UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2017March 31, 2018
Commission Registrant; State of Incorporation; IRS Employer
File Number Address; and Telephone Number Identification No.
001-01245 WISCONSIN ELECTRIC POWER COMPANY 39-0476280
  (A Wisconsin Corporation)  
  231 West Michigan Street  
  P.O. Box 2046  
  Milwaukee, WI 53201  
  (414) 221-2345  

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
    
Yes [X]    No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [X]     No [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
 Large accelerated filer [  ] Accelerated filer [  ]
 Non-accelerated filer [X] (Do not check if a smaller reporting company)
   Smaller reporting company [  ]
   Emerging growth company [  ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [ ]    No [X]

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:

Common Stock, $10 Par Value,
33,289,327 shares outstanding at
September 30, 2017March 31, 2018

All of the common stock of Wisconsin Electric Power Company is owned by WEC Energy Group, Inc.
 

Table of Contents

WISCONSIN ELECTRIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2017March 31, 2018
TABLE OF CONTENTS
   Page
 
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
 
1
PART I.
FINANCIAL INFORMATION
 
3
ITEM 1.
FINANCIAL STATEMENTS (UNAUDITED)
 
3
 
Condensed Consolidated Income Statements
 
3
 
Condensed Consolidated Balance Sheets
 
4
 
Condensed Consolidated Statements of Cash Flows
 
5
 
Notes to Condensed Consolidated Financial Statements
 
6
   Page 
 
Note 1
General Information
6
 
 
Note 2
DispositionsDisposition
6
 
 
Note 3
Property, Plant, and EquipmentOperating Revenues
76
 
 
Note 4
Common EquityProperty, Plant, and Equipment
79
 
 
Note 5
Short-Term Debt and Lines of CreditCommon Equity
810
 
 
Note 6
Materials, Supplies,Short-Term Debt and InventoriesLines of Credit
810
 
 
Note 7
Fair Value MeasurementsMaterials, Supplies, and Inventories
810
 
 
Note 8
Derivative InstrumentsIncome Taxes
1011
 
 
Note 9
Employee BenefitsFair Value Measurements
11
 
 
Note 10
Investment in American Transmission CompanyDerivative Instruments
1213
 
 
Note 11
Segment InformationEmployee Benefits
1214
 
 
Note 12
Variable Interest EntitiesSegment Information
1315
 
 
Note 13
Related PartiesVariable Interest Entities
1416
 
 
Note 14
Commitments and ContingenciesRelated Parties
16
 
 
Note 15
Supplemental Cash Flow InformationCommitments and Contingencies
1918
 
 
Note 16
Regulatory EnvironmentSupplemental Cash Flow Information
2021
 
 
Note 17
Regulatory Environment
21
Note 18
New Accounting Pronouncements
2022
 
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
23
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
3632
ITEM 4.
CONTROLS AND PROCEDURES
 
3633
PART II.
OTHER INFORMATION
 
3734
ITEM 1.
LEGAL PROCEEDINGS
 
3734
ITEM 1A.
RISK FACTORS
 
37
ITEM 5.
OTHER INFORMATION
3734
ITEM 6.
EXHIBITS
 
3735
SIGNATURE
  
3836


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GLOSSARY OF TERMS AND ABBREVIATIONS

The abbreviations and terms set forth below are used throughout this report and have the meanings assigned to them below:
Subsidiaries and Affiliates
ATC American Transmission Company LLC
Bluewater Bluewater Natural Gas Holding, LLC
Bostco Bostco LLC
IntegrysIntegrys Holding, Inc.
UMERC Upper Michigan Energy Resources Corporation
WBS WEC Business Services LLC
We Power W.E. Power, LLC
WEC Energy Group WEC Energy Group, Inc.
WG Wisconsin Gas LLC
WPS Wisconsin Public Service Corporation
   
Federal and State Regulatory Agencies
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
MDEQ Michigan Department of Environmental Quality
MPSC Michigan Public Service Commission
PSCW Public Service Commission of Wisconsin
SEC United States Securities and Exchange Commission
WDNR Wisconsin Department of Natural Resources
   
Accounting Terms
AFUDCAllowance for Funds Used During Construction
AIA Affiliated Interest Agreement
ASU Accounting Standards Update
FASB Financial Accounting Standards Board
GAAP United States Generally Accepted Accounting Principles
OPEB Other Postretirement Employee Benefits
   
Environmental Terms
CO2
 Carbon Dioxide
CSAPRCPP Cross-State Air Pollution RuleClean Power Plan
GHG Greenhouse Gas
NAAQS National Ambient Air Quality Standards
NOxNitrogen Oxide
SO2
Sulfur Dioxide
   
Measurements
Dth Dekatherm
MW Megawatt
MWh Megawatt-hour
   
Other Terms and Abbreviations
D.C. Circuit Court of Appeals United States Court of Appeals for the District of Columbia Circuit
ERGS Elm Road Generating Station
Exchange Act Securities Exchange Act of 1934, as amended
FTRs Financial Transmission Rights
MCPPMilwaukee County Power Plant
MISO Midcontinent Independent System Operator, Inc.

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MISO Energy Markets MISO Energy and Operating Reserves Markets
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

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OC 8 Oak Creek Power Plant Unit 8
PIPP Presque Isle Power Plant
PWGS Port Washington Generating Station
ROE Return on Equity
Supreme Court United States Supreme Court
VAPPTax Legislation Valley Power PlantTax Cuts and Jobs Act of 2017


09/30/201703/31/2018 Form 10-QiiiWisconsin Electric Power Company
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In this report, we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. These statements are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. Readers are cautioned not to place undue reliance on these forward-looking statements. Forward-looking statements may be identified by reference to a future period or periods or by the use of terms such as "anticipates," "believes," "could," "estimates," "expects," "forecasts," "goals," "guidance," "intends," "may," "objectives," "plans," "possible," "potential," "projects," "seeks," "should," "targets," "will," or variations of these terms.

Forward-looking statements include, among other things, statements concerning management's expectations and projections regarding earnings, completion of capital projects, sales and customer growth, rate actions and related filings with regulatory authorities, environmental and other regulations and associated compliance costs, legal proceedings, effective tax rate, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.

Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in risk factors as set forth in this report and our Annual Report on Form 10-K for the year ended December 31, 2016,2017, and those identified below:

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;

The impact of federal, state, and local legislative and regulatory changes, including changes in rate-setting policies or procedures, tax law changes, deregulation and restructuring of the electric and/or natural gas utility industries, transmission or distribution system operation, the approval process for new construction, reliability standards, pipeline integrity and safety standards, allocation of energy assistance, and energy efficiency mandates;

The uncertainty surrounding the recently enacted Tax Legislation, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact, if any, on our credit ratings;

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;

Factors affecting the implementation of WEC Energy Group's generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;

Increased pressure on us by investors and other stakeholder groups to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases;

The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;

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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 or us;

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

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;


09/30/2017 Form 10-Q1Wisconsin Electric Power Company
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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,attacks and cyber security intrusions, as well as the threat of terroristsuch incidents, and cyber security intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our utility assets, technology systems, and personal information, and the costs to notify affected persons to mitigate their information security concerns;

The investment performance of WEC Energy Group'sour 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 WEC Energy Group's acquisition of Integrys;Integrys Holding, Inc.;

Potential business strategies to acquire and dispose of assets or businesses, which cannot be assured to be completed timely or within budgets;

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

The ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and continuing to consolidate WEC Energy Group's enterprise systems with those of its other utilities;

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.

We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.


09/30/201703/31/2018 Form 10-Q2Wisconsin Electric Power Company
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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) Three Months Ended Nine Months Ended Three Months Ended
 September 30 September 30 March 31
(in millions) 2017 2016 2017 2016 2018 2017
Operating revenues $943.8
 $1,023.8
 $2,771.2
 $2,876.5
 $941.5
 $972.0
            
Operating expenses            
Cost of sales 336.5
 357.1
 959.0
 977.8
 357.0
 348.6
Other operation and maintenance 332.6
 359.4
 988.1
 1,043.8
 335.6
 326.6
Depreciation and amortization 83.0
 81.9
 247.8
 243.1
 85.3
 82.1
Property and revenue taxes 28.3
 29.0
 85.0
 87.0
 27.2
 28.4
Total operating expenses 780.4
 827.4
 2,279.9
 2,351.7
 805.1
 785.7
            
Operating income 163.4
 196.4
 491.3
 524.8
 136.4
 186.3
            
Equity in earnings of transmission affiliate —
 14.6
 —
 40.7
Other income, net 5.5
 0.5
 14.3
 6.7
Other (expense) income, net (4.2) 3.2
Interest expense 29.3
 29.5
 88.0
 88.0
 29.7
 29.6
Other expense (23.8) (14.4) (73.7) (40.6) (33.9) (26.4)
            
Income before income taxes 139.6
 182.0
 417.6
 484.2
 102.5
 159.9
Income tax expense 49.9
 66.5
 150.2
 178.2
Income tax (benefit) expense (3.6) 57.8
Net income 89.7
 115.5
 267.4
 306.0
 106.1
 102.1
            
Preferred stock dividend requirements 0.3
 0.3
 0.9
 0.9
 0.3
 0.3
Net income attributed to common shareholder $89.4
 $115.2
 $266.5
 $305.1
 $105.8
 $101.8

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.


09/30/201703/31/2018 Form 10-Q3Wisconsin Electric Power Company
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WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(in millions, except share and per share amounts)
 September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
Assets        
Current assets        
Cash and cash equivalents $3.3
 $15.4
 $10.4
 $12.3
Accounts receivable and unbilled revenues, net of reserves of $41.2 and $40.9, respectively 439.5
 503.2
Accounts and notes receivable from related parties 72.7
 58.2
Accounts receivable and unbilled revenues, net of reserves of $43.5 and $39.5, respectively 489.1
 513.8
Accounts receivable from related parties 146.3
 109.1
Materials, supplies, and inventories 294.6
 271.0
 214.7
 250.7
Prepayments 100.1
 138.0
 114.3
 144.3
Other 7.2
 24.6
 7.1
 9.4
Current assets 917.4
 1,010.4
 981.9
 1,039.6
        
Long-term assets        
Property, plant, and equipment, net of accumulated depreciation of $3,701.0 and $3,619.6, respectively 9,907.3
 9,832.3
Property, plant, and equipment, net of accumulated depreciation of $3,798.9 and $3,741.8, respectively 10,086.2
 10,007.7
Regulatory assets 2,126.0
 2,036.6
 2,122.4
 1,984.9
Equity investment in transmission affiliate —
 402.0
Other 84.5
 90.2
 104.9
 89.4
Long-term assets 12,117.8
 12,361.1
 12,313.5
 12,082.0
Total assets $13,035.2
 $13,371.5
 $13,295.4
 $13,121.6
        
