE complaints. Partially offsetting the decreases in distributions caused by the revenue refund liability was the Company’s growth in earnings each year 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. During 2016 and 2014 the Company issued $75 million and $251 million of long-term debt, respectively, and used the proceeds to pay down short-term debt balances. 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. 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. 2016 vs. 2015 2015 vs. 2014 (In Thousands) 2016 2015 2014 Change Change Distribution of Earnings to Members $(154,144) $(174,815) $(204,125) $ 20,671 $29,310 Issuance of Membership Units for Cash 70,000 20,000 50,000 50,000 (30,000) Issuance (Repayment) of Short-term Debt, Net 36,335 106,390 (160,541) (70,055) 266,931 Issuance of Long-term Debt, Net of Issuance Costs 73,974 98,099 249,752 (24,125) (151,653) Repayment of Long-term Debt - (100,000) - 100,000 (100,000) Advances Received Under Interconnection Agreements 2,010 - - 2,010 - Advances Received for Construction 345 440 12,797 (95) (12,357) Other, Net - 10 38 (10) (28) Net Cash Provided by (Used in) Financing Activities $ 28,520 $(49,876) $ (52,079) $ 78,396 $ 2,203

46 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 a 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 CPCN from the PSCW in April 2015. The Town of Holland, Wisconsin filed an appeal of the PSCW’s order, which is currently pending before the Circuit Court of La Crosse County, Wisconsin. While the aim of the appeal is to reverse the approval of the project, and further appeals to higher courts are likely, the Company believes that the PSCW’s order will ultimately be affirmed. There has been no stay of the PSCW’s order and the project is currently under construction. The Cardinal – Hickory Creek project (“Cardinal – Hickory Creek”) is being developed jointly by the Company, ITC Midwest LLC (“ITC Midwest”) which is an operating company of Fortis Inc., 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 a CPCN from the PSCW, similar approval from the Iowa Utilities Board and certain federal approvals. 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 with an estimated cost of $120 million. 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 which was placed in service in August 2016. The Wisconsin portion will include a 345 kV line and a 138 kV line, each approximately 45 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 and the Company has begun construction. 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 $480 million in new transmission construction projects and other capital spending in 2017. During the fourth quarter of 2016 the Company released its new ten-year transmission assessment and expects that it could incur between $3.6 billion and $4.4 billion in capital expenditures over the next ten years. 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.

47 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 approximately 525 miles long, has an estimated cost of $2.6 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 regulatory phase project costs up to a current, budgeted amount of approximately $119 million; however, DATC has the right to terminate its involvement in the project in January 2019, and will have additional opportunities for termination in the future. DATC has received FERC approval to charge negotiated rates consistent with FERC approvals for Zephyr’s previous owners. The area of Path 15 is an 84-mile stretch containing three existing 500 kV transmission lines in central California. Path 15, as used in these financial statements, refers to the third of the three 500 kV transmission lines in the corridor. 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. Path 15 has a FERC-approved 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. 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 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

48 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, debt securities and equity interests. 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, 2016, 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 $2.9 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 $2.4 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 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): 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. Three Months Twelve Months 2016 2015 2016 2015 Maximum Amount of Total Short-term Debt Outstanding (based on daily outstanding balances) $328 $236 $328 $236 Average Amount of Total Short-term Debt Outstanding (based on daily outstanding balances) $269 $201 $246 $151 Weighted-average Interest Rates 0.65% 0.29% 0.55% 0.23%

49 As of December 31, 2016 the Company’s debt was rated as outlined in the table below: On December 9, 2016 Moody’s Investors Service (“Moody’s”) downgraded the Company’s previous A1 issuer rating due to the recent order by FERC which lowered the Company’s base return on equity as discussed above in Pending Regulatory Matters. The Company does not expect its current A2 rating to affect its ability to access the tier one commercial paper markets. 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. On November 4, 2016 Fitch Ratings affirmed the Company’s debt ratings, as shown in the table above, citing the Company’s stable earnings and cash flow profile. 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 has a $400 million, five-year revolving credit facility, 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 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 October 2016, the Company entered into an agreement with a group of investors, through a private placement offering, to issue $150 million of 30-year, unsecured 3.97 percent senior notes to be funded in two tranches. Closing of the transaction and funding of the first $75 million of notes took place on November 15, 2016 with interest due semiannually on January 26 and July 26, beginning on July 26, 2017. The notes will mature on January 26, 2047. Funding of the remaining $75 million of notes occurred on January 26, 2017. These notes will also pay interest semiannually on January 26 and July 26, beginning on July 26, 2017, and will mature on January 26, 2047. Fitch Moody's Standard & Poors Commercial Paper F-1 P-1 A-1 Senior Unsecured/Issuer A+ A2 A+

