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, 2017
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Commission☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2021
OR
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| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ________________ to ___________________
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Commission
File Number | | Registrant; State of Incorporation; | | IRS Employer |
File Number | |
Address; and Telephone Number | | IRS Employer
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 | | |
(A Wisconsin Corporation)
231 West Michigan Street
P.O. Box 2046
Milwaukee, WI 53201
(414) 221-2345
Securities registered pursuant to Section 12(b) of the Act:
None
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.
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| Large accelerated filer | ☐ | | Accelerated filer | ☐ | |
| Non-accelerated filer | ☒ | | Smaller reporting company | ☐ |
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| 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, 20172021
All of the common stock of Wisconsin Electric Power Company is ownedheld by WEC Energy Group, Inc.
WISCONSIN ELECTRIC POWER COMPANY
QUARTERLY REPORT ON FORM 10-Q
For the Quarter Ended September 30, 20172021
TABLE OF CONTENTS
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09/30/20172021 Form 10-Q | i | Wisconsin Electric Power Company |
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:
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| Affiliates |
| ATC | | American Transmission Company LLC |
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Subsidiaries and Affiliates | | |
ATC | | American Transmission Company LLC |
Bluewater | | Bluewater Natural Gas Holding, LLC |
Bostco | | Bostco LLC |
Integrys | | Integrys 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. |
WGWEPCo Environmental Trust | | Wisconsin GasWEPCo Environmental Trust Finance I, LLC |
WPS | | |
| WPS | | Wisconsin Public Service Corporation |
| | |
| Federal and State Regulatory Agencies |
EPADOC | | United States Department of Commerce |
| 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 |
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| Accounting Terms |
| AFUDC | | Allowance for Funds Used During Construction |
AIAARO | | Affiliated Interest AgreementAsset Retirement Obligation |
| ASU | | Accounting Standards Update |
| FASB | | Financial Accounting Standards Board |
| GAAP | | United States Generally Accepted Accounting Principles |
| OPEB | | Other Postretirement Employee Benefits |
| VIE | | Variable Interest Entity |
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| Environmental Terms |
| ACE | | Affordable Clean Energy |
| BATW | | Bottom Ash Transport Water |
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| BTA | | Best Technology Available |
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CO2 | | Carbon Dioxide |
| CSAPR | | Cross-State Air Pollution Rule |
GHGELG | | Greenhouse GasSteam Electric Effluent Limitation Guidelines |
NAAQSFGD | | Flue Gas Desulfurization |
| GHG | | Greenhouse Gas |
| NAAQS | | National Ambient Air Quality Standards |
NOx | | Nitrogen Oxide |
SO2
NOx | | Sulfur DioxideNitrogen Oxide |
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Measurements | | |
Dth | | Dekatherm |
MW | | MegawattMeasurements |
MWhDth | | Megawatt-hourDekatherm |
| MW | | Megawatt |
| MWh | | Megawatt-hour |
| | |
| Other Terms and Abbreviations |
| AMI | | Advanced Metering Infrastructure |
| Badger Hollow II | | Badger Hollow Solar Park II |
| CDC | | Centers for Disease Control and Prevention |
| COVID-19 | | Coronavirus Disease – 2019 |
| D.C. Circuit Court of Appeals | | United States Court of Appeals for the District of Columbia Circuit |
| ERGS | | Elm Road Generating Station |
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| ESG Progress Plan | | WEC Energy Group's Capital Investment Plan for Efficiency, Sustainability, and Growth |
| ETB | | Environmental Trust Bond |
| EV | | Electric Vehicle |
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| 09/30/2021 Form 10-Q | ii | Wisconsin Electric Power Company |
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| Exchange Act | | Securities Exchange Act of 1934, as amended |
FTRsExecutive Order 13990 | | Executive Order 13990 of January 20, 2021 – Protecting Public Health and the Environment and Restoring Science To Tackle the Climate Crisis |
| FTR | | Financial Transmission RightsRight |
MCPPITC | | Milwaukee County Power PlantInvestment Tax Credit |
MISOLIBOR | | London Interbank Offered Rate |
| LNG | | Liquefied Natural Gas |
| MISO | | Midcontinent Independent System Operator, Inc. |
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| OCPP | | Oak Creek Power Plant |
| OC 5 | | Oak Creek Power Plant Unit 5 |
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| OC 7 | | Oak Creek Power Plant Unit 7 |
| OC 8 | | Oak Creek Power Plant Unit 8 |
| PSB | | Public Service Building |
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09/30/2017 Form 10-Q | ii | Wisconsin Electric Power Company |
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MISO Energy MarketsPTC | | MISO Energy and Operating Reserves MarketsProduction Tax Credit |
OCPPROE | | Oak Creek Power Plant |
OC 5 | | Oak Creek Power Plant Unit 5 |
OC 6 | | Oak Creek Power Plant Unit 6 |
OC 7 | | Oak Creek Power Plant Unit 7 |
OC 8 | | Oak Creek Power Plant Unit 8 |
PIPP | | Presque Isle Power Plant |
PWGS | | Port Washington Generating Station |
ROE | | Return on Equity |
| SSR | | System Support Resource |
| Supreme Court | | United States Supreme Court |
VAPPTax Legislation | | Valley Power PlantTax Cuts and Jobs Act of 2017 |
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| WHO | | World Health Organization |
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09/30/20172021 Form 10-Q | iii | Wisconsin Electric Power Company |
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, andincluding associated compliance costs, legal proceedings, effective tax rate,rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmentalclimate-related matters, the ESG Progress Plan, 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 2020 Annual Report on Form 10-K, for the year ended December 31, 2016, 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 or regulatory developments, unusualvarying, adverse, or unusually severe weather conditions, 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 health pandemics, including the COVID-19 pandemic, on our business functions, financial condition, liquidity, and results of operations;
•The impact of recent and future federal, state, and local legislative andand/or 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;mandates, and tax laws, including those that affect our ability to use PTCs and ITCs;
•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 regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;
•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 and the ability to recover the related costs through rates;
•Supply chain disruptions, including any that may occur as a result of the DOC's impending decision on whether to impose new tariffs on solar panels and cells imported from several Southeastern Asian countries;
•Factors affecting the implementation of WEC Energy Group's CO2 emission and/or methane emission reduction goals, and opportunities and actions related to those goals, including related regulatory decisions, the cost of materials, supplies, and labor, technology advances, and the feasibility of competing generation projects;
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| 09/30/2021 Form 10-Q | 1 | Wisconsin Electric Power Company |
•The financial and operational feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases;
•The risks associated with inflation and changing commodity prices, particularlyincluding natural gas and electricity,electricity;
•The availability and the availabilitycost of sources of fossil fuel, natural gas and other fossil fuels, 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;
•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;
•Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate;
•Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;
•The direct or indirect effect on our business resulting from terrorist attacks and cyber security intrusions, as well as the threat of such incidents, 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 and to comply with state notification laws;
•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;
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09/30/2017 Form 10-Q | 1 | Wisconsin Electric Power Company |
•Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;
The direct or indirect effect on our business resulting from terrorist incidents, the threat of terrorist incidents, and cyber security intrusion, including the failure to maintain the security of personally identifiable information, the associated costs to protect our assets and personal information, and the costs to notify affected persons to mitigate their information security concerns;
•The 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, and related legislation or regulation supporting the use of that technology, that result in competitive disadvantages and create the potential for impairment of existing assets;
The timing, costs,•Potential business strategies to acquire and anticipated benefits associated with the remaining integration efforts relatingdispose of assets, which cannot be assured to WEC Energy Group's acquisition of Integrys;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 continuing to integrate and 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.
WeExcept as may be required by law, 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.
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09/30/20172021 Form 10-Q | 2 | Wisconsin Electric Power Company |
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
WISCONSIN ELECTRIC POWER COMPANY
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| CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) | | Three Months Ended | | Nine Months Ended |
| | September 30 | | September 30 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
| Operating revenues | | $ | 958.8 | | | $ | 900.2 | | | $ | 2,791.5 | | | $ | 2,540.7 | |
| | | | | | | | |
| Operating expenses | | | | | | | | |
| Cost of sales | | 336.7 | | | 297.9 | | | 1,017.3 | | | 822.7 | |
| Other operation and maintenance | | 220.0 | | | 221.9 | | | 642.4 | | | 640.8 | |
| Depreciation and amortization | | 116.7 | | | 107.7 | | | 340.7 | | | 318.4 | |
| Property and revenue taxes | | 24.5 | | | 28.1 | | | 74.6 | | | 78.6 | |
| Total operating expenses | | 697.9 | | | 655.6 | | | 2,075.0 | | | 1,860.5 | |
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| Operating income | | 260.9 | | | 244.6 | | | 716.5 | | | 680.2 | |
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| Other income, net | | 7.6 | | | 5.7 | | | 22.3 | | | 15.9 | |
| Interest expense | | 114.3 | | | 116.3 | | | 346.5 | | | 351.5 | |
| Other expense | | (106.7) | | | (110.6) | | | (324.2) | | | (335.6) | |
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| Income before income taxes | | 154.2 | | | 134.0 | | | 392.3 | | | 344.6 | |
| Income tax expense | | 24.4 | | | 19.1 | | | 56.1 | | | 39.8 | |
| Net income | | 129.8 | | | 114.9 | | | 336.2 | | | 304.8 | |
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| Preferred stock dividend requirements | | 0.3 | | | 0.3 | | | 0.9 | | | 0.9 | |
| Net income attributed to common shareholder | | $ | 129.5 | | | $ | 114.6 | | | $ | 335.3 | | | $ | 303.9 | |
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| CONDENSED CONSOLIDATED INCOME STATEMENTS (Unaudited) | | Three Months Ended | | Nine Months Ended |
| | | September 30 | | September 30 |
| (in millions) | | 2017 | | 2016 | | 2017 | | 2016 |
| Operating revenues | | $ | 943.8 |
| | $ | 1,023.8 |
| | $ | 2,771.2 |
| | $ | 2,876.5 |
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| Operating expenses | | | | | | | | |
| Cost of sales | | 336.5 |
| | 357.1 |
| | 959.0 |
| | 977.8 |
|
| Other operation and maintenance | | 332.6 |
| | 359.4 |
| | 988.1 |
| | 1,043.8 |
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| Depreciation and amortization | | 83.0 |
| | 81.9 |
| | 247.8 |
| | 243.1 |
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| Property and revenue taxes | | 28.3 |
| | 29.0 |
| | 85.0 |
| | 87.0 |
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| Total operating expenses | | 780.4 |
| | 827.4 |
| | 2,279.9 |
| | 2,351.7 |
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| Operating income | | 163.4 |
| | 196.4 |
| | 491.3 |
| | 524.8 |
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| Equity in earnings of transmission affiliate | | — |
| | 14.6 |
| | — |
| | 40.7 |
|
| Other income, net | | 5.5 |
| | 0.5 |
| | 14.3 |
| | 6.7 |
|
| Interest expense | | 29.3 |
| | 29.5 |
| | 88.0 |
| | 88.0 |
|
| Other expense | | (23.8 | ) | | (14.4 | ) | | (73.7 | ) | | (40.6 | ) |
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| Income before income taxes | | 139.6 |
| | 182.0 |
| | 417.6 |
| | 484.2 |
|
| Income tax expense | | 49.9 |
| | 66.5 |
| | 150.2 |
| | 178.2 |
|
| Net income | | 89.7 |
| | 115.5 |
| | 267.4 |
| | 306.0 |
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| Preferred stock dividend requirements | | 0.3 |
| | 0.3 |
| | 0.9 |
| | 0.9 |
|
| Net income attributed to common shareholder | | $ | 89.4 |
| | $ | 115.2 |
| | $ | 266.5 |
| | $ | 305.1 |
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The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.
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09/30/20172021 Form 10-Q | 3 | Wisconsin Electric Power Company |
WISCONSIN ELECTRIC POWER COMPANY
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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts) | | September 30, 2021 | | December 31, 2020 |
| Assets | | | | |
| Current assets | | | | |
| Cash and cash equivalents | | $ | 5.5 | | | $ | 7.2 | |
| Accounts receivable and unbilled revenues, net of reserves of $47.1 and $59.3, respectively | | 576.1 | | | 466.1 | |
| Accounts receivable from related parties | | 60.6 | | | 67.9 | |
| Materials, supplies, and inventories | | 226.1 | | | 219.5 | |
| Prepaid taxes | | 68.9 | | | 98.5 | |
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| Derivative assets | | 85.5 | | | 6.2 | |
| Other | | 19.9 | | | 30.2 | |
| Current assets | | 1,042.6 | | | 895.6 | |
| | | | |
| Long-term assets | | | | |
| Property, plant, and equipment, net of accumulated depreciation and amortization of $5,066.2 and $4,849.2, respectively | | 9,974.4 | | | 9,789.9 | |
| Regulatory assets (September 30, 2021 includes $102.9 related to WEPCo Environmental Trust) | | 2,809.1 | | | 2,803.3 | |
| Other | | 143.4 | | | 116.4 | |
| Long-term assets | | 12,926.9 | | | 12,709.6 | |
| Total assets | | $ | 13,969.5 | | | $ | 13,605.2 | |
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| Liabilities and Equity | | | | |
| Current liabilities | | | | |
| Short-term debt | | $ | 22.5 | | | $ | 292.0 | |
| Current portion of long-term debt (September 30, 2021 includes $8.5 related to WEPCo Environmental Trust) | | 8.5 | | | 300.0 | |
| Current portion of finance lease obligations | | 71.2 | | | 66.8 | |
| Accounts payable | | 324.9 | | | 261.2 | |
| Accounts payable to related parties | | 160.9 | | | 172.0 | |
| Accrued payroll and benefits | | 43.7 | | | 43.3 | |
| Accrued taxes | | 56.2 | | | 25.0 | |
| Other | | 155.0 | | | 97.1 | |
| Current liabilities | | 842.9 | | | 1,257.4 | |
| | | | |
| Long-term liabilities | | | | |
| Long-term debt (September 30, 2021 includes $107.0 related to WEPCo Environmental Trust) | | 2,867.1 | | | 2,461.2 | |
| Finance lease obligations | | 2,733.6 | | | 2,774.4 | |
| Deferred income taxes | | 1,382.0 | | | 1,357.2 | |
| Regulatory liabilities | | 1,777.4 | | | 1,703.7 | |
| Pension and OPEB obligations | | 63.8 | | | 85.9 | |
| Other | | 284.1 | | | 272.8 | |
| Long-term liabilities | | 9,108.0 | | | 8,655.2 | |
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| Commitments and contingencies (Note 18) | | 0 | | 0 |
| | | | |
| Common shareholder's equity | | | | |
| Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding | | 332.9 | | | 332.9 | |
| Additional paid in capital | | 1,290.8 | | | 1,060.1 | |
| Retained earnings | | 2,364.5 | | | 2,269.2 | |
| Common shareholder's equity | | 3,988.2 | | | 3,662.2 | |
| | | | |
| Preferred stock | | 30.4 | | | 30.4 | |
| Total liabilities and equity | | $ | 13,969.5 | | | $ | 13,605.2 | |
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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (in millions, except share and per share amounts) | | September 30, 2017 | | December 31, 2016 |
| Assets | | | | |
| Current assets | | | | |
| Cash and cash equivalents | | $ | 3.3 |
| | $ | 15.4 |
|
| 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 |
|
| Materials, supplies, and inventories | | 294.6 |
| | 271.0 |
|
| Prepayments | | 100.1 |
| | 138.0 |
|
| Other | | 7.2 |
| | 24.6 |
|
| Current assets | | 917.4 |
| | 1,010.4 |
|
| | | | | |
| 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 |
|
| Regulatory assets | | 2,126.0 |
| | 2,036.6 |
|
| Equity investment in transmission affiliate | | — |
| | 402.0 |
|
| Other | | 84.5 |
| | 90.2 |
|
| Long-term assets | | 12,117.8 |
| | 12,361.1 |
|
| Total assets | | $ | 13,035.2 |
| | $ | 13,371.5 |
|
| | | | | |
| Liabilities and Equity | | | | |
| Current liabilities | | | | |
| Short-term debt | | $ | 59.0 |
| | $ | 159.0 |
|
| Current portion of long-term debt | | 250.0 |
| | — |
|
| Current portion of capital lease obligations | | 33.4 |
| | 28.5 |
|
| Subsidiary note payable to WEC Energy Group | | — |
| | 18.5 |
|
| Accounts payable | | 276.5 |
| | 297.9 |
|
| Accounts payable to related parties | | 119.2 |
| | 112.9 |
|
| Accrued payroll and benefits | | 44.3 |
| | 51.8 |
|
| Accrued taxes | | 30.8 |
| | 46.0 |
|
| Other | | 92.4 |
| | 100.1 |
|
| Current liabilities | | 905.6 |
| | 814.7 |
|
| | | | | |
| Long-term liabilities | | | | |
| Long-term debt | | 2,411.7 |
| | 2,661.1 |
|
| Capital lease obligations | | 2,829.7 |
| | 2,756.5 |
|
| Deferred income taxes | | 2,214.2 |
| | 2,333.3 |
|
| Regulatory liabilities | | 829.7 |
| | 853.9 |
|
| Pension and OPEB obligations | | 154.9 |
| | 167.6 |
|
| Other | | 271.5 |
| | 260.2 |
|
| Long-term liabilities | | 8,711.7 |
| | 9,032.6 |
|
| | | | | |
| Commitments and contingencies (Note 14) | |
| |
|
| | | | | |
| Common shareholder's equity | | | | |
| Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding | | 332.9 |
| | 332.9 |
|
| Additional paid in capital | | 815.3 |
| | 1,020.1 |
|
| Retained earnings | | 2,239.3 |
| | 2,140.8 |
|
| Common shareholder's equity | | 3,387.5 |
| | 3,493.8 |
|
| | | | | |
| Preferred stock | | 30.4 |
| | 30.4 |
|
| Total liabilities and equity | | $ | 13,035.2 |
| | $ | 13,371.5 |
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.