Liabilities and Equity        
Current liabilities        
Short-term debt $59.0
 $159.0
 $60.0
 $210.9
Current portion of long-term debt 250.0
 —
 250.0
 250.0
Current portion of capital lease obligations 33.4
 28.5
 44.6
 42.5
Subsidiary note payable to WEC Energy Group —
 18.5
Accounts payable 276.5
 297.9
 217.6
 329.3
Accounts payable to related parties 119.2
 112.9
 249.5
 131.5
Accrued payroll and benefits 44.3
 51.8
 37.5
 53.4
Accrued taxes 30.8
 46.0
 65.7
 58.2
Other 92.4
 100.1
 142.1
 111.8
Current liabilities 905.6
 814.7
 1,067.0
 1,187.6
        
Long-term liabilities        
Long-term debt 2,411.7
 2,661.1
 2,412.8
 2,412.3
Capital lease obligations 2,829.7
 2,756.5
 2,811.5
 2,823.8
Deferred income taxes 2,214.2
 2,333.3
 1,179.7
 1,155.5
Regulatory liabilities 829.7
 853.9
 1,891.1
 1,708.0
Pension and OPEB obligations 154.9
 167.6
 156.9
 143.2
Other 271.5
 260.2
 288.1
 276.9
Long-term liabilities 8,711.7
 9,032.6
 8,740.1
 8,519.7
        
Commitments and contingencies (Note 14) 
 
Commitments and contingencies (Note 15) 
 
        
Common shareholder's equity        
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding 332.9
 332.9
 332.9
 332.9
Additional paid in capital 815.3
 1,020.1
 830.9
 802.7
Retained earnings 2,239.3
 2,140.8
 2,294.1
 2,248.3
Common shareholder's equity 3,387.5
 3,493.8
 3,457.9
 3,383.9
        
Preferred stock 30.4
 30.4
 30.4
 30.4
Total liabilities and equity $13,035.2
 $13,371.5
 $13,295.4
 $13,121.6
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.

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WISCONSIN ELECTRIC POWER COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended Three Months Ended
 September 30 March 31
(in millions) 2017 2016 2018 2017
Operating Activities        
Net income $267.4
 $306.0
 $106.1
 $102.1
Reconciliation to cash provided by operating activities        
Depreciation and amortization 247.8
 249.0
 85.3
 82.1
Deferred income taxes and investment tax credits, net 105.2
 248.6
 (15.4) 20.7
Contributions and payments related to pension and OPEB plans (5.9) (6.4) (2.1) (3.3)
Equity income in transmission affiliate, net of distributions —
 (13.0)
Proceeds from (payments for) liabilities transferred from (to) WBS 0.9
 (116.1)
(Payments for) proceeds from liabilities transferred (to) from WBS (1.4) 0.9
Change in –        
Accounts receivable and unbilled revenues 49.0
 13.1
 (12.5) 42.1
Materials, supplies, and inventories (23.6) 37.5
 36.0
 19.4
Prepaid taxes 31.2
 (75.2) 24.2
 25.1
Other current assets 5.3
 16.1
 6.0
 3.2
Accounts payable (14.6) (12.2) 12.3
 (63.5)
Accrued taxes (15.2) 0.8
 10.9
 (15.9)
Amounts refundable to customers 15.7
 10.0
Other current liabilities (15.6) (5.8) (1.8) (21.0)
Other, net (37.6) (27.8) 106.6
 7.9
Net cash provided by operating activities 594.3
 614.6
 369.9
 209.8
        
Investing Activities        
Capital expenditures (405.7) (322.5) (141.9) (105.5)
Capital contributions to transmission affiliate —
 (10.4)
Proceeds from the sale of assets 22.9
 31.7
 0.5
 12.9
Proceeds from assets transferred to WBS —
 13.1
Short-term notes receivable from related parties, net (3.1) —
Payment for assets received from WBS (48.9) —
Other, net 3.8
 2.9
 1.7
 0.4
Net cash used in investing activities (382.1) (285.2) (188.6) (92.2)
        
Financing Activities        
Change in short-term debt (100.0) (39.5) (150.9) (124.0)
Repayment of subsidiary note to parent (18.5) (2.5) —
 (12.8)
Equity contribution from parent 75.0
 —
 28.0
 75.0
Payments of dividends to parent (180.0) (320.0)
Payments of preferred stock dividends (0.9) (0.9)
Other, net 0.1
 18.6
Payment of dividends to parent (60.0) (60.0)
Payment of preferred stock dividends (0.3) (0.3)
Net cash used in financing activities (224.3) (344.3) (183.2) (122.1)
        
Net change in cash and cash equivalents (12.1) (14.9) (1.9) (4.5)
Cash and cash equivalents at beginning of period 15.4
 27.1
 12.3
 15.4
Cash and cash equivalents at end of period $3.3
 $12.2
 $10.4
 $10.9

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.


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WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 2017March 31, 2018

NOTE 1—GENERAL INFORMATION

As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary, Bostco.

Prior to January 1, 2017, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 13, Related Parties, for more information on the transfer.

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. UMERC holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan. The existing contract between the Tilden Mining Company and us will remain in place until a new power generation solution for the region is commercially operational. See Note 13, Related Parties, and Note 16, Regulatory Environment, for more information on UMERC.

We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2016.2017. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2017,March 31, 2018, are not necessarily indicative of expected results for 20172018 due to seasonal variations and other factors.

In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.

NOTE 2—DISPOSITIONSDISPOSITION

Utility Segment

Sale of Milwaukee County Power Plant

In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ($6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

Other Segment

–Sale of Bostco Real Estate Holdings

In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.

NOTE 3—OPERATING REVENUES

Adoption of ASU 2014-09, Revenues from Contracts with Customers

On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, revenues are recognized when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services.

We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods.

We adopted the following practical expedients and optional exemptions for the implementation of this standard:

We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes.
When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts.
We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period.
We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less.
We elected to apply this standard only to contracts that are not completed as of the date of initial application.

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Disaggregation of Operating Revenues

The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. There are no revenues associated with our other segment. Comparable amounts have not been presented for the three months ended March 31, 2017, due to our adoption of this standard under the modified retrospective method.
(in millions) Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2018  
Electric utility $779.6
Natural gas utility 160.8
Total revenues from contracts with customers 940.4
Other operating revenues 1.1
Total operating revenues $941.5

Revenues from Contracts with Customers
Electric Utility Operating Revenues

The following table disaggregates electric utility operating revenues into customer class for the current period:
(in millions) Electric Utility Operating Revenues
Three Months Ended March 31, 2018  
Residential $281.4
Small commercial and industrial 237.7
Large commercial and industrial 148.9
Other 5.4
Total retail revenues 673.4
Wholesale 28.5
Resale 63.7
Steam 9.7
Other utility revenues 4.3
Total electric utility operating revenues $779.6

Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled and consists of both the sale and the delivery of the electric commodity. The rates, charges, terms, and conditions of service for sales to these customers are included in tariffs that have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component using an output method based on the quantity of electricity delivered each month.

Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. The rates, charges, terms and conditions of service for sales to wholesale customers are included in tariffs that have been approved by the FERC. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally

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recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.

We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.

For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual current year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.

Natural Gas Utility Operating Revenues

The following table disaggregates natural gas utility operating revenues into customer class for the current period:
(in millions) Natural Gas Utility Operations
Three Months Ended March 31, 2018  
Residential $114.7
Commercial and industrial 55.6
Total retail revenues 170.3
Transport 4.4
Other utility revenues * (13.9)
Total natural gas utility operating revenues $160.8

*Includes amounts (refunded to) collected from customers for purchased gas adjustment costs.

We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. Certain of our customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.

The transaction price of the performance obligations is valued using rates in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component using an output method based on natural gas delivered each month.

Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.


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Other Operating Revenues

Other operating revenues consist primarily of the following:
(in millions) Three Months Ended March 31, 2018
Late payment charges $2.8
Leases 0.8
Alternative revenues * (2.5)
Total other operating revenues $1.1

*Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed below.

Alternative Revenues

Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.

Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.

NOTE 3—4—PROPERTY, PLANT, AND EQUIPMENT

Utility Segment Plant to be Retired

We have evaluated future plans for our older and less efficient fossil fuel generating units and have announced the retirement of the plants identified below. The net book value of these plants was classified as plant to be retired within property, plant, and equipment on our balance sheet at March 31, 2018. In addition, severance expense in the amount of $25.8 million was recorded within the utility segment in 2017 related to these announced plant retirements.

Pleasant Prairie Power Plant

As a result of a MISO ruling in December 2017, the Pleasant Prairie power plant was retired effective April 10, 2018. Retirement of the Pleasant Prairie power plant was considered probable at March 31, 2018. The net book value of this generating unit was $674.1 million at March 31, 2018, and was classified as plant to be retired within property, plant, and equipment on our balance sheet. This unit is included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 15, Commitments and Contingencies, for more information regarding the new natural gas-fired generation.

Presque Isle Power Plant

In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MWsMW of natural gas-fired generation in the Upper Peninsula of Michigan. These new units are expected to begin commercial operation by mid-2019. Upon receiving thisthe MPSC's approval, early retirement of the PIPP generating units became probable. The newAs a result of a MISO ruling received in April 2018, the PIPP units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPPmust be retired no later than 2020.May 31, 2019. The net book value of these units was $203.0$188.7 million at September 30, 2017.March 31, 2018, and was classified as plant to be retired within property, plant, and equipment on our balance sheet. These units are currently included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. The net book value of these assets was transferred from plant in service to plant to be retired. See Note 16, Regulatory Environment,15, Commitments and Contingencies, for more information regarding UMERC’s application.information.

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NOTE 4—5—COMMON EQUITY

Stock-Based Compensation

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the nine months ended September 30, 2017:
(in millions) Retained Earnings
Balance at December 31, 2016 $2,140.8
Net income 267.4
Common stock dividends (180.0)
Preferred stock dividends (0.9)
Cumulative effect of adoption of ASU 2016-09 11.9
Other 0.1
Balance at September 30, 2017 $2,239.3

ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.

As we did not record any excess tax benefits in 2017, adoption of this ASU had no impact on our financial statements other than the cumulative-effect adjustment discussed above.

Restrictions

Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 9,8, Common Equity, in our 20162017 Annual Report on Form 10-K for additional information on these and other restrictions.

We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.


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NOTE 5—6—SHORT-TERM DEBT AND LINES OF CREDIT

The following table shows our short-term borrowings and their corresponding weighted-average interest rates:
(in millions, except percentages) September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
Commercial paper        
Amount outstanding $59.0
 $159.0
 $60.0
 $210.9
Weighted-average interest rate on amounts outstanding 1.19% 0.87% 2.05% 1.81%

Our average amount of commercial paper borrowings based on daily outstanding balances during the ninethree months ended September 30, 2017,March 31, 2018, was $37.7$96.2 million with a weighted-average interest rate during the period of 1.04%1.86%.

In April 2017, our consolidated subsidiary, Bostco, paid off a note payable to our parent, WEC Energy Group.