50 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 $70 million, which it received in quarterly installments throughout 2016. Due to projected increases in construction for 2017, the Company has been authorized by Management Inc.’s board of directors to request up to $155 million of additional capital through voluntary additional capital calls during 2017. 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. Long-term Contractual Obligations and Commercial Commitments The Company’s contractual obligations and other commitments as of December 31, 2016, representing cash obligations that are considered to be firm commitments, are as follows (in thousands): 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. incurred on behalf of the Company 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. Payment Due Within Due After Total 1 Year 2 – 3 Years 4 – 5 Years 5 Years Senior Notes $1,875,000 $ - $350,000 $ - $1,525,000 Interest Payments on Senior Notes 1,455,959 93,615 160,143 150,513 1,051,688 Interconnection Agreements 5,582 - 5,582 - - Operating Leases 58,411 6,448 12,193 11,627 28,143 Total Contractual Obligations and Other Commitments $3,394,952 $100,063 $527,918 $162,140 $2,604,831

51 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 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. A new sister entity, ATC Development LLC (“Development LLC”), was created in 2016 to formally separate the Company's development activities from its operations in its traditional footprint. Those owners of the Company who wish to participate in investments outside the traditional footprint will be able to do so through Development LLC, while the remaining owners will have the opportunity to continue to invest only in the traditional footprint. Effective in 2016, the Company no longer bears the costs of such external development activities; Management Inc. now charges such costs to Development LLC, which is not a subsidiary of either the Company or Management, Inc. The Company incurred $5.6 million in 2015 and $4.7 million in 2014 for such costs which were not recovered through the Company’s rate formula. The Company expects to transfer its interest in DATC, discussed above in Capital Resources and Requirements, to Development LLC in 2017. This transfer requires FERC approval, for which the Company expects to file during the first quarter of 2017. 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. The Company has a number of projects that have met the criteria established under the provisions of the MISO Tariff to have regional cost-sharing rate treatment. 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. 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 the Company continues construction of projects that qualified for regional cost-sharing. However, the Company expects that it will continue to earn its allowed return on its assets under these cost allocation arrangements.

52 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. 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 June 2016, and ongoing substantive audit field work continues. At this time, the Company is unable to predict whether any findings will result from this audit. Legal Matters 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. 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. 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.

53 Regulatory Accounting The Company operates under 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. On September 28, 2016 FERC issued an order in the first complaint proceeding effectively reducing the Company’s overall ROE from 12.2 percent to 10.82 percent. Although FERC has ruled in the first ROE complaint, approximately $82 million of the $140 million 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 2016. The Company will continue to review such estimates as it conducts future depreciation studies and expects the next study to occur in 2021. As of December 31, 2016, the Company had $0.4 million in regulatory assets and $322 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.

54 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.



Commission File Number	Registrant; State of Incorporation; Address; and Telephone Number	IRS Employer Identification No.

001-09057	WEC ENERGY GROUP, INC.	39-1391525
	(A Wisconsin Corporation) 231 West Michigan Street P. O. Box 1331 Milwaukee, WI 53201 414-221-2345



Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, $.01 Par Value		New York Stock Exchange



	Large accelerated filer [X]	Accelerated filer [ ]
	Non-accelerated filer [ ]	Smaller reporting company [ ]



					Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION					1
PART I					3
ITEM 1.	BUSINESS				3
	A.	INTRODUCTION			3
	B.	UTILITY ENERGY OPERATIONS			3
	C.	NON-UTILITY OPERATIONS			16
	D.	REGULATION			17
	E.	ENVIRONMENTAL COMPLIANCE			20
	F.	EMPLOYEES			21
ITEM 1A.	RISK FACTORS				23
ITEM 1B.	UNRESOLVED STAFF COMMENTS				32
ITEM 2.	PROPERTIES				33
ITEM 3.	LEGAL PROCEEDINGS				35
ITEM 4.	MINE SAFETY DISCLOSURES				35
	EXECUTIVE OFFICERS OF THE REGISTRANT				36
PART II					38
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES				38
ITEM 6.	SELECTED FINANCIAL DATA				39
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS				40
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK				67
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA				68
	A.	Reports of Independent Registered Public Accounting Firm			68
	B.	Consolidated Income Statements			70
	C.	Consolidated Statements of Comprehensive Income			71
	D.	Consolidated Balance Sheets			72
	E.	Consolidated Statements of Cash Flows			73
	F.	Consolidated Statements of Equity			74
	G.	Consolidated Statements of Capitalization			75
	H.	Notes to Consolidated Financial Statements			77
		Note 1	Summary of Significant Accounting Policies	77
		Note 2	Acquisitions	84
		Note 3	Dispositions	87
		Note 4	Investment in American Transmission Company	88
		Note 5	Supplemental Cash Flow Information	89
		Note 6	Regulatory Assets and Liabilities	90
		Note 7	Property, Plant, and Equipment	91
		Note 8	Jointly Owned Facilities	91
		Note 9	Asset Retirement Obligations	92
		Note 10	Goodwill	93
		Note 11	Common Equity	93
		Note 12	Preferred Stock	96
		Note 13	Short-Term Debt and Lines of Credit	96
		Note 14	Long-Term Debt and Capital Lease Obligations	97
		Note 15	Income Taxes	100
		Note 16	Guarantees	102
		Note 17	Employee Benefits	102