|
| | | | | | | |
09/30/20172021 Form 10-Q | 4 | Wisconsin Electric Power Company |
WISCONSIN ELECTRIC POWER COMPANY
| | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) | | Nine Months Ended |
| | September 30 |
| (in millions) | | 2021 | | 2020 |
| Operating activities | | | | |
| Net income | | $ | 336.2 | | | $ | 304.8 | |
| Reconciliation to cash provided by operating activities | | | | |
| Depreciation and amortization | | 340.7 | | | 318.4 | |
| Deferred income taxes and ITCs, net | | (37.2) | | | (43.4) | |
| | | | |
| | | | |
| Change in – | | | | |
| Accounts receivable and unbilled revenues, net | | (42.7) | | | 30.6 | |
| | | | |
| Prepaid taxes | | 29.6 | | | 34.5 | |
| | | | |
| Other current assets | | 8.4 | | | 19.8 | |
| Accounts payable | | 66.0 | | | (69.6) | |
| Accrued taxes | | 31.2 | | | 13.9 | |
| | | | |
| Other current liabilities | | 62.8 | | | 7.5 | |
| Other, net | | 36.7 | | | 27.9 | |
| Net cash provided by operating activities | | 831.7 | | | 644.4 | |
| | | | |
| Investing activities | | | | |
| Capital expenditures | | (625.9) | | | (462.8) | |
| | | | |
| Proceeds from assets transferred to affiliates | | 10.7 | | | 1.3 | |
| | | | |
| | | | |
| Other, net | | 4.6 | | | 9.5 | |
| Net cash used in investing activities | | (610.6) | | | (452.0) | |
| | | | |
| Financing activities | | | | |
| Change in short-term debt | | (269.5) | | | (115.5) | |
| Issuance of long-term debt | | 418.8 | | | — | |
| Retirement of long-term debt | | (300.0) | | | — | |
| Payments for finance lease obligations | | (49.8) | | | (43.0) | |
| Equity contribution from parent | | 230.0 | | | 130.0 | |
| Payment of dividends to parent | | (240.0) | | | (180.0) | |
| Other, net | | (7.1) | | | (1.1) | |
| Net cash used in financing activities | | (217.6) | | | (209.6) | |
| | | | |
| Net change in cash, cash equivalents, and restricted cash | | 3.5 | | | (17.2) | |
| Cash, cash equivalents, and restricted cash at beginning of period | | 7.2 | | | 19.1 | |
| Cash, cash equivalents, and restricted cash at end of period | | $ | 10.7 | | | $ | 1.9 | |
|
| | | | | | | | |
| CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) | | Nine Months Ended |
| | | September 30 |
| (in millions) | | 2017 | | 2016 |
| Operating Activities | | | | |
| Net income | | $ | 267.4 |
| | $ | 306.0 |
|
| Reconciliation to cash provided by operating activities | | | | |
| Depreciation and amortization | | 247.8 |
| | 249.0 |
|
| Deferred income taxes and investment tax credits, net | | 105.2 |
| | 248.6 |
|
| Contributions and payments related to pension and OPEB plans | | (5.9 | ) | | (6.4 | ) |
| Equity income in transmission affiliate, net of distributions | | — |
| | (13.0 | ) |
| Proceeds from (payments for) liabilities transferred from (to) WBS | | 0.9 |
| | (116.1 | ) |
| Change in – | | | | |
| Accounts receivable and unbilled revenues | | 49.0 |
| | 13.1 |
|
| Materials, supplies, and inventories | | (23.6 | ) | | 37.5 |
|
| Prepaid taxes | | 31.2 |
| | (75.2 | ) |
| Other current assets | | 5.3 |
| | 16.1 |
|
| Accounts payable | | (14.6 | ) | | (12.2 | ) |
| Accrued taxes | | (15.2 | ) | | 0.8 |
|
| Other current liabilities | | (15.6 | ) | | (5.8 | ) |
| Other, net | | (37.6 | ) | | (27.8 | ) |
| Net cash provided by operating activities | | 594.3 |
| | 614.6 |
|
| | | | | |
| Investing Activities | | | | |
| Capital expenditures | | (405.7 | ) | | (322.5 | ) |
| Capital contributions to transmission affiliate | | — |
| | (10.4 | ) |
| Proceeds from the sale of assets | | 22.9 |
| | 31.7 |
|
| Proceeds from assets transferred to WBS | | — |
| | 13.1 |
|
| Short-term notes receivable from related parties, net | | (3.1 | ) | | — |
|
| Other, net | | 3.8 |
| | 2.9 |
|
| Net cash used in investing activities | | (382.1 | ) | | (285.2 | ) |
| | | | | |
| Financing Activities | | | | |
| Change in short-term debt | | (100.0 | ) | | (39.5 | ) |
| Repayment of subsidiary note to parent | | (18.5 | ) | | (2.5 | ) |
| Equity contribution from parent | | 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 |
|
| Net cash used in financing activities | | (224.3 | ) | | (344.3 | ) |
| | | | | |
| Net change in cash and cash equivalents | | (12.1 | ) | | (14.9 | ) |
| Cash and cash equivalents at beginning of period | | 15.4 |
| | 27.1 |
|
| Cash and cash equivalents at end of period | | $ | 3.3 |
| | $ | 12.2 |
|
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.
|
| | | | | | | |
09/30/20172021 Form 10-Q | 5 | Wisconsin Electric Power Company |
WISCONSIN ELECTRIC POWER COMPANY
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (Unaudited) | | | | | | |
| | | | | | | | | | | | |
| | Wisconsin Electric Power Company Common Shareholder's Equity | | | | |
| (in millions) | | Common Stock | | Additional Paid In Capital | | Retained Earnings | | Total Common Shareholder's Equity | | Preferred Stock | | Total Equity |
| Balance at December 31, 2020 | | $ | 332.9 | | | $ | 1,060.1 | | | $ | 2,269.2 | | | $ | 3,662.2 | | | $ | 30.4 | | | $ | 3,692.6 | |
| Net income attributed to common shareholder | | — | | | — | | | 127.0 | | | 127.0 | | | — | | | 127.0 | |
| Payment of dividends to parent | | — | | | — | | | (60.0) | | | (60.0) | | | — | | | (60.0) | |
| Equity contribution from parent | | — | | | 30.0 | | | — | | | 30.0 | | | — | | | 30.0 | |
| Stock-based compensation and other | | — | | | 0.5 | | | 0.1 | | | 0.6 | | | — | | | 0.6 | |
| Balance at March 31, 2021 | | $ | 332.9 | | | $ | 1,090.6 | | | $ | 2,336.3 | | | $ | 3,759.8 | | | $ | 30.4 | | | $ | 3,790.2 | |
| Net income attributed to common shareholder | | — | | | — | | | 78.8 | | | 78.8 | | | — | | | 78.8 | |
| Payment of dividends to parent | | — | | | — | | | (60.0) | | | (60.0) | | | — | | | (60.0) | |
| Stock-based compensation and other | | — | | | 0.1 | | | (0.1) | | | — | | | — | | | — | |
| Balance at June 30, 2021 | | $ | 332.9 | | | $ | 1,090.7 | | | $ | 2,355.0 | | | $ | 3,778.6 | | | $ | 30.4 | | | $ | 3,809.0 | |
| Net income attributed to common shareholder | | — | | | — | | | 129.5 | | | 129.5 | | | — | | | 129.5 | |
| Payment of dividends to parent | | — | | | — | | | (120.0) | | | (120.0) | | | — | | | (120.0) | |
| Equity contribution from parent | | — | | | 200.0 | | | — | | | 200.0 | | | — | | | 200.0 | |
| Stock-based compensation and other | | — | | | 0.1 | | | — | | | 0.1 | | | — | | | 0.1 | |
| Balance at September 30, 2021 | | $ | 332.9 | | | $ | 1,290.8 | | | $ | 2,364.5 | | | $ | 3,988.2 | | | $ | 30.4 | | | $ | 4,018.6 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Wisconsin Electric Power Company Common Shareholder's Equity | | | | |
| (in millions) | | Common Stock | | Additional Paid In Capital | | Retained Earnings | | Total Common Shareholder's Equity | | Preferred Stock | | Total Equity |
| Balance at December 31, 2019 | | $ | 332.9 | | | $ | 929.5 | | | $ | 2,298.7 | | | $ | 3,561.1 | | | $ | 30.4 | | | $ | 3,591.5 | |
| Net income attributed to common shareholder | | — | | | — | | | 118.7 | | | 118.7 | | | — | | | 118.7 | |
| Payment of dividends to parent | | — | | | — | | | (60.0) | | | (60.0) | | | — | | | (60.0) | |
| | | | | | | | | | | | |
| Stock-based compensation and other | | — | | | 0.5 | | | — | | | 0.5 | | | — | | | 0.5 | |
| Balance at March 31, 2020 | | $ | 332.9 | | | $ | 930.0 | | | $ | 2,357.4 | | | $ | 3,620.3 | | | $ | 30.4 | | | $ | 3,650.7 | |
| Net income attributed to common shareholder | | — | | | — | | | 70.6 | | | 70.6 | | | — | | | 70.6 | |
| Payment of dividends to parent | | — | | | — | | | (60.0) | | | (60.0) | | | — | | | (60.0) | |
| Equity contribution from parent | | — | | | 65.0 | | | — | | | 65.0 | | | — | | | 65.0 | |
| | | | | | | | | | | | |
| Balance at June 30, 2020 | | $ | 332.9 | | | $ | 995.0 | | | $ | 2,368.0 | | | $ | 3,695.9 | | | $ | 30.4 | | | $ | 3,726.3 | |
| Net income attributed to common shareholder | | — | | | — | | | 114.6 | | | 114.6 | | | — | | | 114.6 | |
| Payment of dividends to parent | | — | | | — | | | (60.0) | | | (60.0) | | | — | | | (60.0) | |
| Equity contribution from parent | | — | | | 65.0 | | | — | | | 65.0 | | | — | | | 65.0 | |
| Stock-based compensation and other | | — | | | 0.1 | | | — | | | 0.1 | | | $ | — | | | $ | 0.1 | |
| Balance at September 30, 2020 | | $ | 332.9 | | | $ | 1,060.1 | | | $ | 2,422.6 | | | $ | 3,815.6 | | | $ | 30.4 | | | $ | 3,846.0 | |
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these financial statements.
| | | | | | | | |
| 09/30/2021 Form 10-Q | 6 | Wisconsin Electric Power Company |
WISCONSIN ELECTRIC POWER COMPANY
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
September 30, 20172021
NOTE 1—GENERAL INFORMATION
Wisconsin Electric Power Company serves approximately 1.1 million electric customers and 0.5 million natural gas customers.
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, and statements of equity, 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.Company.
Prior to January 1, 2017,On our financial statements, we owned approximately 23%consolidate VIEs of ATC, a for-profit, electric transmission company regulated bywhich we are 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.primary beneficiary.
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, 2016.2020. 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, 2017,2021 are not necessarily indicative of expected results for 20172021 due to seasonal variations and other factors.factors, including any continuing financial impacts from the COVID-19 pandemic.
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—DISPOSITIONSOPERATING REVENUES
For more information about our operating revenues, see Note 1(d), Operating Revenues, in our 2020 Annual Report on Form 10-K.
Disaggregation of Operating Revenues
The following tables present our operating revenues disaggregated by revenue source for our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. Revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
| Wisconsin Electric Power Company | | | | | | | | |
| Electric utility | | $ | 905.0 | | | $ | 853.2 | | | $ | 2,447.4 | | | $ | 2,289.5 | |
| Natural gas utility | | 50.2 | | | 44.7 | | | 328.3 | | | 245.6 | |
| Total revenues from contracts with customers | | 955.2 | | | 897.9 | | | 2,775.7 | | | 2,535.1 | |
| Other operating revenues | | 3.6 | | | 2.3 | | | 15.8 | | | 5.6 | |
| Total operating revenues | | $ | 958.8 | | | $ | 900.2 | | | $ | 2,791.5 | | | $ | 2,540.7 | |
| | | | | | | | |
| | | | | | | | |
| 09/30/2021 Form 10-Q | 7 | Wisconsin Electric Power Company |
Revenues from Contracts with Customers
Electric Utility SegmentOperating Revenues
SaleThe following table disaggregates electric utility operating revenues into customer class:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
| Residential | | $ | 385.3 | | | $ | 373.8 | | | $ | 1,005.1 | | | $ | 981.2 | |
| Small commercial and industrial | | 282.4 | | | 265.3 | | | 773.6 | | | 723.8 | |
| Large commercial and industrial | | 168.0 | | | 159.4 | | | 435.1 | | | 405.1 | |
| Other | | 4.7 | | | 4.5 | | | 14.9 | | | 14.2 | |
| Total retail revenues | | 840.4 | | | 803.0 | | | 2,228.7 | | | 2,124.3 | |
| Wholesale | | 16.3 | | | 19.2 | | | 55.0 | | | 56.9 | |
| Resale | | 42.8 | | | 29.1 | | | 135.4 | | | 90.3 | |
| Steam | | 2.7 | | | 2.5 | | | 21.7 | | | 15.0 | |
| Other utility revenues | | 2.8 | | | (0.6) | | | 6.6 | | | 3.0 | |
| Total electric utility operating revenues | | $ | 905.0 | | | $ | 853.2 | | | $ | 2,447.4 | | | $ | 2,289.5 | |
| | | | | | | | |
Natural Gas Utility Operating Revenues
The following table disaggregates natural gas utility operating revenues into customer class:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
| Residential | | $ | 30.7 | | | $ | 23.7 | | | $ | 213.7 | | | $ | 162.4 | |
| Commercial and industrial | | 13.1 | | | 7.1 | | | 97.3 | | | 64.4 | |
| Total retail revenues | | 43.8 | | | 30.8 | | | 311.0 | | | 226.8 | |
| Transportation | | 3.5 | | | 3.2 | | | 12.6 | | | 11.7 | |
Other utility revenues (1) | | 2.9 | | | 10.7 | | | 4.7 | | | 7.1 | |
| Total natural gas utility operating revenues | | $ | 50.2 | | | $ | 44.7 | | | $ | 328.3 | | | $ | 245.6 | |
(1)Includes the revenues subject to our purchased gas recovery mechanism. As these amounts are billed to customers, they are reflected in retail revenues with an offsetting decrease in other utility revenues.
Other Operating Revenues
Other operating revenues consist primarily of Milwaukee County Power Plantthe following:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
Late payment charges (1) | | $ | 2.7 | | | $ | 0.7 | | | $ | 10.8 | | | $ | 3.4 | |
| Rental revenues | | 0.3 | | | 0.3 | | | 2.7 | | | 2.6 | |
Alternative revenues (2) | | 0.6 | | | 1.3 | | | 2.3 | | | (0.4) | |
| Total other operating revenues | | $ | 3.6 | | | $ | 2.3 | | | $ | 15.8 | | | $ | 5.6 | |
In April 2016, we sold
(1)The increase in late payment charges during the MCPP steam generationthree and distribution assets, locatednine months ended September 30, 2021, compared with the same periods in Wauwatosa, Wisconsin. MCPP primarily provided steam2020, was a result of the expiration of a regulatory order from the PSCW in response to the Milwaukee Regional Medical Center hospitalsCOVID-19 pandemic, which included the suspension of late payment charges during a designated time period. See Note 20, Regulatory Environment, for more information.
(2)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 wholesale customers subject to true-up, as discussed in Note 1(d), Operating Revenues, in our 2020 Annual Report on Form 10-K.
| | | | | | | | |
| 09/30/2021 Form 10-Q | 8 | Wisconsin Electric Power Company |
NOTE 3—CREDIT LOSSES
Our exposure to credit losses is related to our accounts receivable and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain onunbilled revenue balances, which are generated from the sale of $10.9electricity and natural gas by our regulated utility operations. Our regulated utility operations are included in our utility segment. No accounts receivable and unbilled revenue balances were reported in the other segment at September 30, 2021 and December 31, 2020.