The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility:
(in millions) Maturity September 30, 2017 Maturity March 31, 2018
Revolving credit facility * December 2020 $500.0
Revolving credit facility October 2022 $500.0
    
Less:    
    
Letters of credit issued inside credit facility $26.2
 $1.2
Commercial paper outstanding   59.0
   60.0
  
Available capacity under existing agreement   $414.8
   $438.8

*In October 2017, we extended the maturity of our credit facility to October 2022.

NOTE 6—7—MATERIALS, SUPPLIES, AND INVENTORIES

Our inventory consisted of:
(in millions) September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
Materials and supplies $155.8
 $148.1
 $136.2
 $140.7
Fossil fuel 93.5
 91.1
 73.9
 74.8
Natural gas in storage 45.3
 31.8
 4.6
 35.2
Total $294.6
 $271.0
 $214.7
 $250.7

Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.


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NOTE 8—INCOME TAXES

The provision for income taxes for the quarter ended March 31, 2018, differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:
  Amount Effective Tax Rate
Statutory federal income tax $21.5
 21.0 %
State income taxes net of federal tax benefit 6.7
 6.5 %
Federal tax reform (5.4) (5.2)%
Tax repairs (25.5) (24.9)%
Other (0.9) (0.9)%
Total income tax benefit $(3.6) (3.5)%

The effective tax rate of (3.5)% for the first quarter of 2018 differs from the United States statutory federal income tax rate of 21% primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement and the impact of the Tax Legislation, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required us to remeasure our deferred income taxes and begin to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see Federal tax reform line above). See Note 17, Regulatory Environment, for more information on the Tax Legislation and the Wisconsin rate settlement.

On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and subject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting.

NOTE 7—9—FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.


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Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.

When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these

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inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs.

We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.

The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
 September 30, 2017 March 31, 2018
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Derivative assets                
Natural gas contracts $0.9
 $0.1
 $—
 $1.0
 $0.4
 $—
 $—
 $0.4
Petroleum products contracts 0.8
 —
 —
 0.8
 0.5
 —
 —
 0.5
FTRs —
 —
 3.7
 3.7
 —
 —
 0.8
 0.8
Coal contracts —
 0.9
 —
 0.9
 —
 0.7
 —
 0.7
Total derivative assets $1.7
 $1.0
 $3.7
 $6.4
 $0.9
 $0.7
 $0.8
 $2.4
                
Derivative liabilities                
Natural gas contracts $0.3
 $0.1
 $—
 $0.4
 $0.5
 $0.1
 $—
 $0.6
Coal contracts —
 1.2
—
—
 1.2
Total derivative liabilities $0.3
 $1.3
 $—
 $1.6

 December 31, 2016 December 31, 2017
(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Derivative assets                
Natural gas contracts $6.0
 $0.8
 $—
 $6.8
 $0.5
 $0.1
 $—
 $0.6
Petroleum products contracts 0.2
 —
 —
 0.2
 0.9
 —
 —
 0.9
FTRs —
 —
 3.1
 3.1
 —
 —
 2.4
 2.4
Coal contracts —
 1.9
 —
 1.9
 —
 0.7
 —
 0.7
Total derivative assets $6.2
 $2.7
 $3.1
 $12.0
 $1.4
 $0.8
 $2.4
 $4.6
                
Derivative liabilities       
       
Natural gas contracts $0.1
 $—
 $—
 $0.1
 $2.0
 $0.1
 $—
 $2.1
Petroleum products contracts 0.1
 —
 —
 0.1
Coal contracts —
 0.5
 —
 0.5
 —
 0.3
 —
 0.3
Total derivative liabilities $0.2
 $0.5
 $—
 $0.7
 $2.0
 $0.4
 $—
 $2.4

The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.


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The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 2017 2016 2018 2017
Balance at the beginning of the period $6.0
 $7.5
 $3.1
 $1.6
 $2.4
 $3.1
Purchases —
 —
 6.9
 8.1
Settlements (2.3) (2.1) (6.3) (4.3) (1.6) (2.0)
Balance at the end of the period $3.7
 $5.4
 $3.7
 $5.4
 $0.8
 $1.1

Fair Value of Financial Instruments

The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
 September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
(in millions) Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value
Preferred stock $30.4
 $29.6
 $30.4
 $28.8
 $30.4
 $29.1
 $30.4
 $30.5
Long-term debt, including current portion 2,661.7
 2,946.7
 2,661.1
 2,923.4
 2,662.8
 2,903.7
 2,662.3
 2,976.3

Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, short-term notes receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based on the quoted market prices for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.

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NOTE 8—10—DERIVATIVE INSTRUMENTS

We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW.

We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities.

The following table shows our derivative assets and derivative liabilities:
 September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities
Other current                
Natural gas contracts $0.8
 $0.4
 $6.3
 $0.1
 $0.4
 $0.3
 $0.6
 $1.9
Petroleum products contracts 0.8
 —
 0.2
 0.1
 0.5
 —
 0.9
 —
FTRs 3.7
 —
 3.1
 —
 0.8
 —
 2.4
 —
Coal contracts 0.6
 0.7
 1.5
 0.5
 0.7
 —
 0.6
 0.1
Total other current * $5.9
 $1.1
 $11.1
 $0.7
 $2.4
 $0.3
 $4.5
 $2.0
                
Other long-term                
Natural gas contracts $0.2
 $—
 $0.5
 $—
 $—
 $0.3
 $—
 $0.2
Coal contracts 0.3
 0.5
 0.4
 —
 —
 —
 0.1
 0.2
Total other long-term * 0.5
 0.5
 0.9
 —
 —
 0.3
 0.1
 0.4
Total $6.4
 $1.6
 $12.0
 $0.7
 $2.4
 $0.6
 $4.6
 $2.4

*On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.

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Realized gains (losses) on derivative instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:
  Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
(in millions) Volumes Gains (Losses) Volumes Gains (Losses)
Natural gas contracts 4.6 Dth $(0.5) 6.8 Dth $(0.5)
Petroleum products contracts 4.1 gallons (0.5) 3.3 gallons (0.4)
FTRs 6.9 MWh 2.4
 7.7 MWh 4.5
Total   $1.4
   $3.6



Nine Months Ended September 30, 2017
Nine Months Ended September 30, 2016
Three Months Ended March 31, 2018
Three Months Ended March 31, 2017
(in millions)
Volumes
Gains (Losses)
Volumes
Gains (Losses)
Volumes
Gains (Losses)
Volumes
Gains (Losses)
Natural gas contracts
17.8 Dth
$0.2

27.0 Dth
$(12.5)
11.7 Dth
$(1.8)
8.2 Dth
$0.5
Petroleum products contracts
13.9 gallons
(1.4)
7.5 gallons
(1.9)
1.4 gallons
0.4

4.9 gallons
(0.5)
FTRs
21.2 MWh
6.9

18.6 MWh
6.8

5.8 MWh
0.8

7.0 MWh
2.5
Total
 
$5.7

 
$(7.6)
 
$(0.6)
 
$2.5

On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30,March 31, 2018 and December 31, 2017, we had posted cash collateral of $1.3$3.8 million in our margin accounts, and at December 31, 2016, we had received cash collateral of $3.4$4.9 million, respectively, in our margin accounts. OnThese amounts were recorded on our balance sheets cash collateral provided to others is reflected in other current assets and cash collateral received is reflected in other current liabilities.assets.

The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
 September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017 
(in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities 
Gross amount recognized on the balance sheet $6.4
 $1.6
 $12.0
 $0.7
 $2.4
 $0.6
 $4.6
 $2.4
 
Gross amount not offset on the balance sheet (0.4) (0.4) (3.6)*(0.2) (0.4) (0.5)
(1 
) 
(1.3)
(2.0)
(2 
) 
Net amount $6.0
 $1.2
 $8.4
 $0.5
 $2.0
 $0.1
 $3.3
 $0.4
 

*03/31/2018 Form 10-QIncludes cash collateral received of $3.4 million.13Wisconsin Electric Power Company
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(1) Includes cash collateral posted of $0.1 million.

(2) Includes cash collateral posted of $0.7 million.

NOTE 9—11—EMPLOYEE BENEFITS

The following tables show the components of net periodic pension and OPEB costs for our benefit plans:
 Pension Costs Pension Costs
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 2017 2016 2018 2017
Service cost $3.0
 $2.7
 $9.1
 $7.9
 $3.3
 $3.0
Interest cost 11.8
 12.4
 35.3
 37.3
 10.6
 11.9
Expected return on plan assets (19.2) (19.5) (57.5) (58.3) (19.0) (19.2)
Loss on plan settlement 0.7
 —
 3.5
 —
Amortization of prior service cost 0.3
 0.4
 0.9
 1.2
 0.2
 0.3
Amortization of net actuarial loss 8.8
 8.1
 26.5
 24.3
 9.4
 8.8
Net periodic benefit cost $5.4
 $4.1
 $17.8
 $12.4
 $4.5
 $4.8

  OPEB Costs
  Three Months Ended March 31
(in millions) 2018 2017
Service cost $1.8
 $1.9
Interest cost 2.8
 3.1
Expected return on plan assets (3.9) (3.6)
Amortization of prior service credit (0.6) (0.3)
Amortization of net actuarial loss —
 0.3
Net periodic benefit cost $0.1
 $1.4

During the three months ended March 31, 2018, we made contributions and payments of $1.5 million related to our pension plans and $0.6 million related to our OPEB plans. We expect to make contributions and payments of $2.4 million related to our pension plans and $4.3 million related to our OPEB plans during the remainder of 2018, dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation.

Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for the quarters ended March 31, 2018 and 2017, we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service cost components in other income, net. For the quarter ended March 31, 2018, the non-service cost components of net benefit cost were in a net credit position, in the amount of $(1.7) million. For the quarter ended March 31, 2017, the non-service cost components of net benefit cost were in a net debit position, in the amount of $1.2 million, and were reclassified from other operation and maintenance to other income, net, on our income statements.


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  OPEB Costs
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2017 2016 2017 2016
Service cost $1.8
 $1.9
 $5.2
 $5.5
Interest cost 3.0
 3.3
 9.2
 9.9
Expected return on plan assets (3.6) (3.5) (10.8) (10.5)
Amortization of prior service credit (0.2) (0.3) (0.8) (0.8)
Amortization of net actuarial loss —
 0.2
 —
 0.7
Net periodic benefit cost $1.0
 $1.6
 $2.8
 $4.8

DuringAs required by ASU 2017-07, our income statements for the nine monthsyears ended September 30,December 31, 2017, we made payments of $3.9 million related2016, and 2015 were retroactively restated from what was previously presented in our 2017 Annual Report on Form 10-K. The impacts to our pension plans and $2.0 million to our OPEB plans. We expect to make paymentsincome statements from adoption of $1.3 million related to our pension plans and $2.5 million related to our OPEB plans during the remainder of 2017, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.