		Note 18	Commitments and Contingencies	107
		Note 19	Fair Value Measurements	114
		Note 20	Derivative Instruments	115
		Note 21	Variable Interest Entities	116
		Note 22	Regulatory Environment	117
		Note 23	Other Income, Net	121
		Note 24	Segment Information	122
		Note 25	Quarterly Financial Information (Unaudited)	123
		Note 26	New Accounting Pronouncements	124
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE				126
ITEM 9A.	CONTROLS AND PROCEDURES				126
ITEM 9B.	OTHER INFORMATION				126
PART III					127
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE OF THE REGISTRANT				127
ITEM 11.	EXECUTIVE COMPENSATION				127
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS				127
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE				128
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES				128
PART IV					129
ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES				129
ITEM 16.	FORM 10-K SUMMARY				129
SCHEDULE I — CONDENSED PARENT COMPANY FINANCIAL STATEMENTS					130
	A.	Income Statements			130
	B.	Statements of Comprehensive Income			131
	C.	Balance Sheets			132
	D.	Statements of Cash Flows			133
	E.	Notes to Parent Company Financial Statements			134
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS					136
SIGNATURES					137
EXHIBIT INDEX					139



[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Subsidiaries and Affiliates
ATC		American Transmission Company LLC
Bostco		Bostco LLC
DATC		Duke-American Transmission Company
ERGSS		Elm Road Generating Station Supercritical, LLC
Integrys		Integrys Holding, Inc. (previously known as Integrys Energy Group, Inc.)
ITF		Integrys Transportation Fuels, LLC
MERC		Minnesota Energy Resources Corporation
MGU		Michigan Gas Utilities Corporation
NSG		North Shore Gas Company
PDL		WPS Power Development LLC
PELLC		Peoples Energy, LLC
PGL		The Peoples Gas Light and Coke Company
UMERC		Upper Michigan Energy Resources Corporation
WBS		WEC Business Services LLC
WE		Wisconsin Electric Power Company
We Power		W.E. Power, LLC
WECC		Wisconsin Energy Capital Corporation
WG		Wisconsin Gas LLC
Wispark		Wispark LLC
Wisvest		Wisvest LLC
WPS		Wisconsin Public Service Corporation
WRPC		Wisconsin River Power Company

Federal and State Regulatory Agencies
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
ICC		Illinois Commerce Commission
MDEQ		Michigan Department of Environmental Quality
MPSC		Michigan Public Service Commission
MPUC		Minnesota Public Utilities Commission
PSCW		Public Service Commission of Wisconsin
SEC		Securities and Exchange Commission
WDNR		Wisconsin Department of Natural Resources

Accounting Terms
AFUDC		Allowance for Funds Used During Construction
ARO		Asset Retirement Obligation
ASC		Accounting Standards Codification
ASU		Accounting Standards Update
CWIP		Construction Work in Progress
FASB		Financial Accounting Standards Board
GAAP		Generally Accepted Accounting Principles
LIFO		Last-In, First-Out
OPEB		Other Postretirement Employee Benefits



Environmental Terms
Act 141		2005 Wisconsin Act 141
CAA		Clean Air Act
CO ₂		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
GHG		Greenhouse Gas
MATS		Mercury and Air Toxics Standards
NAAQS		National Ambient Air Quality Standards
NOV		Notice of Violation
NOx		Nitrogen Oxide
SO ₂		Sulfur Dioxide

Measurements
Dth		Dekatherm (One Dth equals one million Btu)
MDth		One thousand Dekatherms
MW		Megawatt (One MW equals one million Watts)
MWh		Megawatt-hour