We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required.
We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by the PSCW, if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 20, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic.
We have included a table below that shows our gross third-party receivable balances and related allowance for credit losses.
| | | | | | | | | | | | | | |
| (in millions) | | September 30, 2021 | | December 31, 2020 |
| Accounts receivable and unbilled revenues | | $ | 623.2 | | | $ | 525.4 | |
| Allowance for credit losses | | 47.1 | | | 59.3 | |
Accounts receivable and unbilled revenues, net (1) | | $ | 576.1 | | | $ | 466.1 | |
| | | | |
Total accounts receivable, net – past due greater than 90 days (1) | | $ | 30.3 | | | $ | 56.3 | |
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1) | | 97.5 | % | | 98.2 | % |
(1)Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. As a result, at September 30, 2021, $217.2 million, ($6.5or 37.7%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentages in the above table or this note. See Note 20, Regulatory Environment, for more information on these orders.
A rollforward of the allowance for credit losses for the three and nine months ended September 30, 2021 and 2020 is included below:
| | | | | | | | | | | | | | |
| | Three Months Ended |
| (in millions) | | September 30, 2021 | | September 30, 2020 |
| Balance at June 30 | | $ | 71.3 | | | $ | 45.7 | |
| Provision for credit losses | | 5.5 | | | 7.7 | |
| Provision for credit losses deferred for future recovery or refund | | (22.4) | | | 2.9 | |
| Write-offs charged against the allowance | | (10.6) | | | (9.0) | |
| Recoveries of amounts previously written off | | 3.3 | | | 4.8 | |
| Balance at September 30 | | $ | 47.1 | | | $ | 52.1 | |
| | | | | | | | |
| 09/30/2021 Form 10-Q | 9 | Wisconsin Electric Power Company |
| | | | | | | | | | | | | | |
| | Nine Months Ended |
| (in millions) | | September 30, 2021 | | September 30, 2020 |
| Balance at December 31 | | $ | 59.3 | | | $ | 38.1 | |
| Provision for credit losses | | 18.0 | | | 21.4 | |
| Provision for credit losses deferred for future recovery or refund | | (8.5) | | | 6.4 | |
| Write-offs charged against the allowance | | (32.8) | | | (30.6) | |
| Recoveries of amounts previously written off | | 11.1 | | | 16.8 | |
| Balance at September 30 | | $ | 47.1 | | | $ | 52.1 | |
The allowance for credit losses decreased over both the three and nine month periods ended September 30, 2021. The decrease in the allowance for credit losses over both periods was driven by lower past due accounts receivable balances, as we have been able to ramp up collection efforts due to the return to normal collection practices in April 2021. See Note 20, Regulatory Environment, for more information.
The increase in our allowance for credit losses in 2020 was driven by an increase in past due accounts receivable balances from December 31, 2019 to September 30, 2020. This is a trend we generally see over the winter moratorium months, when we are not allowed to disconnect customer service as a result of non-payment. In Wisconsin, the winter moratorium begins on November 1 and ends on April 15. However, as a result of the COVID-19 pandemic and related regulatory orders we received, we were also unable to disconnect any of our customers during the second and third quarters of 2020.
NOTE 4—REGULATORY ASSETS AND LIABILITIES
The following regulatory assets and liabilities were reflected on our balance sheets at September 30, 2021 and December 31, 2020. For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2020 Annual Report on Form 10-K.
| | | | | | | | | | | | | | |
| (in millions) | | September 30, 2021 | | December 31, 2020 |
| Regulatory assets | | | | |
| Finance leases | | $ | 1,021.9 | | | $ | 985.5 | |
| Plant retirements | | 661.1 | | | 669.8 | |
| Pension and OPEB costs | | 446.8 | | | 477.0 | |
| Income tax related items | | 388.7 | | | 392.6 | |
| SSR | | 131.6 | | | 135.6 | |
Securitization (1) | | 102.9 | | | 105.2 | |
| AROs | | 43.7 | | | 28.6 | |
| Other, net | | 12.4 | | | 9.0 | |
| Total regulatory assets | | $ | 2,809.1 | | | $ | 2,803.3 | |
| | | | |
| | | | |
| | | | |
| | | | |
| | | | |
(1)See Note 17, Variable Interest Entities, for more information.
| | | | | | | | |
| 09/30/2021 Form 10-Q | 10 | Wisconsin Electric Power Company |
| | | | | | | | | | | | | | |
| (in millions) | | September 30, 2021 | | December 31, 2020 |
| Regulatory liabilities | | | | |
| Income tax related items | | $ | 742.7 | | | $ | 806.7 | |
| Removal costs | | 694.0 | | | 677.2 | |
| Pension and OPEB benefits | | 129.4 | | | 132.1 | |
Derivatives (1) | | 106.6 | | | 5.9 | |
| Electric transmission costs | | 64.1 | | | 61.7 | |
| Uncollectible expense | | 25.8 | | | 15.5 | |
| Other, net | | 14.8 | | | 8.8 | |
| Total regulatory liabilities | | $ | 1,777.4 | | | $ | 1,707.9 | |
| | | | |
| Balance sheet presentation | | | | |
| Other current liabilities | | $ | — | | | $ | 4.2 | |
| Regulatory liabilities | | 1,777.4 | | | 1,703.7 | |
| Total regulatory liabilities | | $ | 1,777.4 | | | $ | 1,707.9 | |
(1) For most energy-related physical and financial contracts that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. See Note 13, Derivative Instruments, for more information.
NOTE 5—PROPERTY, PLANT, AND EQUIPMENT
During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into our PSB. The damage to the building from the flooding and steam was extensive and requires significant repairs and restorations. As of September 30, 2021, we have incurred $93.5 million after tax), whichof costs related to these repairs and restorations. We received $20.0 million of insurance proceeds in 2020 to cover a portion of these costs and $61.0 million was recorded in accounts receivable on our balance sheet as of September 30, 2021 for future insurance recoveries. The remaining $12.5 million of costs were included in other operation and maintenance onexpense in 2020 as we do not intend to seek recovery of these costs.
In June 2021, we received approval from the PSCW to restore the PSB and to defer the project costs, net of insurance proceeds, as a component of rate base. As such, we do not currently expect a significant impact to our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. Thefuture 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,although 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 includedmay experience differences between periods in the sale weretiming of cash flows, we also do not materialcurrently expect a significant impact to our long-term cash flows from this event.
NOTE 6—ASSET RETIREMENT OBLIGATIONS
We have recorded AROs primarily for asbestos abatement at certain generation and therefore, were not presented as heldsubstation facilities, the removal and dismantlement of biomass generation facilities, the dismantling of wind generation projects, and the closure of coal combustion residual landfills at our generation facilities.
On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the nine months ended September 30, 2021:
| | | | | | | | | | | |
| (in millions) | | Nine Months Ended September 30, 2021 | |
| Balance as of January 1, 2021 | | $ | 54.5 | | |
| Accretion | | 1.2 | | |
| Revisions to estimated cash flows | | 16.7 | | (1) |
| Liabilities settled | | (1.1) | | |
| Balance as of September 30, 2021 | | $ | 71.3 | | |
(1) This increase was primarily due to revisions made to estimated cash flows 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 inlegal requirement to dismantle, at retirement, our corporate strategy and did not have a major effect on our operations and financial results.wind generation projects.
|
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09/30/20172021 Form 10-Q | 611 | Wisconsin Electric Power Company |
NOTE 3—PROPERTY, PLANT, AND EQUIPMENT
In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MWs of natural gas-fired generation in the Upper Peninsula of Michigan. Upon receiving this approval, early retirement of the PIPP generating units became probable. The new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. The net book value of these units was $203.0 million at September 30, 2017. 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, for more information regarding UMERC’s application.
NOTE 4—7—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 20162020 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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09/30/2017 Form 10-Q | 7 | Wisconsin Electric Power Company |
NOTE 5—8—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, 2021 | | December 31, 2020 |
| Commercial paper | | | | |
| Amount outstanding | | $ | 22.5 | | | $ | 292.0 | |
| Weighted-average interest rate on amounts outstanding | | 0.15 | % | | 0.21 | % |
|
| | | | | | | | |
| (in millions, except percentages) | | September 30, 2017 | | December 31, 2016 |
| Commercial paper | | | | |
| Amount outstanding | | $ | 59.0 |
| | $ | 159.0 |
|
| Weighted-average interest rate on amounts outstanding | | 1.19 | % | | 0.87 | % |
Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2017,2021 was $37.7$190.6 million with a weighted-average interest rate during the period of 1.04%0.17%.
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 |
| Revolving credit facility * | | December 2020 | | $ | 500.0 |
|
| | | | | |
| Less: | | | | |
|
| Letters of credit issued inside credit facility | | | | $ | 26.2 |
|
| Commercial paper outstanding | | | | 59.0 |
|
| | | | | |
| Available capacity under existing agreement | | | | $ | 414.8 |
|
| | | | | | | | | | | | | | |
*(in millions) | In October 2017, we extended the maturity of our | Maturity | | September 30, 2021 |
Revolving credit facility to October 2022.(1) | | September 2026 | | $ | 500.0 | |
| | | | |
| Less: | | | | |
| Letters of credit issued inside credit facility | | | | $ | 1.0 | |
| Commercial paper outstanding | | | | 22.5 | |
| Available capacity under existing credit facility | | | | $ | 476.5 | |
(1) In September 2021, we extended the maturity of our credit facility to September 2026.
NOTE 6—9—LONG-TERM DEBT
Wisconsin Electric Power Company
In June 2021, we issued $300.0 million of 1.70% Debentures due June 15, 2028, and used the net proceeds to redeem all $300.0 million outstanding of our 2.95% Debentures due September 15, 2021 at par.
WEPCo Environmental Trust Finance I, LLC
In May 2021, WEPCo Environmental Trust, a special purpose entity we formed, issued $118.8 million of 1.578% ETBs due December 15, 2035, and used the net proceeds to purchase environmental control property from us. Principal and interest will be paid semiannually, beginning December 15, 2021, and the ETBs are expected to be fully repaid by December 15, 2033. For additional information, see Note 17, Variable Interest Entities – WEPCo Environmental Trust Finance I, LLC.
| | | | | | | | |
| 09/30/2021 Form 10-Q | 12 | Wisconsin Electric Power Company |
NOTE 10—MATERIALS, SUPPLIES, AND INVENTORIES
Our inventory consisted of:
| | | | | | | | | | | | | | |
| (in millions) | | September 30, 2021 | | December 31, 2020 |
| Materials and supplies | | $ | 141.3 | | | $ | 136.5 | |
| Natural gas in storage | | 49.0 | | | 25.9 | |
| Fossil fuel | | 35.8 | | | 57.1 | |
| Total | | $ | 226.1 | | | $ | 219.5 | |
|
| | | | | | | | |
| (in millions) | | September 30, 2017 | | December 31, 2016 |
| Materials and supplies | | $ | 155.8 |
| | $ | 148.1 |
|
| Fossil fuel | | 93.5 |
| | 91.1 |
|
| Natural gas in storage | | 45.3 |
| | 31.8 |
|
| Total | | $ | 294.6 |
| | $ | 271.0 |
|
Substantially all materials and supplies, fossil fuel, and natural gas in storage, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.
NOTE 7—11—INCOME TAXES
The provision for income taxes 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:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2020 |
| (in millions) | | Amount | | Effective Tax Rate | | Amount | | Effective Tax Rate |
| Statutory federal income tax | | $ | 32.3 | | | 21.0 | % | | $ | 28.1 | | | 21.0 | % |
| State income taxes net of federal tax benefit | | 9.8 | | | 6.4 | % | | 8.6 | | | 6.4 | % |
| Federal excess deferred tax amortization – Wisconsin unprotected | | (12.5) | | | (8.1) | % | | (11.4) | | | (8.5) | % |
| Federal excess deferred tax amortization | | (6.8) | | | (4.4) | % | | (6.2) | | | (4.7) | % |
| PTCs | | (1.9) | | | (1.2) | % | | (2.9) | | | (2.2) | % |
| Domestic production activities deferral | | 1.9 | | | 1.2 | % | | (0.9) | | | (0.7) | % |
| | | | | | | | |
| Other | | 1.6 | | | 0.9 | % | | 3.8 | | | 3.0 | % |
| Total income tax expense | | $ | 24.4 | | | 15.8 | % | | $ | 19.1 | | | 14.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2020 |
| (in millions) | | Amount | | Effective Tax Rate | | Amount | | Effective Tax Rate |
| Statutory federal income tax | | $ | 82.2 | | | 21.0 | % | | $ | 72.2 | | | 21.0 | % |
| State income taxes net of federal tax benefit | | 25.0 | | | 6.4 | % | | 22.1 | | | 6.4 | % |
| Federal excess deferred tax amortization – Wisconsin unprotected | | (35.8) | | | (9.1) | % | | (34.3) | | | (10.0) | % |
| Federal excess deferred tax amortization | | (19.4) | | | (5.0) | % | | (18.6) | | | (5.4) | % |
| PTCs | | (5.7) | | | (1.5) | % | | (8.6) | | | (2.5) | % |
| Domestic production activities deferral | | 5.3 | | | 1.4 | % | | 2.5 | | | 0.7 | % |
| Other | | 4.5 | | | 1.1 | % | | 4.5 | | | 1.3 | % |
| Total income tax expense | | $ | 56.1 | | | 14.3 | % | | $ | 39.8 | | | 11.5 | % |
The effective tax rates of 15.8% and 14.3% for the three and nine months ended September 30, 2021, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In accordance with the rate order received from the PSCW in December 2019, we are amortizing the unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to our customers. In addition, the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, and PTCs drove a decrease in the effective tax rate. These items were partially offset by state income taxes.
The effective tax rates of 14.3% and 11.5% for the three and nine months ended September 30, 2020, respectively, differ from the United States statutory federal income tax rate of 21%, primarily due to the recognition of certain unprotected deferred tax benefits created as a result of the Tax Legislation. In addition, the impact of the protected benefits associated with the Tax Legislation, as discussed in more detail below, and PTCs drove a decrease in the effective tax rate. These items were partially offset by state income taxes.
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| 09/30/2021 Form 10-Q | 13 | Wisconsin Electric Power Company |
The Tax Legislation required us to remeasure the deferred income taxes at our utility segment and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above).
See Note 20, Regulatory Environment, for more information on unprotected tax benefits.
NOTE 12—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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09/30/2017 Form 10-Q | 8 | Wisconsin Electric Power Company |
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 inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developedinternally-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, 2021 |
| (in millions) | | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative assets | | | | | | | | |
| Natural gas contracts | | $ | 60.7 | | | $ | 3.3 | | | $ | — | | | $ | 64.0 | |
| FTRs | | — | | | — | | | 1.6 | | | 1.6 | |
| Coal contracts | | — | | | 28.8 | | | — | | | 28.8 | |
| Total derivative assets | | $ | 60.7 | | | $ | 32.1 | | | $ | 1.6 | | | $ | 94.4 | |
| | | | | | | | |
| Derivative liabilities | | | | | | | | |
| Natural gas contracts | | $ | — | | | $ | 0.4 | | | $ | — | | | $ | 0.4 | |
| | | | | | | | |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | | |
| | | September 30, 2017 |
| (in millions) | | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative assets | | | | | | | | |
| Natural gas contracts | | $ | 0.9 |
| | $ | 0.1 |
| | $ | — |
| | $ | 1.0 |
|
| Petroleum products contracts | | 0.8 |
| | — |
| | — |
| | 0.8 |
|
| FTRs | | — |
| | — |
| | 3.7 |
| | 3.7 |
|
| Coal contracts | | — |
| | 0.9 |
| | — |
| | 0.9 |
|
| Total derivative assets | | $ | 1.7 |
| | $ | 1.0 |
| | $ | 3.7 |
| | $ | 6.4 |
|
| | | | | | | | | |
| Derivative liabilities | | | | | | | | |
| Natural gas contracts | | $ | 0.3 |
| | $ | 0.1 |
| | $ | — |
| | $ | 0.4 |
|
| Coal contracts | | — |
| | 1.2 |
| — |
| — |
| | 1.2 |
|
| Total derivative liabilities | | $ | 0.3 |
| | $ | 1.3 |
| | $ | — |
| | $ | 1.6 |
|
|
| | | | | | | | | | | | | | | | |
| | | December 31, 2016 |
| (in millions) | | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative assets | | | | | | | | |
| Natural gas contracts | | $ | 6.0 |
| | $ | 0.8 |
| | $ | — |
| | $ | 6.8 |
|
| Petroleum products contracts | | 0.2 |
| | — |
| | — |
| | 0.2 |
|
| FTRs | | — |
| | — |
| | 3.1 |
| | 3.1 |
|
| Coal contracts | | — |
| | 1.9 |
| | — |
| | 1.9 |
|
| Total derivative assets | | $ | 6.2 |
| | $ | 2.7 |
| | $ | 3.1 |
| | $ | 12.0 |
|
| | | | | | | | | |
| Derivative liabilities | | | | | | | |
|
| Natural gas contracts | | $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
|
| Petroleum products contracts | | 0.1 |
| | — |
| | — |
| | 0.1 |
|
| Coal contracts | | — |
| | 0.5 |
| | — |
| | 0.5 |
|
| Total derivative liabilities | | $ | 0.2 |
| | $ | 0.5 |
| | $ | — |
| | $ | 0.7 |
|
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| 09/30/2021 Form 10-Q | 14 | Wisconsin Electric Power Company |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2020 |
| (in millions) | | Level 1 | | Level 2 | | Level 3 | | Total |
| Derivative assets | | | | | | | | |
| Natural gas contracts | | $ | 3.0 | | | $ | 0.8 | | | $ | — | | | $ | 3.8 | |
| FTRs | | — | | | — | | | 1.1 | | | 1.1 | |
| Coal contracts | | — | | | 1.4 | | | — | | | 1.4 | |
| Total derivative assets | | $ | 3.0 | | | $ | 2.2 | | | $ | 1.1 | | | $ | 6.3 | |
| | | | | | | | |
| Derivative liabilities | | | | | | | | |
| Natural gas contracts | | $ | 2.9 | | | $ | 0.6 | | | $ | — | | | $ | 3.5 | |
| Coal contracts | | — | | | 0.6 | | | — | | | 0.6 | |
| Total derivative liabilities | | $ | 2.9 | | | $ | 1.2 | | | $ | — | | | $ | 4.1 | |
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 and Operating Reserves Markets.