NOTE 10—INVESTMENT IN AMERICAN TRANSMISSION COMPANY

At December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. On January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not resultthis standard are reflected in the recognition of a gain or loss. The following table shows changes to our investment in ATC:below.
  Three Months Ended September 30 Nine Months Ended September 30
(in millions) 2016 2017 2016
Balance at beginning of period $394.8
 $402.0
 $382.2
Less: Transfer of ownership interest —
 402.0
 —
Add: Earnings from equity method investment 14.6
 —
 40.7
Add: Capital contributions 5.8
 —
 10.4
Less: Distributions 9.7
 —
 27.7
Less: Other —
 —
 0.1
Balance at end of period $405.5
 $—
 $405.5
  Year Ended December 31, 2017 Year Ended December 31, 2016 Year Ended December 31, 2015
(in millions) 
Form
10-K Income Statement
 Impact of ASU 2017-07 Income Statement After Adoption 
Form
10-K Income Statement
 Impact of ASU 2017-07 Income Statement After Adoption 
Form
10-K Income Statement
 Impact of ASU 2017-07 Income Statement After Adoption
Operating expenses                  
Other operation and maintenance $1,358.5
 $(6.5) $1,352.0
 $1,430.2
 $(4.7) $1,425.5
 $1,384.9
 $(4.3) $1,380.6
                   
Other expense                  
Other income, net 19.7
 (6.5) 13.2
 9.1
 (4.7) 4.4
 11.2
 (4.3) 6.9

See Note 13, Related Parties,In addition, under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for more information on transactions with ATC.capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, will be presented as regulatory assets or liabilities rather than property, plant, and equipment.

NOTE 11—12—SEGMENT INFORMATION

We use operating income to measure segment profitability and to allocate resources to our businesses. At September 30, 2017,March 31, 2018, we reported two segments, which are described below.

Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin, and to one customer in the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 13, Related Parties, and Note 16, Regulatory Environment, for additional information. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.

Our other segment includes Bostco, our non-utility subsidiary that developedwas originally formed to develop and investedinvest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 2, Dispositions,Disposition, for more information. Prior

The following tables show summarized financial information for the three months ended March 31, 2018 and 2017, related to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 10, Investment in American Transmission Company, for more information.reportable segments:
(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Three Months Ended March 31, 2018      
Operating revenues $941.5
 $—
 $941.5
Other operation and maintenance 335.6
 —
 335.6
Depreciation and amortization 85.3
 —
 85.3
Operating income 136.4
 —
 136.4
Interest expense 29.7
 —
 29.7


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The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30, 2017 and 2016:
(in millions) Utility Other Wisconsin Electric Power Company Consolidated Utility Other Wisconsin Electric Power Company Consolidated
Three Months Ended September 30, 2017      
Three Months Ended March 31, 2017      
Operating revenues $943.8
 $—
 $943.8
 $972.0
 $—
 $972.0
Other operation and maintenance 332.6
 —
 332.6
Other operation and maintenance * 326.6
 —
 326.6
Depreciation and amortization 83.0
 —
 83.0
 82.1
 —
 82.1
Operating income 163.4
 —
 163.4
Operating income * 186.3
 —
 186.3
Interest expense 29.3
 —
 29.3
 29.3
 0.3
 29.6

(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Three Months Ended September 30, 2016      
Operating revenues $1,023.8
 $—
 $1,023.8
Other operation and maintenance 359.4
 —
 359.4
Depreciation and amortization 81.9
 —
 81.9
Operating income 196.4
 —
 196.4
Equity in earnings of transmission affiliate —
 14.6
 14.6
Interest expense 29.3
 0.2
 29.5

(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Nine Months Ended September 30, 2017      
Operating revenues $2,771.2
 $—
 $2,771.2
Other operation and maintenance 988.1
 —
 988.1
Depreciation and amortization 247.8
 —
 247.8
Operating income 491.3
 —
 491.3
Interest expense 87.7
 0.3
 88.0

(in millions) Utility Other Wisconsin Electric Power Company Consolidated
Nine Months Ended September 30, 2016      
Operating revenues $2,876.5
 $—
 $2,876.5
Other operation and maintenance 1,043.8
 —
 1,043.8
Depreciation and amortization 243.1
 —
 243.1
Operating income 524.8
 —
 524.8
Equity in earnings of transmission affiliate —
 40.7
 40.7
Interest expense 87.3
 0.7
 88.0
*Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 11, Employee Benefits, for more information on this new standard.

NOTE 12—13—VARIABLE INTEREST ENTITIES

The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.

We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.


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American Transmission Company

As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 10, Investment in American Transmission Company, for more information.

Purchased Power Agreement

We have a purchased power agreement that represents a variable interest. This agreement is for 236 MWsMW of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately fivefour years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement.

We have approximately $74.9$67.7 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the ninethree months ended September 30,March 31, 2018 and 2017 and 2016 were $13.5$4.7 million and $40.5$4.5 million, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.

NOTE 13—14—RELATED PARTIES

We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities.

We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group.

A new AIA took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. All of the applicable state commissions approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater, which is discussed in more detail below.

Bostco, our consolidated subsidiary, had a note payable to our parent company, WEC Energy Group. The balance of this note payable was $18.5 million at December 31, 2016. This note payable was paid off in the first half of 2017.

In connection with the sale of Bostco’s remaining real estate holdings, Wispark LLC, a subsidiary of WEC Energy Group, provided $7.0 million of financing to the buyer and established a corresponding note receivable. Bostco had a $7.0 million related party receivable from Wispark LLC that was paid in April 2017. See Note 2, Dispositions, for more information on the real estate sale.

On January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016, to another subsidiary of WEC Energy Group. In addition, we transferred $195.1$186.8 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss.

We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs.

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Our balance sheets included the following receivables and payables related to transactions entered into with ATC:
(in millions) September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
Accounts receivable        
Services provided to ATC $1.0
 $1.1
 $1.3
 $0.8
Accounts payable        
Services received from ATC 20.2
 20.0
 16.4
 22.2

The following table shows activity associated with our related party transactions:
 Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 2017 2016 2018 2017
Lease agreements  
  
  
  
  
  
Lease payments to We Power (1)
 $104.3
 $91.4
 $315.4
 $308.8
 $92.2
 $104.4
Construction work in progress billed to We Power 5.9
 10.8
 31.1
 28.5
 3.8
 16.3
Transactions with WBS (2)
            
Billings to WBS (3)
 60.2
 46.2
 177.2
 156.0
 5.9
 56.5
Billings from WBS (4)
 49.4
 40.4
 152.1
 266.0
 108.1
 49.8
Transactions with WPS (2)
            
Natural gas purchases from WPS 0.8
 1.0
 1.3
 1.7
Billings to WPS 6.4
 4.1
 14.1
 7.0
 3.0
 2.5
Billings from WPS 1.4
 1.4
 3.6
 1.9
 3.2
 1.1
Transactions with WG    
        
Natural gas purchases from WG 1.4
 1.3
 4.0
 4.0
 1.3
 1.3
Services received from WG 6.0
 6.0
 17.3
 16.5
Services provided to WG 16.3
 15.5
 48.2
 45.4
Transactions with UMERC (5)
        
Billings to WG 13.9
 15.8
Billings from WG 4.7
 5.5
Transactions with UMERC    
Electric sales to UMERC 9.0
 —
 23.1
 —
 8.1
 7.7
Billings to UMERC (2)
 18.7
 —
 52.6
 —
 4.2
 4.7
Billings from UMERC (2)
 14.6
 —
 45.1
 —
Transactions with Bluewater (6)
        
Transactions with Bluewater (5)
    
Storage service fees 1.4
 —
 1.4
 —
 1.3
 —
Transactions with ATC            
Charges to ATC for services and construction 2.9
 2.1
 8.1
 6.6
 3.0
 2.8
Charges from ATC for network transmission services 60.4
 61.7
 181.1
 188.3
 58.0
 60.3
Refund from ATC per FERC ROE order —
 —
 (19.4) —
 —
 19.4

(1) 
We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2.

(2) 
Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs.

(3) 
Includes $0.9 million for the transfer of certain benefit-related liabilities from WBS for the ninethree months ended September 30,March 31, 2017. There were no transfers of assets to WBS orbenefit-related liabilities transferred from WBS for the three months ended September 30, 2017. For the nine months ended September 30, 2016, includes $13.1 million for the transfer of certain assets to WBS. There were no transfers of assets to WBS during the three months ended September 30, 2016.March 31, 2018.

(4) 
Includes $9.1$1.4 million and $116.1 million, respectively, for the transfer of certain benefit-related liabilities to WBS for the three and nine months ended September 30, 2016.March 31, 2018. Also includes $48.9 million for the transfer of certain software assets from WBS for the three months ended March 31, 2018. There were no benefit-related liabilities transferred to WBS or assets transferred from WBS for the three and nine months ended September 30,March 31, 2017.

(5) 
UMERC became operational effective January 1, 2017. See below for more information.

(6)
TheWEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information.


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Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets, (includingincluding the related deferred income tax liabilities)liabilities, transferred to UMERC from us in 2017 was $60.0$61.1 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under

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common control, and therefore, did not result in the recognition of a gain or loss. The Tilden Mining Company will remain a customer of ours until UMERC's proposed generation solution for the Upper Peninsula of Michigan begins commercial operation.

UMERC obtainscurrently meets its energy and capacity requirements to supply its customersmarket obligations through power purchase agreements with us and WPS.

Parent Company'sWEC Energy Group's Acquisition of Natural Gas Storage Facilities in Michigan

On June 30, 2017, our parent companyWEC Energy Group completed the acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that will provide for a portion of the current storage needs for our natural gas utility operations. In September 2017, we finalized a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage.storage, which was then approved by the PSCW in November 2017. See Note 16,17, Regulatory Environment, for more information.

NOTE 14—15—COMMITMENTS AND CONTINGENCIES

We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.

Unconditional Purchase Obligations

We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of September 30, 2017,March 31, 2018, were $10,094.8$9,890.7 million.

Environmental Matters

Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx,sulfur dioxide, nitrogen oxide, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.

Air Quality

Cross-State Air Pollution Rule

In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing the CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.

The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015 and issued the final rule in September 2016. We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.

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Sulfur Dioxide National Ambient Air Quality Standards

The EPA issued a revised 1-Hour SO2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. We believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant costs to comply with this regulation.

8-Hour Ozone National Ambient Air Quality Standards

The eastern portion of Kenosha County is currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has updated the 2008 ozone NAAQS attainment plan for Kenosha County and submitted it to the EPA for approval. The plan concluded that Wisconsin will not need to implement any new regulatory measures or programs. The area is forecasted to meet the standard by the 2018 compliance date due to emission control measures already in place. We expect the EPA to issue a decision later in 2017.