Other Terms and Abbreviations
6.11% Junior Notes		Integrys's 2006 6.11% Junior Subordinated Notes Due 2066
ALJ		Administrative Law Judge
ARRs		Auction Revenue Rights
CNG		Compressed Natural Gas
Compensation Committee		Compensation Committee of the Board of Directors
D.C. Circuit Court of Appeals		United States Court of Appeals for the District of Columbia
ERGS		Elm Road Generating Station
ER 1		Elm Road Generating Station Unit 1
ER 2		Elm Road Generating Station Unit 2
Exchange Act		Securities Exchange Act of 1934, as amended
FTRs		Financial Transmission Rights
GCRM		Gas Cost Recovery Mechanism
LMP		Locational Marginal Price
MCPP		Milwaukee County Power Plant
Merger Agreement		Agreement and Plan of Merger, dated as of June 22, 2014, between Integrys Energy Group, Inc. and Wisconsin Energy Corporation
MISO		Midcontinent Independent System Operator, Inc.
MISO Energy Markets		MISO Energy and Operating Reserves Market
NYMEX		New York Mercantile Exchange
OCPP		Oak Creek Power Plant
OC 5		Oak Creek Power Plant Unit 5
OC 6		Oak Creek Power Plant Unit 6
OC 7		Oak Creek Power Plant Unit 7
OC 8		Oak Creek Power Plant Unit 8
Omnibus Stock Incentive Plan		WEC Energy Group 1993 Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016
PIPP		Presque Isle Power Plant
Point Beach		Point Beach Nuclear Power Plant
PWGS		Port Washington Generating Station
PWGS 1		Port Washington Generating Station Unit 1
PWGS 2		Port Washington Generating Station Unit 2
ROE		Return on Equity
RTO		Regional Transmission Organization



SMP		Gas System Modernization Program
SMRP		System Modernization and Reliability Project
SSR		System Support Resource
Supreme Court		United States Supreme Court
Treasury Grant		Section 1603 Renewable Energy Treasury Grant
VAPP		Valley Power Plant


•	Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints;


•	Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers;


•	The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations;


•	The ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;


•	The timely completion of capital projects within budgets, as well as the recovery of the related costs through rates;


•	Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;


•	Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;


•	Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry, us, or any of our subsidiaries;


•	Restrictions imposed by various financing arrangements and regulatory requirements on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans or advances;


•	The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;


•	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;


•	The direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber security intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;


•	The financial performance of ATC and its corresponding contribution to our earnings, as well as the ability of ATC and DATC to obtain the required approvals for their transmission projects;


•	The investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements;


•	Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees;


•	Advances in technology that result in competitive disadvantages and create the potential for impairment of existing assets;


•	The timing, costs, and anticipated benefits associated with the remaining integration efforts relating to the Integrys acquisition;


•	The risk associated with the values of goodwill and other intangible assets and their possible impairment;


•	Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets, and legislative or regulatory restrictions or caps on non-utility acquisitions, investments or projects, including the State of Wisconsin's public utility holding company law;


•	The timing and outcome of any audits, disputes, and other proceedings related to taxes;


•	The effect of accounting pronouncements issued periodically by standard-setting bodies; and


•	Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.



	Year Ended December 31
(in millions)	2016		2015 ⁽¹⁾		2014
Operating revenues
Residential	$	1,620.7	$	1,398.5	$	1,199.3
Small commercial and industrial ⁽²⁾	1,418.1		1,235.7		1,054.3
Large commercial and industrial ⁽²⁾	949.5		858.8		640.7
Other	29.8		26.9		23.0
Total retail revenues ⁽²⁾	4,018.1		3,519.9		2,917.3
Wholesale	231.2		181.4		131.9
Resale	247.1		248.7		264.1
Steam	27.2		41.0		44.1
Other operating revenues ⁽³⁾	104.5		77.5		87.8
Total operating revenues ⁽²⁾	$	4,628.1	$	4,068.5	$	3,445.2


⁽¹⁾	Includes the operations of WPS beginning July 1, 2015, as a result of the acquisition of Integrys on June 29, 2015.


⁽²⁾	Includes distribution sales for customers who have purchased power from an alternative electric supplier in Michigan.


⁽³⁾	Includes SSR revenue, amounts collected from (refunded to) customers for certain fuel and purchased power costs that exceed a 2% price variance from costs included in rates, and other revenues, partially offset by revenues from the mines that are being deferred until a future rate proceeding. For more information, see the discussion below under the heading "Large Electric Retail Customers."