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09/30/2017 Form 10-Q | 9 | Wisconsin Electric Power Company |
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 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
| Balance at the beginning of the period | | $ | 2.6 | | | $ | 2.8 | | | $ | 1.1 | | | $ | 1.5 | |
| Purchases | | — | | | — | | | 3.0 | | | 3.1 | |
| Settlements | | (1.0) | | | (0.9) | | | (2.5) | | | (2.7) | |
| Balance at the end of the period | | $ | 1.6 | | | $ | 1.9 | | | $ | 1.6 | | | $ | 1.9 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2017 | | 2016 | | 2017 | | 2016 |
| Balance at the beginning of the period | | $ | 6.0 |
| | $ | 7.5 |
| | $ | 3.1 |
| | $ | 1.6 |
|
| Purchases | | — |
| | — |
| | 6.9 |
| | 8.1 |
|
| Settlements | | (2.3 | ) | | (2.1 | ) | | (6.3 | ) | | (4.3 | ) |
| Balance at the end of the period | | $ | 3.7 |
| | $ | 5.4 |
| | $ | 3.7 |
| | $ | 5.4 |
|
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that arewere not recorded at fair value:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2021 | | December 31, 2020 |
| (in millions) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Preferred stock | | $ | 30.4 | | | $ | 30.5 | | | $ | 30.4 | | | $ | 32.3 | |
| Long-term debt, including current portion | | 2,875.6 | | | 3,445.1 | | | 2,761.2 | | | 3,451.8 | |
|
| | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| (in millions) | | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| Preferred stock | | $ | 30.4 |
| | $ | 29.6 |
| | $ | 30.4 |
| | $ | 28.8 |
|
| Long-term debt, including current portion | | 2,661.7 |
| | 2,946.7 |
| | 2,661.1 |
| | 2,923.4 |
|
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 our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
NOTE 8—13—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.
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| 09/30/2021 Form 10-Q | 15 | Wisconsin Electric Power Company |
None of our derivatives are designated as hedging instruments. On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. Derivative assets and liabilities not shown separately on our balance sheets are included in the other current and other long-term line items. The following table shows our derivative assets and derivative liabilities:liabilities.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2021 | | December 31, 2020 |
| (in millions) | | Derivative Assets | | Derivative Liabilities | | Derivative Assets | | Derivative Liabilities |
| Current | | | | | | | | |
| Natural gas contracts | | $ | 59.3 | | | $ | 0.4 | | | $ | 3.7 | | | $ | 3.2 | |
| FTRs | | 1.6 | | | — | | | 1.1 | | | — | |
| Coal contracts | | 24.6 | | | — | | | 1.4 | | | 0.5 | |
| Total current | | 85.5 | | | 0.4 | | | 6.2 | | | 3.7 | |
| | | | | | | | |
| Long-term | | | | | | | | |
| Natural gas contracts | | 4.7 | | | — | | | 0.1 | | | 0.3 | |
| Coal contracts | | 4.2 | | | — | | | — | | | 0.1 | |
| Total long-term | | 8.9 | | | — | | | 0.1 | | | 0.4 | |
| Total | | $ | 94.4 | | | $ | 0.4 | | | $ | 6.3 | | | $ | 4.1 | |
|
| | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| (in millions) | | Derivative Assets | | Derivative Liabilities | | Derivative Assets | | Derivative Liabilities |
| Other current | | | | | | | | |
| Natural gas contracts | | $ | 0.8 |
| | $ | 0.4 |
| | $ | 6.3 |
| | $ | 0.1 |
|
| Petroleum products contracts | | 0.8 |
| | — |
| | 0.2 |
| | 0.1 |
|
| FTRs | | 3.7 |
| | — |
| | 3.1 |
| | — |
|
| Coal contracts | | 0.6 |
| | 0.7 |
| | 1.5 |
| | 0.5 |
|
| Total other current * | | $ | 5.9 |
| | $ | 1.1 |
| | $ | 11.1 |
| | $ | 0.7 |
|
| | | | | | | | | |
| Other long-term | | | | | | | | |
| Natural gas contracts | | $ | 0.2 |
| | $ | — |
| | $ | 0.5 |
| | $ | — |
|
| Coal contracts | | 0.3 |
| | 0.5 |
| | 0.4 |
| | — |
|
| Total other long-term * | | 0.5 |
| | 0.5 |
| | 0.9 |
| | — |
|
| Total | | $ | 6.4 |
| | $ | 1.6 |
| | $ | 12.0 |
| | $ | 0.7 |
|
| |
* | 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. |
|
| | |
09/30/2017 Form 10-Q | 10 | Wisconsin Electric Power Company |
Realized gains (losses) on derivative instrumentsderivatives 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, 2021 | | Three Months Ended September 30, 2020 |
| (in millions) | | Volumes | | Gains | | Volumes | | Gains (Losses) |
| Natural gas contracts | | 15.9 Dth | | $ | 16.2 | | | 12.7 Dth | | $ | (4.1) | |
| FTRs | | 5.4 MWh | | 1.1 | | | 5.8 MWh | | 0.8 | |
| Total | | | | $ | 17.3 | | | | | $ | (3.3) | |
| | | | | | | | |
| | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2020 |
| (in millions) | | Volumes | | Gains | | Volumes | | Gains (Losses) |
| Natural gas contracts | | 51.5 Dth | | $ | 14.6 | | | 45.8 Dth | | $ | (15.4) | |
| FTRs | | 16.5 MWh | | 7.6 | | | 16.0 MWh | | 2.1 | |
| Total | | | | $ | 22.2 | | | | | $ | (13.3) | |
|
| | | | | | | | | | | | |
| | | 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 |
| (in millions) |
| Volumes |
| Gains (Losses) |
| Volumes |
| Gains (Losses) |
| Natural gas contracts |
| 17.8 Dth |
| $ | 0.2 |
|
| 27.0 Dth |
| $ | (12.5 | ) |
| Petroleum products contracts |
| 13.9 gallons |
| (1.4 | ) |
| 7.5 gallons |
| (1.9 | ) |
| FTRs |
| 21.2 MWh |
| 6.9 |
|
| 18.6 MWh |
| 6.8 |
|
| Total |
| |
| $ | 5.7 |
|
| |
| $ | (7.6 | ) |
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, 2017,2021 and December 31, 2020, we had posted cash collateral of $1.3$4.0 million and $6.7 million, respectively. These amounts were recorded on our balance sheets in our margin accounts, and at December 31, 2016,other current assets. At September 30, 2021, we had also received cash collateral of $3.4 million in our margin accounts. On$38.8 million. This amount was recorded on our balance sheets, cash collateral provided to others is reflected in other current assets and cash collateral received is reflectedsheet in other current liabilities.
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2021 | | December 31, 2020 |
| (in millions) | | Derivative Assets | | Derivative Liabilities | | Derivative Assets | | Derivative Liabilities |
| Gross amount recognized on the balance sheet | | $ | 94.4 | | | $ | 0.4 | | | $ | 6.3 | | | $ | 4.1 | |
| Gross amount not offset on the balance sheet | | (38.9) | | (1) | (0.1) | | | (2.9) | | | (2.9) | |
| Net amount | | $ | 55.5 | | | $ | 0.3 | | | $ | 3.4 | | | $ | 1.2 | |
(1) Includes cash collateral received of $38.8 million.
NOTE 14—GUARANTEES
As of September 30, 2021, we had $26.0 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us, which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets.
|
| | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| (in millions) | | Derivative Assets | | Derivative Liabilities | | Derivative Assets | | Derivative Liabilities |
| Gross amount recognized on the balance sheet | | $ | 6.4 |
| | $ | 1.6 |
| | $ | 12.0 |
| | $ | 0.7 |
|
| Gross amount not offset on the balance sheet | | (0.4 | ) | | (0.4 | ) | | (3.6 | ) | * | (0.2 | ) |
| Net amount | | $ | 6.0 |
| | $ | 1.2 |
| | $ | 8.4 |
| | $ | 0.5 |
|
| | | | | | | | |
*09/30/2021 Form 10-Q | Includes cash collateral received of $3.4 million.16 | Wisconsin Electric Power Company |
NOTE 9—15—EMPLOYEE BENEFITS
The following tables show the components of net periodic pension and OPEB costsbenefit cost (credit) for our benefit plans:plans.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Pension Benefits |
| | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
| Service cost | | $ | 3.6 | | | $ | 3.2 | | | $ | 10.8 | | | $ | 9.4 | |
| Interest cost | | 7.8 | | | 9.5 | | | 23.3 | | | 28.4 | |
| Expected return on plan assets | | (17.6) | | | (17.4) | | | (52.7) | | | (52.1) | |
| Loss on plan settlement | | — | | | 2.1 | | | — | | | 2.1 | |
| Amortization of prior service credit | | — | | | (0.1) | | | (0.1) | | | (0.1) | |
| Amortization of net actuarial loss | | 10.5 | | | 9.4 | | | 31.5 | | | 28.3 | |
| Net periodic benefit cost | | $ | 4.3 | | | $ | 6.7 | | | $ | 12.8 | | | $ | 16.0 | |
|
| | | | | | | | | | | | | | | | |
| | | Pension Costs |
| | | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2017 | | 2016 | | 2017 | | 2016 |
| Service cost | | $ | 3.0 |
| | $ | 2.7 |
| | $ | 9.1 |
| | $ | 7.9 |
|
| Interest cost | | 11.8 |
| | 12.4 |
| | 35.3 |
| | 37.3 |
|
| Expected return on plan assets | | (19.2 | ) | | (19.5 | ) | | (57.5 | ) | | (58.3 | ) |
| Loss on plan settlement | | 0.7 |
| | — |
| | 3.5 |
| | — |
|
| Amortization of prior service cost | | 0.3 |
| | 0.4 |
| | 0.9 |
| | 1.2 |
|
| Amortization of net actuarial loss | | 8.8 |
| | 8.1 |
| | 26.5 |
| | 24.3 |
|
| Net periodic benefit cost | | $ | 5.4 |
| | $ | 4.1 |
| | $ | 17.8 |
| | $ | 12.4 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | OPEB Benefits |
| | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | 2021 | | 2020 |
| Service cost | | $ | 1.1 | | | $ | 1.1 | | | $ | 3.2 | | | $ | 3.2 | |
| Interest cost | | 1.3 | | | 1.7 | | | 4.0 | | | 5.1 | |
| Expected return on plan assets | | (4.2) | | | (4.0) | | | (12.6) | | | (11.8) | |
| Amortization of prior service credit | | (0.3) | | | (0.2) | | | (0.9) | | | (0.5) | |
| Amortization of net actuarial gain | | (2.7) | | | (2.6) | | | (8.2) | | | (7.9) | |
| Net periodic benefit credit | | $ | (4.8) | | | $ | (4.0) | | | $ | (14.5) | | | $ | (11.9) | |
|
| | |
09/30/2017 Form 10-Q | 11 | Wisconsin Electric Power Company |
|
| | | | | | | | | | | | | | | | |
| | | 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 |
|
During the nine months ended September 30, 2017,2021, we made contributions and payments of $3.9$3.6 million related to our pension plans and $2.0 millionan insignificant amount related to our OPEB plans. We do not expect to make any significant contributions or payments of $1.3 million related to our pension plans and $2.5 million related to our OPEB plans during the remainder of 2017,2021. This is 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 result in the recognition of a gain or loss. The following table shows changes to our investment in ATC:
|
| | | | | | | | | | | | |
| | | 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 |
|
See Note 13, Related Parties, for more information on transactions with ATC.
NOTE 11—16—SEGMENT INFORMATION
We use operatingnet income attributed to common shareholder to measure segment profitability and to allocate resources to our businesses. At September 30, 2017,2021, we reported two2 segments, which are described below.
Our utility segment includes our electric utility operations, including steam operations, and our 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 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 includeWisconsin. In addition, our steam operations which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Milwaukee.
•Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers andas well as the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin.
OurNo significant items were reported in the other segment includes Bostco, our non-utility subsidiary that developed and invested in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 2, Dispositions, for more information. Prior 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.
|
| | |
09/30/2017 Form 10-Q | 12 | Wisconsin Electric Power Company |
The following tables show summarized financial information related to our reportable segments forduring the three and nine months ended September 30, 20172021 and 2016:2020.
|
| | | | | | | | | | | | |
| (in millions) | | Utility | | Other | | Wisconsin Electric Power Company Consolidated |
| Three Months Ended September 30, 2017 | | | | | | |
| Operating revenues | | $ | 943.8 |
| | $ | — |
| | $ | 943.8 |
|
| Other operation and maintenance | | 332.6 |
| | — |
| | 332.6 |
|
| Depreciation and amortization | | 83.0 |
| | — |
| | 83.0 |
|
| Operating income | | 163.4 |
| | — |
| | 163.4 |
|
| Interest expense | | 29.3 |
| | — |
| | 29.3 |
|
|
| | | | | | | | | | | | |
| (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 |
|
NOTE 12—17—VARIABLE INTEREST ENTITIES
The primary beneficiary of a variable interest entityVIE must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.VIEs.
We assess our relationships with potential variable interest entities,VIEs, 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.investments. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support,
| | | | | | | | |
| 09/30/2021 Form 10-Q | 17 | Wisconsin Electric Power Company |
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.
WEPCo Environmental Trust Finance I, LLC
|
| | |
09/30/2017 Form 10-Q | 13 | Wisconsin Electric Power Company |
$100 million of undepreciated environmental control costs related to our retired Pleasant Prairie power plant, the carrying costs accrued on the $100 million during the securitization process, and the related financing fees. The financing order also authorized us to form WEPCo Environmental Trust, a bankruptcy-remote special purpose entity, for the sole purpose of issuing ETBs to recover the costs approved in the financing order. WEPCo Environmental Trust is our wholly-owned subsidiary.
American Transmission Company
As of December 31, 2016, we owned approximately 23% of ATC,In May 2021, WEPCo Environmental Trust issued ETBs and used the proceeds to acquire environmental control property from us. The environmental control property is recorded as a for-profit,regulatory asset on our balance sheets and includes the right to impose, collect, and receive a non-bypassable environmental control charge from our retail electric transmission company regulateddistribution customers until the ETBs are paid in full and all financing costs have been recovered. The ETBs are secured by the FERCenvironmental control property. Cash collections from the environmental control charge, and certain state regulatory commissions. However, effective January 1, 2017,funds on deposit in trust accounts, are the sole source of funds to satisfy the debt obligation. The bondholders have no recourse to us or any of our affiliates. See Note 9, Long-Term Debt, for more information on the ETBs.
We act as the servicer of the environmental control property on behalf of WEPCo Environmental Trust and are responsible for metering, calculating, billing, and collecting the environmental control charge. As necessary, we transferred our investment in ATCare authorized to another subsidiaryimplement periodic adjustments of WEC Energy Group. ATC wasthe environmental control charge. The adjustments are designed to ensure the timely payment of principal, interest, and other ongoing financing costs. We remit all collections of the environmental control charge to an indenture trustee of WEPCo Environmental Trust.
WEPCo Environmental Trust is a variable interest entity, but consolidation was not required sinceVIE primarily because its equity capitalization is insufficient to support its operations. As described above, we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC'simpact WEPCo Environmental Trust's economic performance. At December 31, 2016,Therefore, we accounted for ATC as an equity method investment. See Note 10, Investment in American Transmission Company, for more information.are considered the primary beneficiary of WEPCo Environmental Trust, and consolidation is required.