After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment forIn December 2017, the EPA informed Wisconsin of its intended area designations of all the counties along Wisconsin's Lake Michigan shoreline, except Brown, Kewaunee, Marinette, and Oconto Counties, as either partial or full nonattainment. Waukesha and Washington counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017,were also included due to the EPA released preliminary interstate ozone transport modeling forcounties being in the 2015 ozone NAAQS.Milwaukee combined statistical area. The EPA is currently scheduled to finalizeissued final nonattainment area designations lateron May 1, 2018. The final designations differ significantly from the intended nonattainment areas EPA proposed late in December 2017. The following counties were designated as partial nonattainment: Manitowoc, Sheboygan, Northern Milwaukee/Ozaukee shoreline, and Kenosha. Racine, Waukesha, and Washington counties will be designated attainment/unclassifiable. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.

Although we are still in the process of reviewing and determining potential impacts resulting from this rule, we believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply.

Climate Change

In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, (CPP), a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and, to the extent that further appellate review is sought, at the Supreme Court. The

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D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.

The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39%, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction.

In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. The EPA announced that it has initiated this review. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In October 2017, the EPA issued a notice of proposed rulemaking to repeal the CPP. TheIn December 2017, the EPA is expected subsequently to issueissued an

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advanced notice of proposed rulemaking that willto solicit input on whether it is appropriate to replace the CPP. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.plan to implement the CPP.

Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. OurWEC Energy Group's plan, which includes us, is to work with ourits industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. We have implemented and continue to evaluate numerous options in order to meet ourWEC Energy Group's CO2 reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. As a result of WEC Energy Group's generation reshaping plan, we expect to retire 1,547 MW of coal generation by 2020, including Pleasant Prairie power plant (now retired) and PIPP. See Note 4, Property, Plant, and Equipment, for more information. In addition, we are evaluating our goal, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius.

We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2017, we reported aggregated CO2 equivalent emissions of 23.5 million metric tonnes to the EPA. The level of CO2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.

We are also required to report CO2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2017, we reported aggregated CO2 equivalent emissions of 3.7 million metric tonnes to the EPA.

Water Quality

Clean Water Act Cooling Water Intake Structure Rule

In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.

Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next

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several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. 

BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP.Valley Power Plant. Due to our plans to retire PIPP and Pleasant Prairie power plant (now retired), we do not believe that BTA determinations for EM will be made in future permit reissuancesnecessary for these units. Although we currently believe that existing technologies at PWGS Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8. 

During 2017 and 2018, we will continue to complete studies and evaluate options to address8 satisfy the EM BTA requirements, atBTA determinations to address EM reduction requirements will not be made until discharge permits are renewed for these plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towersunits. Until that meet EM BTA requirements),time, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements atfor these units. During 2018, we will continue to evaluate options to address the facilities. EM BTA requirements for these units.

We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022)2023), the EM BTA requirements will be waived. We expect to submit this certification in November 2017.the letter identifying the last operating date for PIPP to the MDEQ during 2018, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance.

We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.

Steam Electric Effluent Limitation Guidelines

The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. Various petitions challenging the rule were consolidated and are pending in the United States Fifth Circuit Court of Appeals. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule ("Postponement Rule") to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurization wastewater requirements. This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.

After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule.

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However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.

The final rule would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek siteOCPP and Pleasant Prairie facilities.ERGS. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7 and OC 8, and the Pleasant Prairie units.8. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55approximately $50 million would be required to $75 million fordesign and install these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retireThis estimate reflects the plant. See the UMERC discussionplanned retirements of certain of our generation plants as a result of WEC Energy Group's generation reshaping plan discussed in Note 16, Regulatory Environment, regarding the potential retirement of PIPP.Climate Change above.

Land Quality

Manufactured Gas Plant Remediation

We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.


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The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.

We have established the following regulatory assets and reserves related to manufactured gas plant sites:
(in millions) September 30, 2017 December 31, 2016 March 31, 2018 December 31, 2017
Regulatory assets $27.7
 $29.9
 $30.1
 $30.4
Reserves for future remediation 16.5
 19.0
Reserves for future remediation * 18.5
 18.5

*Recorded within other long-term liabilities on our balance sheets.

Enforcement and Litigation Matters

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.

NOTE 15—16—SUPPLEMENTAL CASH FLOW INFORMATION
 Nine Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 2018 2017
Cash (paid) for interest, net of amount capitalized $(62.1) $(62.9) $(4.7) $(4.8)
Cash (paid) for income taxes, net (60.7) (0.1) —
 (52.1)
Significant noncash transactions:        
Accounts payable related to construction costs 8.5
 5.3
 7.3
 11.0
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2)
 415.4
 —
 —
 415.4
Transfer of net assets to UMERC (1)
 60.0
 —
 —
 68.9
Accounts receivable related to the sale of Bostco real estate holdings (3)
 —
 7.0

(1)
See Note 13,14, Related Parties, for more information on these transactions.

(2)
The amount transferred includesincluded a $13.4 million receivable for distributions approved and recorded in December 2016.

(3)
See Note 2, Disposition, for more information on this transaction.

NOTE 17—REGULATORY ENVIRONMENT

Tax Cuts and Jobs Act of 2017

We deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,065 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes in December 2017. The current 2018 tax benefit related to the Tax Legislation, which reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018, is also being deferred for return to ratepayers.

In April 2018, the PSCW issued a preliminary determination regarding the benefits associated with the Tax Legislation. For our electric utility operations, the PSCW indicated that 80% of the current 2018 and 2019 tax benefits should be used to reduce our transmission regulatory asset, with the remaining 20% returned to our electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of current 2018 and 2019 tax benefits should be returned to our natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting for our electric operations should be used to reduce our transmission regulatory asset, while the timing and method of returning the remaining net tax benefit associated with the revaluation of deferred

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NOTE 16—REGULATORY ENVIRONMENTtaxes was not addressed and will be determined in a future rate proceeding. Until we receive the final written order, the specific terms are subject to change.
We currently serve one retail electric customer in Michigan, and have reached a settlement with that customer. That settlement was filed with the MPSC in March 2018 and addresses all base rate impacts of the Tax Legislation.

2018 and 2019 Rates

During April 2017, we, along with WG and WPS, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which will freeze base rates through 2019 for electric and natural gas customers. Based on the PSCW order, our authorized ROE remains at 10.2%, and our current capital cost structure will remain unchanged through 2019. Various intervenors havehad filed requests for rehearing.rehearing, all of which have been denied.

In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. In addition,We will flow through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at our December 31, 2017 levels. While we will deferwould typically follow the revenue requirement impactsnormalization accounting method and utilize the tax benefits of anythe deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal corporate tax reform enactedcode does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in 2017 or during the base rate freeze period.no change to net income.

Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers.

Natural Gas Storage Facilities in Michigan

In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provideare providing a portion of the current storage needs for our natural gas distribution service customers.operations. As a result of this agreement, we, along with WG and WPS, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreementsagreement and interstate natural gas transportation contracts related to the storage facilities. We also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. During June 2017, theThe PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we finalized the long-term service agreement for the natural gas storage, and filed withwhich was approved by the PSCW for approval of this agreement. We expect to receive approval of the service agreement in the fourth quarter ofNovember 2017. See Note 13,14, Related Parties, for more information.

Formation of Upper Michigan Energy Resources Corporation

In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan.

In August 2016, WEC Energy Group entered into an agreement with the Tilden Mining Company (Tilden), under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years. The agreement also calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation located in the Upper Peninsula of Michigan.

In October 2017, the MPSC approved both the agreement with Tilden and UMERC's application for a certificate of necessity to begin construction of the proposed generation. The new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation.

NOTE 17—18—NEW ACCOUNTING PRONOUNCEMENTS

Revenue Recognition

In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.

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We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.

We are finalizing our review of our contracts with customers and the related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of our operating revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition.

Recognition and Measurement of Financial Instruments

In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded, if applicable, with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Leases

In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements.

Financial Instruments Credit Losses

In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.

Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We do not believe the adoption of this guidance will have a significant impact on our financial statements.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost

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component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. While we have not fully determined the impacts of the adoption of this standard, we expect that as a result of the application of accounting principles for rate regulated entities, a similar amount of net benefit cost (including non-service components), will be recognized in our financial statements consistent with the current ratemaking treatment. As a result, we believe the impacts of adoption will be limited to changes in classification of non-service costs in the income statements.


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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CORPORATE DEVELOPMENTS

The following discussion should be read in conjunction with the accompanying financial statements and related notes and our Annual Report on Form 10-K for the year ended December 31, 2016.2017.

Introduction

We are a wholly owned subsidiary of WEC Energy Group, and derive revenues primarily from the distribution and sale of electricity and natural gas to retail customers in Wisconsin. We have combined common functions with WG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See Note 11,12, Segment Information, for more information on our reportable business segments.

Effective January 1,In March 2017, our customers and electric distribution assetswe sold the remaining real estate holdings of Bostco located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility subsidiary of WEC Energy Group.downtown Milwaukee, Wisconsin, which included retail, office, and residential space. See Note 13, Related Parties, for more information.

Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 13, Related Parties,2, Disposition, for more information.

Corporate Strategy

Our goal is to continue to createbuild and sustain long-term value for our customers and WEC Energy Group's shareholders by focusing on the following:fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety.

Reshaping Our Generation Fleet

WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. WEC Energy Group expects to retire approximately 1,800 MW of coal generation by 2020 across its electric utilities, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. Our 1,190 MW Pleasant Prairie power plant was retired in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 4, Property, Plant, and Equipment, for information related to the Pleasant Prairie power plant retirement and the planned retirement of PIPP as part of WEC Energy Group's plan.

Reliability

We have made significant reliability relatedreliability-related investments in recent years, and plan to continue making significant capital investments to strengthenstrengthening and modernize the reliability ofmodernizing our generation fleet and distribution networks.networks to further improve reliability. Our investments, coupled with our commitment to operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility in the United States in 2017 and, for the seventh year in a row, as the most reliable utility in the Midwest.

Operating Efficiency

We continually look for ways to optimize the operating efficiency of our company. For example, we received approval fromare making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the PSCW to make changes at ERGS to enable the facility to burn coal from the Powder River Basin located in the western United States. The coal plant was originally designed to burn coal mined from the eastern United States. This project is creating flexibilitymanual effort for disconnects and has enabled the plant to operate at lower costs, placing it in a better position to be called upon in the MISO Energy Markets, resulting in lower fuel costs for our customers.reconnects and enhances outage management capabilities.

WEC Energy Group continues to focus on integrating and improving business processes and consolidating its IT infrastructure across all of its companies. We expect these integration efforts to continue to drive operational efficiency.efficiency and to put us in position to effectively support plans for future growth.


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Financial Discipline

A strong adherence to financial discipline is essential to earning our authorized ROE and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.

We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plant,plants, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Dispositions,Disposition, for information on the sale of the MCPP and Bostco's remaining real estate holdings.

WEC Energy Group has developed and is executing a strategy to reshape its generation portfolio in order to reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. Subject to final review, WEC Energy Group plans on retiring approximately 1,800 MWs of coal generation by 2020 across its electric utilities. See Note 3, Property, Plant, and Equipment, for

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information related to the planned retirement of our PIPP generation units. We, along with WEC Energy Group, are also reviewing retirements of additional coal-fueled generation units.

Exceptional Customer Care

Our approach is driven by an intense focus on delivering exceptional customer care every day. We strive to provide the best value for our customers by embracing constructive change, demonstrating personal responsibility for results, leveraging our capabilities and expertise, and using creative solutions to meet or exceed our customers’ expectations.

One example of how we obtain feedback from our customers is through our "We Care" calls, where our employees contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance in order to improve customer satisfaction.

Safety

We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. WEC Energy Group's corporate safety program provides a forum for addressing employee concerns, training employees and contractors on current safety standards, and recognizing those who demonstrate a safety focus.

RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2017MARCH 31, 2018

Consolidated Earnings

Our consolidated earnings for the three months ended September 30, 2017first quarter of 2018 were $89.4$105.8 million, compared to $115.2$101.8 million for the same quarter in 2016.2017. See below for additional information on the $25.8$4.0 million decreaseincrease in consolidated earnings.

Non-GAAP Financial Measures

The discussion below addresses the operating income contribution of our utility segment and includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the three months ended September 30,first quarter of 2018 and 2017 and 2016, was $163.4$136.4 million and $196.4$186.3 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.


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Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the thirdfirst quarter of 20172018 with the thirdsame quarter of 2016,2017, including favorable or better, "B", and unfavorable or worse, "W", variances. Effective January 1, 2017, we transferred our electric customers located in the Upper Peninsula of Michigan to UMERC. See Note 13, Related Parties, for more information.
 Three Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 B (W) 2018 2017 B (W)
Electric revenues $899.3
 $980.4
 $(81.1) $780.3
 $821.8
 $(41.5)
Fuel and purchased power 315.5
 337.2
 21.7
 252.1
 252.7
 0.6
Total electric margins 583.8
 643.2
 (59.4) 528.2
 569.1
 (40.9)
            
Natural gas revenues 44.5
 43.4
 1.1
 161.2
 150.2
 11.0
Cost of natural gas sold 21.0
 19.9
 (1.1) 104.9
 95.9
 (9.0)
Total natural gas margins 23.5
 23.5
 —
 56.3
 54.3
 2.0
            
Total electric and natural gas margins 607.3
 666.7
 (59.4) 584.5
 623.4
 (38.9)
            
Other operation and maintenance 332.6
 359.4
 26.8
 335.6
 326.6
 (9.0)
Depreciation and amortization 83.0
 81.9
 (1.1) 85.3
 82.1
 (3.2)
Property and revenue taxes 28.3
 29.0
 0.7
 27.2
 28.4
 1.2
Operating income $163.4
 $196.4
 $(33.0) $136.4
 $186.3
 $(49.9)

The following table shows a breakdown of other operation and maintenance:
 Three Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 B (W) 2018 2017 B (W)
Operation and maintenance not included in line items below $111.2
 $123.6
 $12.4
 $102.0
 $107.6
 $5.6
We Power (1)
 129.6
 129.6
 —
 127.2
 127.6
 0.4
Transmission (2)
 67.5
 68.3
 0.8
 66.1
 67.0
 0.9
Regulatory amortizations and other pass through expenses (3)
 24.3
 24.1
 (0.2)
Earnings sharing mechanisms —
 13.8
 13.8
Transmission expense related to the flow through of tax repairs (3)
 14.7
 —
 (14.7)
Regulatory amortizations and other pass through expenses (4)
 25.6
 24.4
 (1.2)
Total other operation and maintenance $332.6
 $359.4
 $26.8
 $335.6
 $326.6
 $(9.0)

(1) 
Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During the three months ended September 30,March 31, 2018 and 2017, and 2016, $129.0$110.5 million and $120.0 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by us, with the difference in costs billed or incurred and expenses recognized, deducted from the regulatory asset.

(2)
The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the three months ended September 30, 2017 and 2016, $86.8 million and $88.0 million, respectively, of costs were billed to us by transmission providers.

(3)
Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.


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The following tables provide information on sales volumes by customer class and weather statistics:
  Three Months Ended September 30
  
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W)
Customer Class    
Residential 2,151.9
 2,446.0
 (294.1)
Small commercial and industrial 2,308.9
 2,505.0
 (196.1)
Large commercial and industrial 2,199.7
 2,402.7
 (203.0)
Other 33.2
 30.2
 3.0
Total retail 6,693.7
 7,383.9
 (690.2)
Wholesale 363.6
 289.4
 74.2
Resale 2,190.4
 2,434.4
 (244.0)
Total sales in MWh 9,247.7
 10,107.7
 (860.0)

  Three Months Ended September 30
  
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W)
Customer Class    
Residential 19.6
 17.6
 2.0
Commercial and industrial 13.4
 12.7
 0.7
Total retail 33.0
 30.3
 2.7
Transport 67.1
 68.5
 (1.4)
Total sales in therms 100.1
 98.8
 1.3

  Three Months Ended September 30
  Degree Days
Weather * 2017 2016 B(W)
Heating (118 normal) 72
 27
 45
Cooling (543 normal) 542
 781
 (239)

*Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

Electric Utility Margins

Electric utility margins decreased $59.4 million during the third quarter of 2017, compared with the same quarter in 2016. The significant factors impacting the lower electric utility margins were:

A $42.4 million decrease related to lower sales volumes during the third quarter of 2017, primarily driven by cooler summer weather. As measured by cooling degree days, the quarter ended September 30, 2017, was 30.6% cooler than the same quarter in 2016. Lower overall retail use per customer and the transfer of customers and their related sales to UMERC also contributed to the decrease.

A $25.3 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

These decreases in margins were partially offset by $9.2 million of lower capacity payments to a counterparty during the third quarter of 2017.


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Operating Income

Operating income at the utility segment decreased $33.0 million during the third quarter of 2017, compared with the same quarter in 2016. This decrease was driven by the $59.4 million decrease in margins discussed above, partially offset by $26.4 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

We experienced lower overall operating expenses related to synergy savings resulting from WEC Energy Group's acquisition of Integrys. The significant factors impacting the decrease in operating expenses, which were due in part to synergy savings, were:

A $13.8 million expense recorded in the third quarter of 2016 related to the earnings sharing mechanism in place. See Note 16, Regulatory Environment, for more information

An $11.6 million decrease in operation and maintenance expenses at our plants, primarily related to lower costs at the PIPP and the timing of planned outages and maintenance.

Equity in Earnings of Transmission Affiliate
  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Equity in earnings of transmission affiliate $—
 $14.6
 $(14.6)

At December 31, 2016, we owned approximately 23% of ATC. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 13, Related Parties, for more information.

Consolidated Other Income, Net
  Three Months Ended September 30
(in millions) 2017 2016 B (W)
AFUDC – Equity $0.7
 $0.7
 $—
Other 4.8
 (0.2) 5.0
Other income, net $5.5
 $0.5
 $5.0

The increase was due, in part, to expenses we incurred in the third quarter of 2016 related to the disposition of certain non-utility real estate assets.

Consolidated Interest Expense
  Three Months Ended September 30
(in millions) 2017 2016 B (W)
Interest expense $29.3
 $29.5
 $0.2

Income Tax Expense
  Three Months Ended September 30
  2017 2016 B (W)
Effective tax rate 35.7% 36.5% 0.8%

Our effective tax rate decreased by 0.8% when compared with the third quarter of 2016, primarily due to increased renewable energy credits related to wind and favorable compensation expense in the third quarter of 2017.


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NINE MONTHS ENDED SEPTEMBER 30, 2017

Consolidated Earnings

Our consolidated earnings for the nine months ended September 30, 2017 were $266.5 million, compared to $305.1 million for the same period in 2016. See below for additional information on the $38.6 million decrease in consolidated earnings.

Non-GAAP Financial Measures

The discussion below addresses the operating income contribution of our utility segment and includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.

We believe that electric and natural gas margins provide a more meaningful basis for evaluating utility operations than operating revenues since the majority of prudently incurred fuel and purchased power costs, as well as prudently incurred natural gas costs, are passed through to customers in current rates. As a result, management uses electric and natural gas margins internally when assessing the operating performance of our utility segment as these measures exclude the majority of revenue fluctuations caused by changes in these expenses. Similarly, the presentation of electric and natural gas margins herein is intended to provide supplemental information for investors regarding our operating performance.

Our electric margins and natural gas margins may not be comparable to similar measures presented by other companies. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of our utility segment operating performance. Our utility segment operating income for the nine months ended September 30, 2017 and 2016, was $491.3 million and $524.8 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.

Utility Segment Contribution to Operating Income

The following table compares our utility segment's contribution to operating income for the nine months ended September 30, 2017, with the same period in 2016, including favorable or better, "B", and unfavorable or worse, "W", variances. Effective January 1, 2017, we transferred our electric customers located in the Upper Peninsula of Michigan to UMERC. See Note 13, Related Parties, for more information.
  Nine Months Ended September��30
(in millions) 2017 2016 B (W)
Electric revenues $2,514.7
 $2,631.1
 $(116.4)
Fuel and purchased power 809.4
 841.9
 32.5
Total electric margins 1,705.3
 1,789.2
 (83.9)
       
Natural gas revenues 256.5
 245.4
 11.1
Cost of natural gas sold 149.6
 135.9
 (13.7)
Total natural gas margins 106.9
 109.5
 (2.6)
       
Total electric and natural gas margins 1,812.2
 1,898.7
 (86.5)
       
Other operation and maintenance 988.1
 1,043.8
 55.7
Depreciation and amortization 247.8
 243.1
 (4.7)
Property and revenue taxes 85.0
 87.0
 2.0
Operating income $491.3
 $524.8
 $(33.5)


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The following table shows a breakdown of other operation and maintenance:
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
Operation and maintenance not included in line items below $329.9
 $366.6
 $36.7
We Power (1)
 384.3
 385.5
 1.2
Transmission (2)
 202.0
 205.8
 3.8
Regulatory amortizations and other pass through expenses (3)
 71.9
 72.1
 0.2
Earnings sharing mechanisms —
 13.8
 13.8
Total other operation and maintenance $988.1
 $1,043.8
 $55.7

(1)
Represents costs associated with the We Power generation units, including operating and maintenance costs incurred, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During the nine months ended September 30, 2017 and 2016, $394.0 million and $383.5$124.7 million, respectively, of both lease and operating and maintenance costs were billed to or incurred by us, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.

(2) 
The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the ninethree months ended September 30,March 31, 2018 and 2017, and 2016, $221.4$56.3 million and $256.2$55.0 million, respectively, of costs were billed to us by transmission providers.

(3)
Represents additional transmission expense associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at our December 31, 2017 levels. See Note 17, Regulatory Environment, for more information.

(4) 
Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income.