Purchased The following table summarizes the impact of WEPCo Environmental Trust on our balance sheet.
| | | | | | | | | | |
| (in millions) | | September 30, 2021 | | |
| Assets | | | | |
| Other current assets (restricted cash) | | $ | 4.6 | | | |
| Regulatory assets | | 102.9 | | | |
| Other long-term assets (restricted cash) | | 0.6 | | | |
| | | | |
| Liabilities | | | | |
| Current portion of long-term debt | | 8.5 | | | |
| Other current liabilities (accrued interest) | | 0.7 | | | |
| Long-term debt | | 107.0 | | | |
Power Purchase Agreement
We have a purchased power purchase agreement that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capitalfinance lease. The agreement includes no minimum energy requirements over the remaining term of approximately five years.one year. 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 purchase agreement.
We have approximately $74.9$6.5 million of required capacity payments over the remaining term of this agreement. We believe that the required leasecapacity payments under this contract will continue to be recoverable in rates. Total capacityrates, and lease payments under this contract for the nine months ended September 30, 2017 and 2016 were $13.5 million and $40.5 million, respectively. Ourour maximum exposure to loss is limited to thethese capacity payments under the contract.payments.
NOTE 13—RELATED PARTIES
We routinely enter into transactions with related parties, including WEC Energy Group, its 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 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.
|
| | | | | | | |
09/30/20172021 Form 10-Q | 1418 | Wisconsin Electric Power Company |
Our balance sheets included the following receivables and payables related to transactions entered into with ATC:
|
| | | | | | | | |
| (in millions) | | September 30, 2017 | | December 31, 2016 |
| Accounts receivable | | | | |
| Services provided to ATC | | $ | 1.0 |
| | $ | 1.1 |
|
| Accounts payable | | | | |
| Services received from ATC | | 20.2 |
| | 20.0 |
|
The following table shows activity associated with our related party transactions:
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30 | | Nine Months Ended September 30 |
| (in millions) | | 2017 | | 2016 | | 2017 | | 2016 |
| Lease agreements | | |
| | |
| | |
| | |
|
Lease payments to We Power (1) | | $ | 104.3 |
| | $ | 91.4 |
| | $ | 315.4 |
| | $ | 308.8 |
|
| Construction work in progress billed to We Power | | 5.9 |
| | 10.8 |
| | 31.1 |
| | 28.5 |
|
Transactions with WBS (2) | | | | | | | | |
Billings to WBS (3) | | 60.2 |
| | 46.2 |
| | 177.2 |
| | 156.0 |
|
Billings from WBS (4) | | 49.4 |
| | 40.4 |
| | 152.1 |
| | 266.0 |
|
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 |
|
| Billings from WPS | | 1.4 |
| | 1.4 |
| | 3.6 |
| | 1.9 |
|
| Transactions with WG | | | | |
| | | | |
| Natural gas purchases from WG | | 1.4 |
| | 1.3 |
| | 4.0 |
| | 4.0 |
|
| 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) | | | | | | | | |
| Electric sales to UMERC | | 9.0 |
| | — |
| | 23.1 |
| | — |
|
Billings to UMERC (2) | | 18.7 |
| | — |
| | 52.6 |
| | — |
|
Billings from UMERC (2) | | 14.6 |
| | — |
| | 45.1 |
| | — |
|
Transactions with Bluewater (6) | | | | | | | | |
| Storage service fees | | 1.4 |
| | — |
| | 1.4 |
| | — |
|
| Transactions with ATC | | | | | | | | |
| Charges to ATC for services and construction | | 2.9 |
| | 2.1 |
| | 8.1 |
| | 6.6 |
|
| Charges from ATC for network transmission services | | 60.4 |
| | 61.7 |
| | 181.1 |
| | 188.3 |
|
| Refund from ATC per FERC ROE order | | — |
| | — |
| | (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 nine months ended September 30, 2017. There were no transfers of assets to WBS or 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. |
| |
(4)
| Includes $9.1 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. There were no benefit-related liabilities transferred to WBS for the three and nine months ended September 30, 2017. |
| |
(5)
| UMERC became operational effective January 1, 2017. See below for more information. |
| |
(6)
| The 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 (including the related deferred income tax liabilities) transferred to UMERC from us was $60.0 million. This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under 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 obtains its energy and capacity requirements to supply its customers through power purchase agreements with us and WPS.
Parent Company's Acquisition of Natural Gas Storage Facilities in Michigan
On June 30, 2017, our parent company 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 Bluewater to take the allocated storage. See Note 16, Regulatory Environment, for more information.
NOTE 14—18—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, 2017,2021, were $10,094.8 million.approximately $8.9 billion.
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,sulfur dioxide, NOx, fine particulates, mercury, and GHGs; water intake and discharges; disposalmanagement 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.Ozone
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 nonattainmentThe 2015 ozone standard lowered the 8-hour limit for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet.ground-level ozone. In January 2017,December 2020, the EPA released preliminary interstatecompleted its 5-year review of the ozone transport modelingstandard and issued a final decision to retain, without any changes, the existing 2015 standard. Under Executive Order 13990, the Biden Administration ordered that all agencies review existing regulations, orders, guidance documents, policies, and similar actions promulgated, issued, or adopted between January 20, 2017 and January 20, 2021. Consequently, the December 2020 decision to retain the 2015 ozone standards with no changes is currently under review by the EPA.
The EPA issued final nonattainment area designations for the 2015 ozone NAAQS.standard in April 2018. The following counties within our service territory were designated as partial nonattainment: Kenosha, Sheboygan, and Northern Milwaukee/Ozaukee. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. A decision was issued in July 2020 remanding the rule to the EPA is currently scheduledfor further evaluation. As a result of the July 2020 remand, in June 2021, the EPA published its final action to finalize designations later in 2017. Forrevise the boundaries for 13 counties associated with 6 nonattainment areas, including several in Wisconsin. Under the statenew designations, all of Milwaukee and Ozaukee counties are now listed as nonattainment and portions of Racine, Waukesha, and Washington counties have been added to the nonattainment area. Additionally, the Chicago, Illinois, Indiana, and Wisconsin nonattainment area now includes an expanded portion of Kenosha county, and the partial nonattainment area of Sheboygan county has also been expanded. Preliminary 2019-2021 monitoring data indicates that the Milwaukee and Sheboygan nonattainment areas will havelikely be adjusted to develop a state implementation plan"moderate" nonattainment for the 2015 standard.
In February 2021, the WDNR proposed draft revisions to bring the areas back into attainment. We will be requiredWisconsin Administrative Code to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying withadopt the 2015 ozone NAAQS untilstandard and incorporate by reference the designations are finalfederal air pollution monitoring requirements related to the NAAQS. The Natural Resources Board adopted the rule as proposed during their June 2021 meeting and until the state prepares a draft attainment plan.
Although we are stillrule is now in the process of reviewing and determining potential impacts resulting from this rule, welegislative review. We believe that we are well positioned to meet the requirements associated with the 2015 ozone standard and do not expect to incur significant costs to comply.comply with associated state or federal rules.
Particulate Matter
In addition to the 2015 ozone standard, in December 2020, the EPA completed its 5-year review of the 2012 standard for particulate matter, including fine particulate matter. The EPA determined that no revisions were necessary to the current standard. This determination was also subject to review under Executive Order 13990 and in June 2021, the EPA announced it would reconsider the
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| 09/30/2021 Form 10-Q | 19 | Wisconsin Electric Power Company |
December 2020 decision. Under the Biden Administration's policy review, the EPA concluded that the scientific evidence and information from the December 2020 determination supports revising the level of the annual standard for the particulate matter NAAQS to below the current level of 12 micrograms per cubic meter, while retaining the 24-hour standard. A proposed rule-making is expected in summer 2022, and a final rule is expected in spring 2023. All counties within our service territory are in attainment with the current 2012 standards.
Climate Change
In 2015, the EPA issued a finalThe ACE 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 ineffective since September 2019, was vacated by the D.C. Circuit Court of Appeals in January 2021. The ACE rule replaced the Clean Power Plan and provided existing coal-fired generating units with standards for achieving GHG emission reductions. In a memorandum issued to the extentEPA regional administrators in February 2021, the EPA stated that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court decision meant that no existing rule regulates GHG emissions from electric generating units. The EPA is currently reviewing its options for such regulations and has signaled that a draft rule will not be ready until 2022 at the earliest. In October 2021, the Supreme Court agreed to review the D.C. Circuit Court's ruling vacating the EPA's ACE rule. The Supreme Court will review a number of Appeals heard one caseissues regarding the scope of the EPA's regulatory authority to utilize Section 111(d) of the CAA to address CO2 emissions. Arguments are expected to take place in September 2016, and the other case is still pending. In April 2017, pursuant to motions madeearly 2022 with a decision expected by the summer of 2022.
In January 2021, the EPA finalized a rule to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The rule became effective in March 2021; however, the EPA asked 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 CPPvacate 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 ofremand the final rule, which was granted by the D.C. Circuit Court of Appeals in April 2021. Despite this uncertainty, WEC Energy Group continues to move forward on the ESG Progress Plan, which is heavily focused on reducing GHG emissions.
The ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fueled generation by 2025. By the end of 2020, WEC Energy Group was able to reduce nationwide GHGCO2 emissions from its electric generation fleet by 32% frommore than 50% below 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, WEC Energy Group announced new goals in May 2021. WEC Energy Group committed to a 60% reduction in carbon emissions from its electric generation fleet by 2025 and an 80% reduction by the end of this order2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by making operating refinements, retiring less efficient generating units, and related EPA review, as well asexecuting its capital plan. Over the ongoing legal proceedings,longer term, the timelinestarget for WEC Energy Group's generation fleet is net-zero carbon emissions by 2050. We have already retired approximately 1,500 MW of coal-fired generation since the GHG emission reduction goals and all other aspectsbeginning of 2018. As part of the CPP are uncertain. ESG Progress Plan, WEC Energy Group expects to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirements in 2023-2024 of OCPP Units 5-8.
WEC Energy Group continues to reduce methane emissions by improving its natural gas distribution system. WEC Energy Group's initial 2030 goal called for a 30% reduction in methane emissions from a 2011 baseline. Given advancements with renewable natural gas, WEC Energy Group set a new target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.
Cross-State Air Pollution Rule Update Rule Revision
In April 2017,2015, the EPA withdrewdetermined that several upwind states had failed to submit state implementation plans that addressed their "Good Neighbor" obligations (i.e., the proposed rule forstates projected NOx emissions significantly contribute to a continuing downwind nonattainment and/or maintenance problem); therefore, by statute, the EPA was required to issue 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.implementation plan. In October 2017,March 2021, the EPA issuedfinalized a notice of proposed rulemaking to repeal the CPP. The EPA is expected subsequently to issue an
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09/30/2017 Form 10-Q | 17 | Wisconsin Electric Power Company |
advanced notice of proposed rulemakingCSAPR update rule revision that will 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.
Notwithstanding the uncertain futurekeeps 9 of the CPP,21 CSAPR affected states (including Wisconsin) in a Group 2 NOx ozone season trading program and given current fuel and technology markets, we continue to evaluate opportunities and actionsfound that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our planthe prior CSAPR update is to work with our 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 ordersufficient to meet Wisconsin's "Good Neighbor" obligations. No further NOx reductions will be needed within these 9 states. This rule became effective June 29, 2021 and did not have a material impact on our CO2 reduction goal, such as increased usefinancial condition or results 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.operations.
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 whichthat requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the Best Technology Available (BTA)BTA for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake).impacts. The federal rule became effective in October 2014 and applies to all of our existing generating facilities with
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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 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 In 2016, the WDNR initiated a state rulemaking process to incorporate the federal Section 316(b) requirements into the Wisconsin Administrative Code. This new state rule became effective in June 2020, and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis takingthe WDNR will apply this rule when establishing BTA requirements for cooling water intake structures at existing facilities. These BTA requirements are incorporated into consideration several factors. Wisconsin Pollutant Discharge Elimination System permits for our facilities.
We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8. 8 and Valley power plant. Although we currently believe that existing technology at the Port Washington Generating Station satisfies the BTA requirements, a final determination will not be made until the discharge permit is renewed for this facility, which is expected to be in the second quarter of 2022.
During 2017 and 2018, we will continue to complete studies and evaluate optionsAs a result of past capital investments completed to address the EM BTA requirements at these plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements),Section 316(b) compliance, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. We provided information to the MDEQ about 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), the EM BTA requirements will be waived. We expect to submit this certification in November 2017.
We believe our fleet overall is well positioned to continue to meet the newthis regulation and do not expect to incur significant costs to comply with this regulation.additional compliance costs.
Steam Electric Effluent Limitation Guidelines
The EPA's final steam electric effluent guidelines (ELG)2015 ELG rule took effect in January 2016. In April 2017,2016 and was modified in 2020 to revise the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final ruletreatment technology requirements related to postpone the earliest compliance dates for the bottom ash transport waterBATW and wet flue gas desulfurization wastewater requirements.FGD wastewaters at existing facilities. This rule applies to wastewater discharges from ourcreated new requirements for several types of 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 certainwastewaters. The 2 new requirements into any reissuedthat affect us relate to discharge permits between 2018limits for BATW 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.wet FGD wastewater. 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, There will, however, need to be facility modifications to meet water permit requirements for the BATW systems at OC 7 and OC 8. Wastewater treatment system modifications also will be required for wet FGD discharges and site wastewater from the OCPP and ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require additional wastewater treatment retrofitsapproximately $100 million in capital investment. In February 2021, we applied for PSCW approval of this project.
In July 2021, the EPA announced that it intends to initiate rulemaking to revise the ELG Rule as well as installationmodified in 2020. The EPA has stated that the ELG Rule will continue to be implemented and enforced while the agency pursues this rulemaking process. The EPA plans to propose a revised rule in the fall of other equipment to minimize process water use.2022.
The final rule would phase in new or more stringent requirements related to limitsWaters 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 site and Pleasant Prairie facilities. 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 byUnited States
In September 2021, the new rule, and modifications would be required at OC 7, OC 8,EPA and the Pleasant Prairie units. WeUnited States Army Corps of Engineers together announced they have halted implementation of the April 2020 Navigable Waters Protection Rule and are beginning preliminary engineering for complianceinterpreting "Waters of the United States" consistent with the rulepre-2015 regulatory regime until further notice. The pre-2015 approach involves applying factors established through case law and estimateagency precedents to determine whether a total cost range of $55 millionwetland or surface drainage feature is subject to $75 million forfederal jurisdiction. We continue to move forward on company projects subject to federal permits and will monitor these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expectingactions to retire the plant. See the UMERC discussion in Note 16, Regulatory Environment, regarding thebetter understand potential retirement of PIPP.future impacts.
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 variousthe state jurisdictionsof Wisconsin in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.
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.
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We have established the following regulatory assets and reserves related tofor manufactured gas plant sites:
| | | | | | | | | | | | | | |
| (in millions) | | September 30, 2021 | | December 31, 2020 |
| Regulatory assets | | $ | 17.0 | | | $ | 18.5 | |
Reserves for future environmental remediation (1) | | 10.3 | | | 10.3 | |
|
| | | | | | | | |
| (in millions) | | September 30, 2017 | | December 31, 2016 |
| Regulatory assets | | $ | 27.7 |
| | $ | 29.9 |
|
| Reserves for future remediation | | 16.5 |
| | 19.0 |
|
(1)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 effectimpact on our financial condition or results of operations.
NOTE 15—19—SUPPLEMENTAL CASH FLOW INFORMATION
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 |
| Cash paid for interest, net of amount capitalized | | $ | 318.3 | | | $ | 324.1 | |
| Cash paid for income taxes, net | | 59.4 | | | 71.0 | |
| Significant non-cash investing and financing transactions: | | | | |
| Accounts payable related to construction costs | | 29.7 | | | 38.1 | |
Increase in receivable related to insurance proceeds for property damage (1) | | 58.3 | | | — | |
Receivable from a related party related to insurance proceeds for property damage (1) | | — | | | 20.0 | |
(1)See Note 5, Property, Plant, and Equipment, for information about a steam incident at our PSB.
The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of cash on deposit in financial institutions that is restricted to satisfy the requirements of certain debt agreements at WEPCo Environmental Trust. See Note 17, Variable Interest Entities, for more information.
The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets to the total of these amounts shown on the statements of cash flows:
| | | | | | | | | | | | | | |
| (in millions) | | September 30, 2021 | | December 31, 2020 |
| Cash and cash equivalents | | $ | 5.5 | | | $ | 7.2 | |
| Restricted cash included in other current assets | | 4.6 | | | — | |
| Restricted cash included in other long term assets | | 0.6 | | | — | |
| Cash, cash equivalents, and restricted cash | | $ | 10.7 | | | $ | 7.2 | |
NOTE 20—REGULATORY ENVIRONMENT
|
| | | | | | | | |
| | | Nine Months Ended September 30 |
| (in millions) | | 2017 | | 2016 |
| Cash (paid) for interest, net of amount capitalized | | $ | (62.1 | ) | | $ | (62.9 | ) |
| Cash (paid) for income taxes, net | | (60.7 | ) | | (0.1 | ) |
| Significant noncash transactions: | | | | |
| Accounts payable related to construction costs | | 8.5 |
| | 5.3 |
|
Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) | | 415.4 |
| | — |
|
Transfer of net assets to UMERC (1) | | 60.0 |
| | — |
|
| |
(1)
| See Note 13, Related Parties, for more information on these transactions. |
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(2)
| The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. |
Recovery of Natural Gas Costs
Due to the cold temperatures, wind, snow, and ice throughout the central part of the country during February 2021, the cost of gas purchased for our natural gas utility customers was temporarily driven significantly higher than our normal winter weather expectations. We have a regulatory mechanism in place for recovering all prudently incurred gas costs.
On March 23, 2021, we requested approval from the PSCW to recover approximately $54 million of natural gas costs in excess of the benchmark set in our gas cost recovery mechanism. On March 30, 2021, the PSCW approved our request and we recovered these excess costs over a period of three months, beginning in April 2021.
Coronavirus Disease – 2019
The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territory. In response to the COVID-19 pandemic, Wisconsin declared a public
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health emergency and issued a shelter-in-place order, which has since been lifted. In March 2020, the PSCW issued 2 orders in response to the COVID-19 pandemic. The first order required all public utilities in the state of Wisconsin, including us, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service.
NOTE 16—REGULATORY ENVIRONMENT
In the second order issued in March 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As we already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral only impacts the recovery of uncollectible expense for our commercial and industrial customers. See Note 3, Credit Losses, for information regarding changes to our allowance for credit losses. As of September 30, 2021, amounts deferred related to the COVID-19 pandemic were not significant. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings.
2018
In June 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 2020 order. Utilities were allowed to disconnect commercial and 2019industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. We resumed charging late payment fees in late August 2020. Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020.
Subsequent to the June 2020 order, the PSCW extended the moratorium on disconnections of residential customers until November 1, 2020. In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which began on November 1, 2020 and ended on April 15, 2021. Utilities were allowed to continue assessing late payment fees during the winter moratorium. On April 5, 2021, the PSCW issued a written order indicating that it would not extend the moratorium on disconnections further; therefore, utilities could begin disconnecting residential customers for non-payment after April 15, 2021. Utilities are required to offer a deferred payment arrangement to low-income residential customers prior to disconnecting service. The order also allowed us to resume charging late payment fees on the full balance of all outstanding arrears, regardless of the associated dates the service was provided, after April 15, 2021.
2022 Rates
During April 2017,In March 2021, we alongfiled an application with WGthe PSCW for the approval of certain accounting treatments that will allow us to maintain our current electric, natural gas, and WPS,steam base rates through 2022 and forego filing a rate case for one year. In connection with the request, we also entered into an agreement, dated March 23, 2021, with various stakeholders. Pursuant to the terms of the agreement, the stakeholders fully supported the application. On September 22, 2021, the PSCW issued a written order approving the application.
The final order reflects the following:
•We will amortize, in 2022, certain previously deferred balances to offset approximately half of our forecasted revenue deficiency.
•We are allowed to defer any increases in tax expense due to changes in tax law that occur in 2021 and/or 2022.
•We will maintain our earnings sharing mechanism for 2022, with modification. The earnings sharing mechanism will be modified to authorize us to retain 100% of the first 15 basis points of earnings above our currently authorized ROE. This modification expires on December 31, 2022. The earnings sharing mechanism will otherwise remain as currently authorized.
•We will file a full 2023-2024 test-year rate case no later than May 1, 2022.
2020 and 2021 Rates
In March 2019, we filed an application with the PSCW to increase our retail electric, natural gas, and steam rates, effective January 1, 2020. In August 2019, we filed an application with the PSCW for approval of a settlement agreement we madeentered into with certain intervenors to resolve several ofoutstanding issues in our commercial and industrial customers regarding 2018 andrate case. In December 2019, base rates. In September 2017, the PSCW issued ana written order that approved the settlement agreement without material modification and addressed the remaining outstanding issues that were not included in the settlement agreement. The new rates became effective January 1, 2020.
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The final order reflects the following:
| | | | | | | | | | | | | | |
| 2020 Effective rate increase | | | | |
Electric (1) | | $ | 15.3 | million | / | 0.5% |
Gas (2) | | $ | 10.4 | million | / | 2.8% |
| Steam | | $ | 1.9 | million | / | 8.6% |
| | | | |
| ROE | | 10.0% |
| | | | |
| Common equity component average on a financial basis | | 52.5% |
(1)Amount is net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impacts to our customers. The rate order reflects the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over two years, which will freeze base rates through 2019 for electricresults in approximately $65 million of tax benefits being amortized in each of 2020 and natural gas customers. Based2021. The unprotected deferred tax benefits related to the unrecovered balances of certain of our retired plants and our SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by the PSCW.
(2)Amount includes certain deferred tax expense from the Tax Legislation. The rate order reflects all of the unprotected deferred tax expense from the Tax Legislation being amortized evenly over four years, which results in approximately $5 million of previously deferred tax expense being amortized each year. Unprotected deferred tax expense by its nature is eligible to be recovered from customers in a manner and timeline determined to be appropriate by the PSCW.
In accordance with our rate order, we filed an application with the PSCW in July 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related financing fees. In November 2020, the PSCW issued a written order ourapproving the application. The financing order also authorized ROE remains at 10.2%, and our current capital cost structure will remain unchanged through 2019. Various intervenors have filed requestsus to form a bankruptcy-remote special purpose entity, WEPCo Environmental Trust, for rehearing.the sole purpose of issuing ETBs to recover the approved costs. In May 2021, WEPCo Environmental Trust issued $118.8 million of 1.578% ETBs due December 15, 2035. See Note 9, Long-Term Debt, for more information on the issuance of the ETBs. See Note 17, Variable Interest Entities, for more information on WEPCo Environmental Trust.
In additionits order, the PSCW approved us continuing 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 defer the revenue requirement impacts of any federal corporate tax reform enacted in 2017 or during the base rate freeze period.
Pursuant to the settlement agreement, we also agreed to keep ourhave an earnings sharing mechanism in place through 2019.2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50%ROE: (i) we retain 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the firstnext 50 basis points is refunded to customers; and (iii) 100.0% of additional utilityany remaining excess earnings must be shared withis refunded to customers. All utility earnings aboveIn addition, the first 50 basis points mustrate order 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 provide a portion of the current storage needs for our natural gas distribution service customers. As a result of this agreement, we, along with WGrequires us to maintain residential 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 agreements 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, the 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 with the PSCW for approval of this agreement. We expect to receive approval of the service agreement in the fourth quarter of 2017. See Note 13, 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 thesmall commercial electric and natural gas distribution assets,customer fixed charges at previously held by WPSauthorized rates and us, located into maintain the Upper Peninsula of Michigan.status quo for our electric market-based rate programs for large industrial customers through 2021.
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—21—NEW ACCOUNTING PRONOUNCEMENTS
Revenue RecognitionSimplifying the Accounting for Income Taxes
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,December 2019, the FASB issued ASU 2016-01, Recognition2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and Measurementcalculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of Financial Assets and Liabilities. Thisa consolidated group. The guidance iswas effective for fiscal yearsannual 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 the2020. The adoption of this guidance willASU 2019-12, effective January 1, 2021, did not have a significant impact on our financial statements.statements and related disclosures.
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Reference Rate Reform
In February 2016,March 2020, the FASB issued ASU 2016-02, Leases. This guidance isNo. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for fiscal years, and interim periods within those fiscal years, beginning afterall entities as of March 12, 2020 through 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.31, 2022. We are currently assessingevaluating the effectsimpact this guidance may have on our financial statements.statements and related disclosures.
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 2020 Annual Report on Form 10-K for the year ended December 31, 2016.10-K.
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 WGalso provide wholesale electric service to numerous utilities and operate under the trade name of "We Energies."cooperatives for resale. We conduct our business primarily through our utility reportable segment. See Note 11,16, Segment Information, for more information on our reportable business segments.
Effective January 1, 2017, our customers and electric distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility subsidiary of WEC Energy Group. 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, 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: environmental stewardship; reliability; operating efficiency; financial discipline; exceptional customer care; and safety. WEC Energy Group's capital investment plan for efficiency, sustainability and growth, referred to as its ESG Progress Plan, provides a roadmap to achieve this goal. It is an aggressive plan to cut emissions, maintain superior reliability, deliver significant savings for customers, and grow WEC Energy Group's and our investment in the future of energy.
Throughout its strategic planning process, WEC Energy Group takes into account important developments, risks and opportunities, including new technologies, customer preferences and commodity prices, energy resiliency efforts, and sustainability. WEC Energy Group published the results of a priority sustainability issue assessment in 2020, identifying the issues that are most important to the company and its stakeholders over the short and long terms. This risk and priority assessment has formed WEC Energy Group's direction as a company.
Creating a Sustainable Future
WEC Energy Group's ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with zero-carbon-emitting renewables and clean natural gas-fired generation at its electric utilities including us. When taken together, the retirements and new investments should better balance supply with demand, while maintaining reliable, affordable energy for our customers. The retirements will contribute to meeting WEC Energy Group's and our goals to reduce CO2 emissions from electric generation.
By the end of 2020, WEC Energy Group was able to reduce CO2 emissions from its electric generation fleet by more than 50% below 2005 levels. As a result, WEC Energy Group announced new goals in May 2021. WEC Energy Group committed to a 60% reduction in carbon emissions from its electric generation fleet by 2025 and an 80% reduction by the end of 2030, both from a 2005 baseline. WEC Energy Group expects to achieve these goals by making operating refinements, retiring less efficient generating units and executing its capital plan. Over the longer term, the target for its generation fleet is net-zero CO2 emissions by 2050.
In addition, we are exploring co-firing with natural gas at the ERGS coal-fired units. By the end of 2030, WEC Energy Group expects its use of coal will account for less than 5% of the power it supplies to its customers, and WEC Energy Group believes it will be in a position to eliminate coal as an energy source by 2035.
WEC Energy Group has already retired more than 1,800 MWs of coal-fired generation since the beginning of 2018, which included the 2019 retirement of the Presque Isle power plant as well as the 2018 retirement of the Pleasant Prairie power plant. As part of the ESG Progress Plan, WEC Energy Group expects to retire approximately 1,600 MW of additional fossil-fueled generation by 2025, which includes the planned retirement in 2023-2024 of OCPP Units 5-8.
In addition to retiring these older, fossil-fueled plants, WEC Energy Group expects to invest approximately $3.5 billion from 2022-2026 in regulated renewable energy in Wisconsin. WEC Energy Group's plan is to replace a portion of the retired capacity by building and owning zero-carbon-emitting renewable generation facilities that are anticipated to include the following new investments made by either us or WPS based on specific customer needs:
•1,500 MW of utility-scale solar;
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•800 MW of battery storage; and
•100 MW of wind.
WEC Energy Group also plans on investing in a combination of clean, natural gas-fired generation, made by either us or WPS based on specific customer needs, including:
•100 MW of reciprocating internal combustion engine (RICE) natural gas-fueled generation; and
•the planned purchase of 200 MW of capacity in the West Riverside Energy Center — a new, combined-cycle natural gas plant recently completed by Alliant Energy in Wisconsin.
For more details, see Liquidity and Capital Resources – Capital Resources and Requirements – Capital Requirements – Significant Capital Projects.
In addition, we previously received approval from the PSCW to invest in 100 MW of utility-scale solar. We have partnered with an unaffiliated utility to construct Badger Hollow II that is expected to enter commercial operation in December 2022. Once constructed, we will own 100 MW of the project.
In December 2018, we received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add a total of 35 MW of solar generation to our portfolio, allowing non-profit and government entities, as well as commercial and industrial customers to site utility owned solar arrays on their property. Under this program, we have energized 20 Solar Now projects and currently have another four under construction, together totaling more than 27 MW. The second program, the Dedicated Renewable Energy Resource pilot, would allow large commercial and industrial customers to access renewable resources that we would operate, adding up to 150 MW of renewables to our portfolio, and allowing these larger customers to meet their sustainability and renewable energy goals.
In August 2021, the PSCW approved pilot programs for us to install and maintain EV charging equipment for customers at their homes or businesses. The programs provide direct benefits to customers by removing cost barriers associated with installing EV equipment. In October 2021, subject to the receipt of any necessary regulatory approvals, WEC Energy Group pledged to expand the EV charging network within its utilities' electric service territories. In doing so, WEC Energy Group joined a coalition of utility companies in a unified effort to make EV charging convenient and widely available throughout the Midwest. The coalition WEC Energy Group joined is planning to help build and grow EV charging corridors, enabling the general public to safely and efficiently charge their vehicles.
WEC Energy Group also continues to reduce methane emissions by improving its natural gas distribution system. WEC Energy Group's initial 2030 goal called for a 30% reduction in methane emissions from a 2011 baseline. Given advancements with renewable natural gas, WEC Energy Group set a new target across its natural gas distribution operations to achieve net-zero methane emissions by the end of 2030.
Reliability
We have made significant reliability relatedreliability-related investments in recent years, and in accordance with the ESG Progress Plan, expect to continue strengthening and modernizing our generation fleet, as well as our electric and natural gas distribution networks to further improve reliability.
Below are a few examples of reliability projects that are proposed or recently completed.
•We constructed approximately 46 miles of natural gas transmission main to increase the quantity and reliability of natural gas service in southeastern Wisconsin. This project, called the Lakeshore Lateral Project, was completed in October 2021.
•We plan to continue making significant capital investmentsconstruct a LNG facility to strengthenmeet anticipated peak demand. Subject to PSCW approval, commercial operation for the LNG facility is targeted for the end of 2023.
For more details, see Liquidity and modernize the reliabilityCapital Resources – Capital Resources and Requirements – Capital Requirements – Significant Capital Projects.
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Operating Efficiency
We continually look for ways to optimize the operating efficiency of our company.company and will continue to do so under the ESG Progress Plan. For example, we received approval fromare making progress on our AMI 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 IT infrastructure across allthe resources of its companies. We expect these integration efforts to continue to drive operational efficiency.businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements.
Financial Discipline
A strong adherence to financial discipline is essential to earningmeeting our authorized ROEearnings projections 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 strategic to operations, are not performing as intended, or have an unacceptable risk profile. See Note 2, Dispositions, 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 exampleA multiyear effort is driving a standardized, seamless approach to digital customer service across all of how we obtain feedback from our customers is through our "We Care" calls, where our employees contact customers afterthe WEC Energy Group companies. It has moved all utilities, including us, to a completedcommon platform for all customer-facing self-service options. Using common systems and processes reduces costs, provides greater flexibility and enhances the consistent delivery of exceptional service call. Customer satisfaction is a priority, and making "We Care" callsto customers.
Safety
Safety is one of our core values and a critical component of our culture. We are committed to keeping our employees and the main methods we use to gauge our performance in order to improve customer satisfaction.public safe through a comprehensive corporate safety program that focuses on employee engagement and elimination of at-risk behaviors.
Safety
We have a long-standing commitment to both workplace and public safety, and underUnder our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. Management and union leadership work together to reinforce the Target Zero culture. We set annual goals for safety results as well as measurable leading indicators, in order to raise awareness of at-risk behaviors and situations and guide injury-prevention activities. All employees are encouraged to report unsafe conditions or incidents that could have led to an injury. Injuries and tasks with high levels of risk are assessed, and findings and best practices are shared across the WEC Energy Group companies.
Our 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, 20172021
Consolidated Earnings
Our consolidated earnings for the three months ended September 30, 2017third quarter of 2021 were $89.4$129.5 million, compared to $115.2$114.6 million for the same quarter in 2016.2020. See below for additional information on the $25.8$14.9 million decreaseincrease in consolidated earnings.
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Non-GAAP Financial Measures
The discussion below addresses the operating income contribution of our utility segment andto net income attributed to common shareholder. The discussion 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 marginmargins (electric revenues less fuel and purchased power costs) and natural gas marginmargins (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 meaningfuluseful 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, 20172021 and 2016,2020 was $163.4$260.9 million and $196.4$244.6 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 segmentthe most directly comparable GAAP measure, operating income.
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09/30/2017 Form 10-Q | 24 | Wisconsin Electric Power Company |
Utility Segment Contribution to OperatingNet Income Attributed to Common Shareholder
The following table compares our utility segment's contribution to operatingnet income forduring the third quarter of 20172021, compared with the thirdsame quarter of 2016,in 2020, 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.