The following tables provide information on sales volumes by customer class and weather statistics:
  Nine Months Ended September 30
  
MWh (in thousands)
Electric Sales Volumes 2017 2016 B (W)
Customer Class    
Residential 5,774.7
 6,206.7
 (432.0)
Small commercial and industrial 6,610.7
 6,915.4
 (304.7)
Large commercial and industrial 6,277.4
 7,156.1
 (878.7)
Other 105.4
 103.9
 1.5
Total retail 18,768.2
 20,382.1
 (1,613.9)
Wholesale 1,207.9
 803.0
 404.9
Resale 5,387.4
 6,290.6
 (903.2)
Total sales in MWh 25,363.5
 27,475.7
 (2,112.2)

  Nine Months Ended September 30
  
Therms (in millions)
Natural Gas Sales Volumes 2017 2016 B (W)
Customer Class    
Residential 221.9
 233.5
 (11.6)
Commercial and industrial 126.9
 128.2
 (1.3)
Total retail 348.8
 361.7
 (12.9)
Transport 227.6
 239.6
 (12.0)
Total sales in therms 576.4
 601.3
 (24.9)

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The following tables provide information on delivered sales volumes by customer class and weather statistics:
  Three Months Ended March 31
  
MWh (in thousands)
Electric Sales Volumes 2018 2017 B (W)
Customer Class    
Residential 1,911.9
 1,825.0
 86.9
Small commercial and industrial 2,181.6
 2,197.6
 (16.0)
Large commercial and industrial 2,025.8
 1,985.6
 40.2
Other 37.6
 38.6
 (1.0)
Total retail 6,156.9
 6,046.8
 110.1
Wholesale 425.9
 447.1
 (21.2)
Resale 2,191.4
 2,132.4
 59.0
Total sales in MWh 8,774.2
 8,626.3
 147.9

  Nine Months Ended September 30
  Degree Days
Weather * 2017 2016 B(W)
Heating (4,333 normal) 3,669
 4,058
 (389)
Cooling (704 normal) 745
 977
 (232)
  Three Months Ended March 31
  
Therms (in millions)
Natural Gas Sales Volumes 2018 2017 B (W)
Customer Class    
Residential 177.4
 155.6
 21.8
Commercial and industrial 96.1
 85.8
 10.3
Total retail 273.5
 241.4
 32.1
Transport 95.1
 89.0
 6.1
Total sales in therms 368.6
 330.4
 38.2

  Three Months Ended March 31
  Degree Days
Weather * 2018 2017 B(W)
Heating (3,255 normal) 3,225
 2,849
 376

*Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.

Electric Utility Margins

Electric utility margins decreased $83.9$40.9 million during the nine months ended September 30, 2017,first quarter of 2018, compared with the same periodquarter in 2016.2017. The significant factors impacting the lower electric utility margins were:

A $67.2 million decrease related to lower sales volumes during the nine months ended September 30, 2017, primarily driven by unfavorable weather, lower overall retail use per customer, and the transfer of customers and their related sales to UMERC. Cooler summer weather, warmer winter weather, and an additional day of sales during the same period in 2016 due to leap year contributed to the decrease. As measured by cooling degree days, the nine months ended September 30, 2017, was 23.7% cooler than the same period in 2016. As measured by heating degree days, the nine months ended September 30, 2017, was 9.6% warmer than the same period in 2016.

A $28.2 million period-over-period negative impact from collections of fuel and purchased power costs compared with costs approved in rates. Under the Wisconsin fuel rules, our electric margins are impacted by under or over-collections of certain fuel and purchased power costs that are less than a 2% price variance from the costs included in rates, and the remaining variance that exceeds the 2% variance is deferred.

A $4.5 million decrease in steam margins driven by the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information.
A $4.0$25.1 million decrease in margins related to amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the iron ore mines locatedTax Legislation signed into law in December 2017. See Note 8, Income Taxes, and Note 17, Regulatory Environment, for more information.

A $20.4 million decrease in margins related to a settlement agreement with the PSCW to flow through the tax benefit of our repair-related deferred tax liabilities through reductions in certain regulatory assets, as discussed in the Upper Peninsula of Michigan. In November 2016, one oftable above and in Note 17, Regulatory Environment.

A $1.9 million decrease in wholesale margins driven by reduced capacity rates reflecting the iron ore mines closed. With the return of the mines as retail customersTax Legislation signed into law in 2015, we continue to defer the majority of the margin from those sales and intend to apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding.December 2017.

These decreases in margins were partially offset by $27.2a $9.8 million of lower capacity paymentsincrease related to a counterpartyhigher retail sales volumes during the nine months ended September 30, 2017.

Natural Gas Utility Margins

Natural gas utility margins decreased $2.6 million during the nine months ended September 30, 2017, compared with the same period in 2016. The most significant factor impacting the lower natural gas utility margins were lower sales volumes,first quarter of 2018, primarily driven by warmercolder winter weather. An additional dayAs measured by heating degree days, the first quarter of sales during 2016 due to leap year also contributed to the decrease.

Operating Income

Operating income at the utility segment decreased $33.5 million during the nine months ended September 30, 2017, compared with2018 was 13.2% colder than the same periodquarter in 2016. The decrease was driven by the $86.5 million decrease in margins discussed above, partially offset by $53.0 million of lower operating expenses.

We experienced lower overall operating expenses related to synergy savings resulting from WEC Energy Group's acquisition of Integrys. The significant factors impacting the decrease in operating expenses, which were due in part to synergy savings, were:

A $31.3 million decrease in operation and maintenance expenses at our plants, primarily related to the seasonal operation of the Pleasant Prairie Power Plant, lower costs at the PIPP, the timing of planned outages and maintenance, and the sale of the MCPP in April 2016. See Note 2, Dispositions, for more information on the sale of the MCPP.
2017.

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Natural Gas Utility Margins
A $13.8
Natural gas utility margins increased $2.0 million expense recorded induring the thirdfirst quarter of 20162018, compared with the same quarter in 2017. The most significant factor impacting the higher natural gas utility margins was a $5.2 million increase in sales volumes, primarily driven by colder winter weather, higher overall retail use per customer, and customer growth. This increase in margins was partially offset by $3.1 million of amounts expected to be returned to customers through refunds, bill credits, or reductions in other regulatory assets, driven by the Tax Legislation signed into law in December 2017.

Operating Income

Operating income at the utility segment decreased $49.9 million during the first quarter of 2018, compared with the same quarter in 2017. This decrease was driven by the $38.9 million decrease in net margins discussed above and $11.0 million of higher operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenues taxes).

The significant factors impacting the increase in operating expenses during the first quarter of 2018, compared with the same quarter in 2017, were:

A $14.7 million increase in transmission expenses related to the earnings sharing mechanism in place. See Note 16, Regulatory Environment, for more information.

A $10.7 million decrease in electric and natural gas distribution expenses, due in part to the transferflow through of electric customers and their related sales to UMERC.

A $5.2 million decrease in transmission expenses, We Power costs, and regulatory amortizations and other pass-through expenses includedtax repairs, as discussed in the table above.

A $3.2 million increase in depreciation and amortization driven by an overall increase in utility plant in service and the implementation of an enterprise resource planning system in January 2018.

These decreasesincreases in operating expenses were partially offset by a $10.9by:

A $4.6 million gaindecrease in benefit costs.

A $3.9 million decrease in expenses at our plants, primarily related to the winding down of operations in anticipation of expected plant retirements. This resulted in lower maintenance and labor costs during the first quarter of 2018. See Note 4, Property, Plant, and Equipment, for more information on the sale of the MCPP, which was sold in April 2016. See Note 2, Dispositions, for more information on the sale of the MCPP.plant retirements.

Equity in Earnings of Transmission Affiliate
  Nine Months Ended September 30
(in millions) 2017 2016 B (W)
Equity in earnings of transmission affiliate $—
 $40.7
 $(40.7)

At December 31, 2016, we owned approximately 23% of ATC. On January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 13, Related Parties, for more information.

Consolidated Other (Expense) Income, Net
 Nine Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 B (W) 2018 2017 B (W)
AFUDC – Equity $2.1
 $3.6
 $(1.5)
Allowance for funds used during construction – Equity $1.0
 $0.7
 $0.3
Other 12.2
 3.1
 9.1
 (5.2) 2.5
 (7.7)
Other income, net $14.3
 $6.7
 $7.6
Other (expense) income, net $(4.2) $3.2
 $(7.4)

Other Income,income, net increased by $7.6decreased $7.4 million when compared to the nine months ended September 30, 2016. The increase was driven by gains on property sales duringfirst quarter of 2017, due in part to the nine months ended September 30, 2017, compared withtiming of the same period in 2016, in addition to expenses we incurred in 2016recognition of returns related to certain regulatory assets in the dispositionfirst quarter of certain non-utility real estate assets. These increases were partially offset by lower AFUDC during 2017.2018.

Consolidated Interest Expense
 Nine Months Ended September 30 Three Months Ended March 31
(in millions) 2017 2016 B (W) 2018 2017 B (W)
Interest expense $88.0
 $88.0
 $—
 $29.7
 $29.6
 $(0.1)

Consolidated Income Tax (Benefit) Expense
  Nine Months Ended September 30
  2017 2016 B (W)
Effective tax rate 36.0% 36.8% 0.8%
  Three Months Ended March 31
  2018 2017 B (W)
Effective tax rate (3.5)% 36.1% 39.6%

Our effective tax rate decreased by 0.8%39.6% when compared with the nine months ended September 30, 2016,first quarter of 2017, primarily due to increased renewable energy credits related to wind and favorable compensation expense during the nine months ended September 30, 2017. We expect our 2017 annuala 25% effective tax rate benefit from the flow through of tax repairs in connection with the Wisconsin rate settlement. Also contributing to be between 36.0% and 37.0%.

the decrease in

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the effective tax rate was the impact of the Tax Legislation. See Note 8, Income Taxes, and Note 17, Regulatory Environment, for more information.

We expect our 2018 annual effective tax rate to be between (11)% and (10)%, which includes an estimated 32% effective tax rate benefit due to the flow through of tax repairs.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

The following table summarizes our cash flows during the ninethree months ended September 30:March 31:
(in millions) 2017 2016 
Change in 2017
Over 2016
 2018 2017 
Change in 2018
Over 2017
Cash provided by (used in):            
Operating activities $594.3
 $614.6
 $(20.3) $369.9
 $209.8
 $160.1
Investing activities (382.1) (285.2) (96.9) (188.6) (92.2) (96.4)
Financing activities (224.3) (344.3) 120.0
 (183.2) (122.1) (61.1)

Operating Activities

Net cash provided by operating activities decreased $20.3increased $160.1 million during the nine months ended September 30, 2017,first quarter of 2018, compared with the same period in 2016,2017, driven by:

A $114.2 million decrease in cash related to lower overall collections from customers during the nine months ended September 30, 2017, compared with the same period in 2016. Collections from customers decreased primarily because of unfavorable weather and the loss of sales from the transfer of customers to UMERC in 2017.