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| | Three Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | B (W) |
| Electric revenues | | $ | 908.2 | | | $ | 855.3 | | | $ | 52.9 | |
| Fuel and purchased power | | 309.9 | | | 277.0 | | | (32.9) | |
| Total electric margins | | 598.3 | | | 578.3 | | | 20.0 | |
| | | | | | |
| Natural gas revenues | | 50.6 | | | 44.9 | | | 5.7 | |
| Cost of natural gas sold | | 26.8 | | | 20.9 | | | (5.9) | |
| Total natural gas margins | | 23.8 | | | 24.0 | | | (0.2) | |
| | | | | | |
| Total electric and natural gas margins | | 622.1 | | | 602.3 | | | 19.8 | |
| | | | | | |
| Other operation and maintenance | | 220.0 | | | 221.9 | | | 1.9 | |
| Depreciation and amortization | | 116.7 | | | 107.7 | | | (9.0) | |
| Property and revenue taxes | | 24.5 | | | 28.1 | | | 3.6 | |
| Operating income | | 260.9 | | | 244.6 | | | 16.3 | |
| | | | | | |
| Other income, net | | 7.6 | | | 5.7 | | | 1.9 | |
| Interest expense | | 114.3 | | | 116.3 | | | 2.0 | |
| Income before income taxes | | 154.2 | | | 134.0 | | | 20.2 | |
| | | | | | |
| Income tax expense | | 24.4 | | | 19.1 | | | (5.3) | |
| Preferred stock dividends of subsidiary | | 0.3 | | | 0.3 | | | — | |
| Net income attributed to common shareholder | | $ | 129.5 | | | $ | 114.6 | | | $ | 14.9 | |
|
| | | | | | | | | | | | |
| | | Three Months Ended September 30 |
| (in millions) | | 2017 | | 2016 | | B (W) |
| Electric revenues | | $ | 899.3 |
| | $ | 980.4 |
| | $ | (81.1 | ) |
| Fuel and purchased power | | 315.5 |
| | 337.2 |
| | 21.7 |
|
| Total electric margins | | 583.8 |
| | 643.2 |
| | (59.4 | ) |
| | | | | | | |
| Natural gas revenues | | 44.5 |
| | 43.4 |
| | 1.1 |
|
| Cost of natural gas sold | | 21.0 |
| | 19.9 |
| | (1.1 | ) |
| Total natural gas margins | | 23.5 |
| | 23.5 |
| | — |
|
| | | | | | | |
| Total electric and natural gas margins | | 607.3 |
| | 666.7 |
| | (59.4 | ) |
| | | | | | | |
| Other operation and maintenance | | 332.6 |
| | 359.4 |
| | 26.8 |
|
| Depreciation and amortization | | 83.0 |
| | 81.9 |
| | (1.1 | ) |
| Property and revenue taxes | | 28.3 |
| | 29.0 |
| | 0.7 |
|
| Operating income | | $ | 163.4 |
| | $ | 196.4 |
| | $ | (33.0 | ) |
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The following table shows a breakdown of other operation and maintenance:
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | B (W) |
| Operation and maintenance not included in line items below | | $ | 92.1 | | | $ | 93.4 | | | $ | 1.3 | |
Transmission (1) | | 84.4 | | | 84.4 | | | — | |
We Power (2) | | 27.5 | | | 29.3 | | | 1.8 | |
Regulatory amortizations and other pass through expenses (3) | | 16.0 | | | 14.8 | | | (1.2) | |
| | | | | | |
| Total other operation and maintenance | | $ | 220.0 | | | $ | 221.9 | | | $ | 1.9 | |
|
| | | | | | | | | | | | |
| | | Three Months Ended September 30 |
| (in millions) | | 2017 | | 2016 | | B (W) |
| Operation and maintenance not included in line items below | | $ | 111.2 |
| | $ | 123.6 |
| | $ | 12.4 |
|
We Power (1) | | 129.6 |
| | 129.6 |
| | — |
|
Transmission (2) | | 67.5 |
| | 68.3 |
| | 0.8 |
|
Regulatory amortizations and other pass through expenses (3) | | 24.3 |
| | 24.1 |
| | (0.2 | ) |
| Earnings sharing mechanisms | | — |
| | 13.8 |
| | 13.8 |
|
| Total other operation and maintenance | | $ | 332.6 |
| | $ | 359.4 |
| | $ | 26.8 |
|
| |
(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, 2017 and 2016, $129.0 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. |
(1)Represents transmission expense that we are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability, the difference 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, 2021 and 2020, $81.8 million and $82.4 million, respectively, of costs were billed to us by transmission providers.
(2)Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. During the three months ended September 30, 2021 and 2020, $20.4 million and $24.1 million, respectively, of costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset. |
| | |
09/30/2017 Form 10-Q | 25 | Wisconsin Electric Power Company |
(3)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.
The following tables provide information on delivered sales volumes by customer class and weather statistics:
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30 |
| | MWh (in thousands) |
| Electric Sales Volumes | | 2021 | | 2020 | | B (W) |
| Customer Class | | | | |
| Residential | | 2,465.5 | | | 2,428.5 | | | 37.0 | |
| Small commercial and industrial | | 2,374.9 | | | 2,285.6 | | | 89.3 | |
| Large commercial and industrial | | 1,785.1 | | | 1,778.3 | | | 6.8 | |
| Other | | 25.1 | | | 27.8 | | | (2.7) | |
| Total retail | | 6,650.6 | | | 6,520.2 | | | 130.4 | |
| Wholesale | | 258.6 | | | 266.3 | | | (7.7) | |
| Resale | | 1,210.2 | | | 1,563.8 | | | (353.6) | |
| Total sales in MWh | | 8,119.4 | | | 8,350.3 | | | (230.9) | |
|
| | | | | | | | | |
| | | 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 | | 2021 | | 2020 | | B (W) |
| Customer Class | | | | |
| Residential | | 20.0 | | | 22.2 | | | (2.2) | |
| Commercial and industrial | | 14.3 | | | 13.5 | | | 0.8 | |
| Total retail | | 34.3 | | | 35.7 | | | (1.4) | |
| Transportation | | 59.1 | | | 55.8 | | | 3.3 | |
| Total sales in therms | | 93.4 | | | 91.5 | | | 1.9 | |
| | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30 |
| | Degree Days |
Weather (1) | | 2021 | | 2020 | | B (W) |
| Heating (104 Normal) | | 22 | | | 103 | | | (78.6) | % |
| Cooling (581 Normal) | | 715 | | | 708 | | | 1.0 | % |
| | | | | | |
(1)Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.
|
| | | | | | | | | |
| | | 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 | ) |
| | | | | | | | |
*09/30/2021 Form 10-Q | Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin.30 | Wisconsin Electric Power Company |
Electric Utility Margins
Electric utility margins decreased $59.4increased $20.0 million during the third quarter of 2017,2021, compared with the same quarter in 2016.2020. The significant factors impacting the lowerhigher electric utility margins were:
•A $42.4$12.5 million decreaseincrease in margins related to lowerhigher retail sales volumes, duringincluding the third quarterimpact of 2017, primarily driven by cooler summer weather. As measured by cooling degree days, the third quarter ended September 30, 2017,of 2021 was 30.6% cooler1.0% warmer than the same quarter in 2016. Lower overall2020. Commercial and industrial retail use per customer andsales volumes also improved during the transferthird quarter of customers and their related sales to UMERC also contributed2021, compared with the same quarter in 2020, due to the decrease.
A $25.3 million quarter-over-quarter negative impact from collections of fuel and purchased power costs compared with costs approvedcontinued economic recovery 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 includedCOVID-19 pandemic.
•A $5.6 million increase in rates,margins from other revenues, primarily related to higher revenues from third party use of our assets as well as higher late payment charges during the third quarter of 2021. We resumed charging late payment charges in late August 2020 after they were suspended by the PSCW beginning March 24, 2020, as a result of the COVID-19 pandemic. See Note 20, Regulatory Environment, for more information.
•Securitization revenues of $3.8 million received during the third quarter of 2021 related to an environmental control charge from our retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 9, Long-Term Debt, and the remaining variance that exceeds the 2% variance is deferred.Note 17, Variable Interest Entities, for more information. These revenues are all offset in depreciation and amortization as well as interest expense.
These decreasesincreases in margins were partially offset by $9.2lower margins of $4.1 million driven by a decrease in wholesale customers related to the expiration of lower capacity payments to a counterparty during the third quarter of 2017.certain wholesale contracts.
Natural Gas Utility Margins
|
| | |
09/30/2017 Form 10-Q | 26 | Wisconsin Electric Power Company |
Operating Income
Operating income at theNatural gas utility segmentmargins decreased $33.0$0.2 million during the third quarter of 2017,2021, compared with the same quarter in 2016. This decrease2020. The most significant factor impacting the lower natural gas utility margins was lower retail sales volumes, primarily driven by warmer weather during the $59.4 million decreasethird quarter of 2021. As measured by heating degree days, the third quarter of 2021 was 78.6% warmer than the same quarter in margins discussed above, partially offset by $26.4 million of lower operating expenses (which include2020.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenuesrevenue taxes).
We experienced lower overallOther operating expenses related to synergy savings resulting from WEC Energy Group's acquisitionat the utility segment increased $3.5 million during the third quarter of Integrys.2021, compared with the same quarter in 2020. The significant factors impacting the decreaseincrease in operating expenses which were due in part to synergy savings, were:
•A $13.8$9.0 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan, as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.
•A $6.1 million increase in electric and natural gas distribution expenses, primarily driven by significant summer storms in 2021.
•A $2.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territory.
These increases in operating expenses were partially offset by a $14.2 million decrease in benefit costs, primarily due to lower stock-based compensation and deferred compensation costs.
Interest Expense
Interest expense recorded indecreased $2.0 million during 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% when2021, compared with the thirdsame quarter of 2016,in 2020, primarily due to increased renewable energy credits related to wind and favorable compensationlower interest expense on finance lease liabilities. This decrease was partially offset by interest expense on the ETBs issued by WEPCo Environmental Trust in the third quarter of 2017.May 2021, which is offset in revenues.
|
| | | | | | | |
09/30/20172021 Form 10-Q | 2731 | Wisconsin Electric Power Company |
Income Tax Expense
Income tax expense increased $5.3 million during the third quarter of 2021, compared with the same quarter in 2020. The increase was primarily due to an increase in pretax income.
NINE MONTHS ENDED SEPTEMBER 30, 20172021
Consolidated Earnings
Our consolidated earnings for the nine months ended September 30, 20172021 were $266.5$335.3 million, compared to $305.1$303.9 million for the same period in 2016.2020. See below for additional information on the $38.6$31.4 million decreaseincrease in consolidated earnings.
Expected 2021 Annual Effective Tax Rate
We expect our 2021 annual effective tax rate to be between 13.0% and 14.0%, which includes an estimated 10.0% effective tax rate benefit due to the amortization of unprotected excess deferred taxes in connection with our 2019 Wisconsin rate order. Excluding this estimated effective tax rate benefit, the expected 2021 range would be between 23.0% and 24.0%.
Non-GAAP Financial Measures
The discussion below addresses the operating income contribution of our utility segment andto net income attributed to common shareholder. The discussion 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 marginmargins (electric revenues less fuel and purchased power costs) and natural gas marginmargins (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 meaningfuluseful 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, 20172021 and 2016,2020 was $491.3$716.5 million and $524.8$680.2 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 segmentthe most directly comparable GAAP measure, 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 | ) |
|
| | | | | | | |
09/30/20172021 Form 10-Q | 2832 | Wisconsin Electric Power Company |
Utility Segment Contribution to Net Income Attributed to Common Shareholder
| | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | B (W) |
| Electric revenues | | $ | 2,461.7 | | | $ | 2,294.6 | | | $ | 167.1 | |
| Fuel and purchased power | | 808.9 | | | 698.0 | | | (110.9) | |
| Total electric margins | | 1,652.8 | | | 1,596.6 | | | 56.2 | |
| | | | | | |
| Natural gas revenues | | 329.8 | | | 246.1 | | | 83.7 | |
| Cost of natural gas sold | | 208.4 | | | 124.7 | | | (83.7) | |
| Total natural gas margins | | 121.4 | | | 121.4 | | | — | |
| | | | | | |
| Total electric and natural gas margins | | 1,774.2 | | | 1,718.0 | | | 56.2 | |
| | | | | | |
| Other operation and maintenance | | 642.4 | | | 640.8 | | | (1.6) | |
| Depreciation and amortization | | 340.7 | | | 318.4 | | | (22.3) | |
| Property and revenue taxes | | 74.6 | | | 78.6 | | | 4.0 | |
| Operating income | | 716.5 | | | 680.2 | | | 36.3 | |
| | | | | | |
| Other income, net | | 22.3 | | | 15.9 | | | 6.4 | |
| Interest expense | | 346.5 | | | 351.5 | | | 5.0 | |
| Income before income taxes | | 392.3 | | | 344.6 | | | 47.7 | |
| | | | | | |
| Income tax expense | | 56.1 | | | 39.8 | | | (16.3) | |
| Preferred stock dividends of subsidiary | | 0.9 | | | 0.9 | | | — | |
| Net income attributed to common shareholder | | $ | 335.3 | | | $ | 303.9 | | | $ | 31.4 | |
The following table shows a breakdown of other operation and maintenance:
| | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30 |
| (in millions) | | 2021 | | 2020 | | B (W) |
| Operation and maintenance not included in line items below | | $ | 253.7 | | | $ | 249.3 | | | $ | (4.4) | |
Transmission (1) | | 253.3 | | | 253.3 | | | — | |
We Power (2) | | 86.3 | | | 89.5 | | | 3.2 | |
Regulatory amortizations and other pass through expenses (3) | | 49.1 | | | 48.7 | | | (0.4) | |
| | | | | | |
| Total other operation and maintenance | | $ | 642.4 | | | $ | 640.8 | | | $ | (1.6) | |
(1)Represents transmission expense that we are authorized to collect in rates. The PSCW has approved escrow accounting for ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability, the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During the nine months ended September 30, 2021 and 2020, $251.0 million and $235.3 million, respectively, of costs were billed to us by transmission providers.
(2)Represents costs associated with the We Power generation units, including operating and maintenance costs we recognized. During the nine months ended September 30, 2021 and 2020, $72.0 million and $84.7 million, respectively, of costs were billed to or incurred by us related to the We Power generation units, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.
(3)Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on net income.
|
| | | | | | | | | | | | |
| | | 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)
09/30/2021 Form 10-Q | Represents costs associated with the We33 | Wisconsin Electric 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 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.Company |
| |
(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 nine months ended September 30, 2017 and 2016, $221.4 million and $256.2 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. |
The following tables provide information on delivered sales volumes by customer class and weather statistics:
| | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30 |
| | MWh (in thousands) |
| Electric Sales Volumes | | 2021 | | 2020 | | B (W) |
| Customer Class | | | | |
| Residential | | 6,353.3 | | | 6,295.7 | | | 57.6 | |
| Small commercial and industrial | | 6,521.1 | | | 6,238.6 | | | 282.5 | |
| Large commercial and industrial | | 5,051.5 | | | 4,873.4 | | | 178.1 | |
| Other | | 84.6 | | | 92.2 | | | (7.6) | |
| Total retail | | 18,010.5 | | | 17,499.9 | | | 510.6 | |
| Wholesale | | 851.2 | | | 757.1 | | | 94.1 | |
| Resale | | 4,359.3 | | | 4,508.3 | | | (149.0) | |
| Total sales in MWh | | 23,221.0 | | | 22,765.3 | | | 455.7 | |
|
| | | | | | | | | |
| | | 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 | | 2021 | | 2020 | | B (W) |
| Customer Class | | | | |
| Residential | | 243.0 | | | 248.9 | | | (5.9) | |
| Commercial and industrial | | 133.3 | | | 133.8 | | | (0.5) | |
| Total retail | | 376.3 | | | 382.7 | | | (6.4) | |
| Transportation | | 221.0 | | | 225.5 | | | (4.5) | |
| Total sales in therms | | 597.3 | | | 608.2 | | | (10.9) | |
|
| | | | | | | | | |
| | | 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 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30 |
| | Degree Days |
Weather (1) | | 2021 | | 2020 | | B (W) |
| Heating (4,313 Normal) | | 3,880 | | | 4,023 | | | (3.6) | % |
| Cooling (745 Normal) | | 1,018 | | | 931 | | | 9.3 | % |
(1)Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin. |
| | |
09/30/2017 Form 10-Q | 29 | Wisconsin Electric Power Company |
|
| | | | | | | | | |
| | | 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 | ) |
| |
* | 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 $83.9increased $56.2 million during the nine months ended September 30, 2017,2021, compared with the same period in 2016.2020. The significant factors impacting the lowerhigher electric utility margins were:
•A $67.2$38.4 million decreaseincrease in margins related to lowerhigher sales volumes, duringincluding the nine months ended September 30, 2017, primarily driven by unfavorable weather, lower overall retail use per customer, and the transferimpact 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.weather. 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%2021 were 9.3% warmer than the same period in 2016.
A $28.2 million period-over-period negative impact from collections of fuel2020. Commercial 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 million decrease in margins related to the iron ore mines located in the Upper Peninsula of Michigan. In November 2016, one of the iron ore mines closed. With the return of the mines asindustrial retail customers 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.