A $60.6 million decrease in cash related to an increase in cash paid for income taxes during the nine months ended September 30, 2017, compared with the same period in 2016. This decrease in cash was primarily the result of the extension of bonus depreciation in December 2015.

A $34.4 million decrease in cash resulting from higher payments for natural gas and fuel and purchased power, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 14.1% during the nine months ended September 30, 2017, compared with the same period in 2016.

A $27.7 million decrease in distributions received during the nine months ended September 30, 2017, compared with the same period in 2016, due to the transfer of our investment in ATC to another subsidiary of WEC Energy Group. See Note 10, Investment in American Transmission Company, for more information.

These decreases in net cash provided by operating activities were partially offset by:

A $116.1 million increase in cash related to a cash payment to WBS during the nine months ended September 30, 2016for transfers of certain benefit-related liabilities to WBS. We did not make a similar payment in 2017.

A $111.7$155.4 million increase in cash from lower payments for operating and maintenance costs. Duringcosts primarily due to lower payments of accounts payable to related parties for the first quarter of nine months ended September 30, 20172018, compared with the same period in 2017. In addition, our lease payments to We Power as well as payments for employee benefits and plant operating and maintenance costs also decreased.

A $52.1 million net increase in cash related to transmission, electric generation costs, and electric anda decrease in cash paid for income taxes during the first quarter of 2018, compared with the same period in 2017. This increase in cash was primarily the result of statutory changes in the due date for certain tax payments.

These increases in net cash provided by operating activities were partially offset by a $56.8 million decrease in cash resulting from higher payments in the first quarter of 2018 for natural gas distribution costs decreased.
we purchased at the end of 2017 and during the first quarter of 2018 to meet the requirements of our customers during the colder winter weather.

Investing Activities

Net cash used in investing activities increased $96.9$96.4 million during the nine months ended September 30, 2017,first quarter of 2018, compared with the same period in 2016,2017, driven by:

AnA payment of $83.248.9 million to WBS during the first quarter of 2018, related to transfers of an enterprise resource planning system and other software from WBS. There were no similar transfers in 2017.

A $36.4 million increase in cash paid for capital expenditures during the first quarter of nine months ended September 30, 20172018, compared with the same period in 2016,2017, which is discussed in more detail below.

Cash ofA $13.112.4 million received during the nine months ended September 30, 2016, related to transfers of certain software to WBS.

An $8.8 million decrease in the proceeds received from the sale of assets and businesses during the first quarter of nine months ended September 30, 20172018, compared with the same period in 2016.2017. See Note 2, Dispositions,Disposition, for more information.


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These increases in net cash used in investing activities were partially offset by $10.4 million of capital contributions paid to our transmission affiliate during the nine months ended September 30, 2016. We did not make similar contributions in 2017 due to the transfer of our investment in ATC.

Capital Expenditures

Capital expenditures for the ninethree months ended September 30March 31 were as follows:
(in millions) 2017 2016 
Change in 2017
Over 2016
 2018 2017 
Change in 2018
Over 2017
Capital expenditures $405.7
 $322.5
 $83.2
 $141.9
 $105.5
 $36.4

The increase in cash paid for capital expenditures during the nine months ended September 30, 2017first quarter of 2018 was driven by upgrades of our natural gas and electric distribution systems, including meter and main replacement projects, and various projects at the OCPP.software projects.

See Capital Resources and Requirements -– Capital Requirements – Significant Capital Projects for more information.

Financing Activities

Net cash used in financing activities decreased $120.0increased $61.1 million during the nine months ended September 30, 2017,first quarter of 2018, compared with the same period in 2016,2017, primarily driven by:

A $140.047.0 million decrease in dividends paid to our parent. We paid special dividends to our parent to balance our capital structure during the nine months ended September 30, 2016.

A $75.0 millionequity contributioncontributions received from our parent to balance our capital structure during the first quarter of nine months ended September 30, 2018, compared with the same period in 2017.

These decreases in net cash used in financing activities were partially offset by:

A $60.526.9 million increase in net repayments of commercial paper during the first quarter of nine months ended September 30, 2018, compared with the same period in 2017.

A $16.0 million increaseThese increases in net repaymentscash used in financing activities were partially offset by a $12.8 million net repayment of our subsidiary's note to our parent during the nine months ended September 30, 2017.
first quarter of 2017.

For more information on our short-term financing activities, see Note 5,6, Short-Term Debt and Lines of Credit.

Capital Resources and Requirements

Capital Resources

Liquidity

We anticipate meeting our capital requirements for our existing operations through internally generated funds and short-term borrowings, supplemented by the issuance of intermediate or long-term debt securities, depending on market conditions and other factors, and equity contributions from our parent.

We currently have access to the capital markets and have been able to generate funds internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement, access to capital markets, and internally generated cash.

We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 5,6, Short-Term Debt and Lines of Credit, for more information on our credit facility.

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As of September 30, 2017,March 31, 2018, we were the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million. In August 2009, we terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of September 30, 2017,March 31, 2018, the repurchased bonds were still outstanding but are not reported in our long-term debt since they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties.


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Working Capital

Although not the case asAs of September 30, 2017,March 31, 2018, our current liabilities sometimes exceedexceeded our current assets. If this were to occur, we wouldassets by $85.1 million. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.debt.

Credit Rating Risk

We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings and/or Baa3 at Moody's Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.

In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.

In July 2017, Moody's downgraded our senior unsecured rating to A2 from A1. Moody's affirmed our P-1 commercial paper rating. We do not believe this change in rating will have a material impact on our ability to access capital markets.

Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.

If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue future debt securities and certain other types of financing and could increase borrowing costs under our credit facility.

Capital Requirements

Significant Capital Projects

We have several capital projects that will require significant capital expenditures over the next three years and beyond. All projected capital requirements are subject to periodic review and may vary significantly from estimates, depending on a number of factors. These factors include environmental requirements, regulatory restraints and requirements, changes in tax laws and regulations,impacts from the Tax Legislation, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:
(in millions)    
2017 $576.7
2018 592.6
 $598.5
2019 541.2
 552.5
2020 807.5
Total $1,710.5
 $1,958.5

The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI) program. AMI is an integrated system of smart meters, communication networks and data management systems that enable two-way communication between utilities and customers.

Additionally, as part of our commitment to invest in zero-carbon generation, we plan to invest in utility scale solar. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.

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Off-Balance Sheet Arrangements

We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or

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expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 5,6, Short-Term Debt and Lines of Credit, and Note 12,13, Variable Interest Entities.

Contractual Obligations

For additional information about our commitments, see Contractual Obligations in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Requirements in our 20162017 Annual Report on Form 10-K.

FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES

The following is a discussion of certain factors that may affect our results of operations, liquidity, and capital resources. The following discussion should be read together with the information in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources in our 20162017 Annual Report on Form 10-K, which provides a more complete discussion of factors affecting us, including market risks and other significant risks, industry restructuring, environmental matters, critical accounting policies and estimates, and other matters.

Environmental Matters

See Note 14,15, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.

Other Matters

Tax Cuts and Jobs Act of 2017

In December 2017, the Tax Legislation was signed into law. The FERC, PSCW, and MPSC are working with us to return any tax savings from the Tax Legislation to customers. If the amounts our regulators order us to return to customers exceed the actual tax savings realized or if our regulators require the tax savings to be applied in a manner other than we had expected, it could have a material adverse effect on our financial condition, results of operations, and cash flow. See Note 17, Regulatory Environment, for more information.


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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes related to market risk from the disclosures presented in our Annual Report on Form 10-K for the year ended December 31, 2016.2017. In addition to the Form 10-K disclosures, see Note 7,9, Fair Value Measurements, and Note 8,10, Derivative Instruments, in this report for information concerning our market risk exposures.


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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon such evaluation, our principal executive officer and principal financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective: (i) in recording, processing, summarizing, and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act; and (ii) to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

ThereDuring the first quarter of 2018, WEC Energy Group completed an enterprise resource planning (ERP) system integration project to bring all of its subsidiaries, including us, onto a consolidated ERP system. Accordingly, we are modifying the design and documentation of certain internal control processes and procedures related to the integrated ERP system. We do not believe that the implementation of the ERP system will have an adverse effect on our internal control over financial reporting.

With the exception of the ERP system implementation described above, there were no changes in our internal control over financial reporting (as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the third quarter of 2017 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The following should be read in conjunction with Item 3. Legal Proceedings in Part I of our 20162017 Annual Report on Form 10-K. See Note 14,15, Commitments and Contingencies, and Note 17, Regulatory Environment, in this report for more information on material legal proceedings and matters related to us.

In addition to those legal proceedings referenced above,discussed in Note 15, Commitments and Contingencies, Note 17, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these legal proceedings cannot be predicted with certainty, management believes, after consultation with legal counsel, that the ultimate resolution of these proceedings will not have a material effect on our financial statements.

Presque Isle Power Plant Matter

In March 2018, the EPA issued a Finding of Violation to us regarding alleged violations of mercury emission limits for PIPP Units 5, 6, 8, and 9, as well as failing to conduct low emitting electric utility steam generating units mercury testing once every 12 months. We observed atypical initial mercury test results in June 2017 and immediately began to troubleshoot the potential cause. We found that the supplier of dry sorbent injection material for the air quality control system that controls mercury had delivered material that was out of specification per our contract and permit requirements. In June 2017, we notified the MDEQ, who notified the EPA that the EPA had jurisdiction regarding this matter. We have been working with the EPA to resolve this matter and do not expect it to have a material impact on our financial statements.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors presented in our Annual Report on Form 10-K for the year ended December 31, 2016.2017. See Item 1A. Risk Factors in Part I of our 20162017 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.


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In October 2017, Allen L. Leverett, Chief Executive Officer of Wisconsin Electric, suffered a stroke. Mr. Leverett has been released from the hospital and is making progress in his recovery and rehabilitation work. Pursuant to the Wisconsin Electric Bylaws, on October 31, 2017, the Wisconsin Electric Board ordered that the duties of Chief Executive Officer would be exercised by the President of Wisconsin Electric, J. Kevin Fletcher, on an interim basis. Mr. Fletcher has executed the certificates attached to this Form 10-Q in such capacity.

ITEM 6. EXHIBITS
Number Exhibit
12Statements re Computation of Ratios
12.1
Ratio of Earnings to Fixed Charges
31 Rule 13a-14(a) / 15d-14(a) Certifications
    
  
31.1
Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
  
31.2
Certification Pursuant to Rule 13a-14(a) or 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
    
32 Section 1350 Certifications
    
  
32.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
  
32.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
    
101 Interactive Data File
 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



  WISCONSIN ELECTRIC POWER COMPANY
  (Registrant)
   
  /s/ WILLIAM J. GUC
Date:November 3, 2017May 4, 2018William J. Guc
  Vice President and Controller
   
  (Duly Authorized Officer and Chief Accounting Officer)


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