These decreases in margins were partially offset by $27.2 million of lower capacity payments to a counterpartyvolumes also improved during the nine months ended September 30, 2017.2021, compared with the same period in 2020, due to the continued economic recovery in Wisconsin from the COVID-19 pandemic.
•A $10.3 million increase in margins from other revenues, primarily related to higher late payment charges as well as higher revenues from third party use of our assets during the nine months ended September 30, 2021. We resumed charging late payment charges in late August 2020 after they were suspended by the PSCW beginning March 24, 2020, as a result of the COVID-19 pandemic. See Note 20, Regulatory Environment, for more information.
•A $5.6 million increase in margins driven by lower costs related to the purchase of required capacity as a result of an expiration of a contract in 2020, as well as lower ash handling costs.
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| 09/30/2021 Form 10-Q | 34 | Wisconsin Electric Power Company |
•Securitization revenues of $4.7 million received during the nine months ended September 30, 2021 related to an environmental control charge from WE's retail electric distribution customers. We began assessing this charge in June 2021, subsequent to the issuance of the ETBs by WEPCo Environmental Trust in May 2021, in accordance with a November 2020 PSCW financing order. See Note 9, Long-Term Debt, and Note 17, Variable Interest Entities, for more information. These revenues are all offset in depreciation and amortization as well as interest expense.
These increases in margins were partially offset by lower margins of $2.5 million driven by a decrease in wholesale customers related to the expiration of certain wholesale contracts.
Natural Gas Utility Margins
Natural gas utility margins decreased $2.6did not change during the nine months ended September 30, 2021, compared with the same period in 2020. A $1.0 million increase in margins from other revenues, primarily related to higher late payment charges during the nine months ended September 30, 2021, as discussed above under Electric Utility Margins, was offset by lower sales volumes.
Other Operating Expenses (includes other operation and maintenance, depreciation and amortization, and property and revenue taxes)
Other operating expenses at the utility segment increased $19.9 million during the nine months ended September 30, 2017,2021, compared with the same period in 2016.2020. The most significant factorfactors impacting the lowerincrease in operating expenses were:
•A $22.3 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan as well as an increase related to the We Power leases. In addition, a portion of the increase is related to securitization amortization, which is offset in revenues.
•A $7.9 million increase in electric and natural gas utility margins were lower sales volumes,distribution expenses, primarily driven by warmer winter weather. Ansignificant summer storms in 2021.
•A $4.5 million increase in customer service expenses, primarily related to additional day of sales during 2016costs from an information technology project created to improve the billing, call center, and credit collection functions, as well as higher call volumes and metering costs.
•A $2.0 million increase in expenses related to charitable projects supporting our customers and the communities within our service territory.
•A $1.7 million increase in property and liability insurance premiums.
These increases in operating expenses were partially offset by:
•A $15.9 million decrease in benefit costs, primarily due to leap year also contributedlower stock-based compensation.
•Costs incurred of $2.5 million during the second quarter of 2020, related to the decrease.damage to our PSB resulting from a significant rain event in May 2020. See Note 5, Property, Plant, and Equipment, for more information.
OperatingOther Income, Net
OperatingOther income, at the utility segment decreased $33.5net increased $6.4 million during the nine months ended September 30, 2017,2021, compared with the same period in 2016. The decrease was2020, driven by higher net credits from the $86.5 million decrease in margins discussed above, partially offset by $53.0 millionnon-service components 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 operationour net periodic pension 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. OPEB costs. See Note 2, Dispositions, for more information on the sale of the MCPP.
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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.
A $10.7 million decrease in electric and natural gas distribution expenses, due in part to the transfer 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 included in the table above.
These decreases in operating expenses were partially offset by a $10.9 million gain on the sale of the MCPP, which was sold in April 2016. See Note 2, Dispositions,15, Employee Benefits, for more information on the sale of the MCPP.
our benefit costs. Higher AFUDC–Equity in Earnings of Transmission Affiliate
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| | | | | | | | | | | | |
| | | 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 ourdue to continued capital investment in ATC to another subsidiary of WEC Energy Group. See Note 13, Related Parties, for more information.
Consolidated Other Income, Net
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| | | Nine Months Ended September 30 |
| (in millions) | | 2017 | | 2016 | | B (W) |
| AFUDC – Equity | | $ | 2.1 |
| | $ | 3.6 |
| | $ | (1.5 | ) |
| Other | | 12.2 |
| | 3.1 |
| | 9.1 |
|
| Other income, net | | $ | 14.3 |
| | $ | 6.7 |
| | $ | 7.6 |
|
Other Income, net increased by $7.6 million when comparedalso contributed to the nine months ended September 30, 2016. The increase was driven by gains on property salesin other income, net.
Interest Expense
Interest expense decreased $5.0 million during the nine months ended September 30, 2017,2021, compared with the same period in 2016, in addition2020, primarily due to expenses we incurred in 2016 related to the disposition of certain non-utility real estate assets. These increases werelower interest expense on finance lease liabilities. This decrease was partially offset by lower AFUDC during 2017.interest expense on the ETBs issued by WEPCo Environmental Trust in May 2021, which is offset in revenues.
Consolidated Interest Expense
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| | | Nine Months Ended September 30 |
| (in millions) | | 2017 | | 2016 | | B (W) |
| Interest expense | | $ | 88.0 |
| | $ | 88.0 |
| | $ | — |
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| 09/30/2021 Form 10-Q | 35 | Wisconsin Electric Power Company |
Income Tax Expense
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| | | Nine Months Ended September 30 |
| | | 2017 | | 2016 | | B (W) |
| Effective tax rate | | 36.0 | % | | 36.8 | % | | 0.8 | % |
Our effectiveIncome tax rate decreased by 0.8% when compared with the nine months ended September 30, 2016, primarily due toexpense increased renewable energy credits related to wind and favorable compensation expense$16.3 million during the nine months ended September 30, 2017. We expect our 2017 annual effective tax rate2021, compared with the same period in 2020. The increase was primarily due to be between 36.0%an increase in pretax income and 37.0%.a decrease in PTCs.
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09/30/2017 Form 10-Q | 31 | Wisconsin Electric Power Company |
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
The following table summarizes our cash flows during the nine months ended September 30:
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| (in millions) | | 2021 | | 2020 | | Change in 2021 Over 2020 |
| Cash provided by (used in): | | | | | | |
| Operating activities | | $ | 831.7 | | | $ | 644.4 | | | $ | 187.3 | |
| Investing activities | | (610.6) | | | (452.0) | | | (158.6) | |
| Financing activities | | (217.6) | | | (209.6) | | | (8.0) | |
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| | | | | | | | | | | | |
| (in millions) | | 2017 | | 2016 | | Change in 2017 Over 2016 |
| Cash provided by (used in): | | | | | | |
| Operating activities | | $ | 594.3 |
| | $ | 614.6 |
| | $ | (20.3 | ) |
| Investing activities | | (382.1 | ) | | (285.2 | ) | | (96.9 | ) |
| Financing activities | | (224.3 | ) | | (344.3 | ) | | 120.0 |
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Operating Activities
Net cash provided by operating activities decreased $20.3increased $187.3 million during the nine months ended September 30, 2017,2021, compared with the same period in 2016,2020, driven by:by:
•A $114.2$128.9 million decreaseincrease in cash related to lowerhigher overall collections from customers as a result of an increase in sales volumes during the nine months ended September 30, 2017,2021, compared with the same period in 2016. Collections from customers decreased primarily because of unfavorable2020. This increase was driven by favorable weather and the loss of salescontinued economic recovery in Wisconsin from the transferCOVID-19 pandemic. In addition, we received higher collections from customers for late payment charges and began collecting securitization revenues in June 2021 related to the issuance of customers to UMERC in 2017.
the ETBs by WEPCo Environmental Trust. See Note 9, Long-Term Debt, and Note 17, Variable Interest Entities, for more information on the issuance of our ETBs.
•A $60.6$77.5 million decreaseincrease in cash relateddue to higher collateral received from counterparties, driven by an increase in cash paid for income taxesthe fair value of our natural gas derivative assets during the nine months ended September 30, 2017,2021, compared with the same period in 2016. This decrease2020.
•A $50.4 million increase in cash was primarily the result of the extension of bonus depreciation in December 2015.
A $34.4 million decrease in cash resulting from higherlower payments for natural gasother operation and fuel and purchased power, primarily due to higher commodity prices. The average per-unit cost of natural gas sold increased 14.1% duringmaintenance expenses. During the nine months ended September 30, 2017,2021, our payments were lower for benefits and costs associated with the We Power generation units, as well as timing of payments for accounts payable.
•An $11.6 million increase in cash related to lower payments for income taxes during the nine months ended September 30, 2021, compared with the same period in 2016.
A $27.7 million2020, driven by a decrease in distributions received during the nine months ended September 30, 2017, compared with the same periodtaxable income 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.
2021.
These decreasesincreases in net cash provided by operating activities were partially offset by:
A $116.1by a $90.2 million increasedecrease in cash related to a cash payment to WBShigher payments for fuel and purchased power at our plants during the nine months ended September 30, 2016for transfers2021, compared with the same period in 2020. Natural gas costs increased significantly throughout the central part of certain benefit-related liabilitiesthe country in February 2021 related to WBS. We did not make a similar paymentextreme weather conditions. In addition to higher costs related to the extreme weather conditions in 2017.
A $111.7 million increase in cash from lower payments for operating and maintenance costs. DuringFebruary 2021, we incurred higher natural gas costs throughout the nine months ended September 30, 2017,2021, compared with the same period in 2020, as a result of an increase in the price of natural gas. Higher coal costs also drove higher payments for fuel used at our payments related to transmission, electric generation costs, and electric and natural gas distribution costs decreased.
plants.
Investing Activities
Net cash used in investing activities increased $96.9$158.6 million during the nine months ended September 30, 2017,2021, compared with the same period in 2016,2020, driven by:
An $83.2by a $163.1 million increase in cash paid for capital expenditures, during the nine months ended September 30, 2017, compared with the same period in 2016, which is discussed in more detail below.
Cash of $13.1 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 nine months ended September 30, 2017, compared with the same period in 2016. See Note 2, Dispositions, for more information.
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09/30/2017 Form 10-Q | 32 | Wisconsin Electric Power Company |
These increases This increase in net cash used in investing activities werewas partially offset by $10.4higher proceeds received from affiliates of $9.4 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 due2021 for assets transferred related to the transfera customer billing system.
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Capital Expenditures
Capital expenditures for the nine months ended September 30 were as follows:
| | | | | | | | | | | | | | | | | | | | |
| (in millions) | | 2021 | | 2020 | | Change in 2021 Over 2020 |
| Capital expenditures | | $ | 625.9 | | | $ | 462.8 | | | $ | 163.1 | |
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| | | | | | | | | | | | |
| (in millions) | | 2017 | | 2016 | | Change in 2017 Over 2016 |
| Capital expenditures | | $ | 405.7 |
| | $ | 322.5 |
| | $ | 83.2 |
|
The increase in cash paid for capital expenditures during the nine months ended September 30, 20172021, compared with the same period in 2020, was primarily driven by higher payments for capital expenditures related to upgrades ofto our natural gas distribution system, repairs and electric distribution systems, including meterrestoration of our PSB driven by the significant rain event, and main replacement projects,renovation of a service center during the nine months ended September 30, 2021. See Note 5, Property, Plant, and various projects atEquipment, for more information on the OCPP.PSB. These increases were partially offset by lower payments for capital expenditures related to an information technology project created to improve our billing, call center, and credit collection functions during the nine months ended September 30, 2021.
See Capital Resources and Requirements -– Capital Requirements – Significant Capital Projects for more information.
Financing Activities
Net cash used in financing activities decreased $120.0increased $8.0 million during the nine months ended September 30, 2017,2021, compared with the same period in 2016, primarily2020, driven by:
•A $140.0$154.0 million decrease in dividends paidcash related 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 million equity contribution received from our parent to balance our capital structure during the nine months ended September 30, 2017.
These decreases in net cash used in financing activities were partially offset by:
A $60.5 million increase inhigher net repayments of commercial paper during the nine months ended September 30, 2017.
2021, compared with the same period in 2020.
•A $16.0$60.0 million increase decrease in net repayments of our subsidiary's notecash related to higher dividends paid to our parent during the nine months ended September 30, 2017.
2021, compared with the same period in 2020, to balance our capital structure.
•A $6.8 million increase in our principal payments for finance lease obligations during the nine months ended September 30, 2021, compared with the same period in 2020.
These decreases in cash were partially offset by:
•A $418.8 million increase in cash due to the issuance of long-term debt during the nine months ended September 30, 2021. A portion of these proceeds were used to redeem $300.0 million of long-term debt with higher interest rates. There were no issuances or repayments of long-term debt during the nine months ended September 30, 2020.
•A $100.0 million increase in cash related to higher equity contributions received from our parent during the nine months ended September 30, 2021, compared with the same period in 2020, to balance our capital structure.
Significant Financing Activities
For more information on our short-term financing activities, see Note 5,8, Short-Term Debt and Lines of Credit.Credit, and Note 9, Long-Term Debt.
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
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| 09/30/2021 Form 10-Q | 37 | Wisconsin Electric Power Company |
currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangement,arrangements, access to capital markets, and internally generated cash. See Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019, for additional information on the impacts of the COVID-19 pandemic.
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 5,8, Short-Term Debt and Lines of Credit, for more information on our credit facility.
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09/30/2017 Form 10-Q | 33 | Wisconsin Electric Power Company |
As of September 30, 2017, 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, 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.
Working Capital
Although not the case as of September 30, 2017,2021, our current liabilities sometimes exceed our current assets. If this were to occur, we would 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 programsprogram and to refinance current maturities of long-term debt, if necessary.
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, a division of S&P Global Inc., and/or Baa3 at Moody's Investors Service.Service, Inc. 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 additional impacts from the COVID-19 pandemic, the credit rating agencies could place our credit ratings on negative outlook or downgrade 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, acquisition and development opportunities, market volatility, economic trends, and economic trends.the COVID-19 pandemic. Our estimated capital expenditures for the next three years are as follows:
| | | | | | | | | | | |
| (in millions) | | | |
| 2021 | | $ | 841.9 | | (1) |
| 2022 | | 1,204.2 | | |
| 2023 | | 1,360.2 | | |
| Total | | $ | 3,406.3 | | |
(1)This includes actual capital expenditures already incurred in 2021, as well as estimated capital expenditures for the remainder of the year.
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| | | | |
| (in millions) | | |
| 2017 | | $ | 576.7 |
|
| 2018 | | 592.6 |
|
| 2019 | | 541.2 |
|
| Total | | $ | 1,710.5 |
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| 09/30/2021 Form 10-Q | 38 | Wisconsin Electric Power Company |
The majority of spending consists of upgradingWe continue to upgrade our electric and natural gas distribution systems to enhance reliability. These upgrades include the advanced metering infrastructure (AMI)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.
WEC Energy Group is committed to investing in solar, wind, battery storage, and clean natural gas-fired generation. Below are examples of projects that are proposed or currently underway.
•We have partnered with an unaffiliated utility to construct a utility-scale solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, we will own 100 MW of the project. Our share of the cost of this project is estimated to be approximately $130 million. Commercial operation of Badger Hollow II is targeted for December 2022.
•In February 2021, we, along with WPS and an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Paris Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Kenosha County, Wisconsin and once constructed, we will own 150 MW of solar generation and 82 MW of battery storage of this project. If approved, our share of the cost of this project is estimated to be approximately $320 million, with construction expected to begin in 2022 and completed by the end of 2023.
•We, along with WPS, received approval to accelerate capital investments in two wind parks. Our share of the investment is expected to be approximately $85 million to repower major components of Blue Sky Green Field Wind Park, which is expected to be completed by the end of 2022.
•In March 2021, we, along with WPS and an unaffiliated utility, filed an application with the PSCW for approval to acquire and construct the Darien Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Rock and Walworth counties, Wisconsin and once constructed, we will own 188 MW of solar generation and 56 MW of battery storage of this project. If approved, our share of the cost of this project is estimated to be approximately $335 million, with construction expected to begin in late 2021 and completed by the end of 2023.
•In April 2021, we, along with WPS and an unaffiliated utility, filed an application with the PSCW for approval to acquire the Koshkonong Solar-Battery Park, a utility-scale solar-powered electric generating facility with a battery energy storage system. The project will be located in Dane County, Wisconsin and once constructed, we will own 225 MW of solar generation and 124 MW of battery storage of this project. If approved, our share of the cost of this project is estimated to be approximately $488 million, with construction expected to begin in late 2022 and completed by the second quarter of 2024.
•In April 2021, we, along with WPS, filed an application with the PSCW for approval to construct a natural gas-fired generation facility at WPS's existing Weston power plant site in northern Wisconsin. The new facility will consist of seven reciprocating internal combustion engines. Once constructed, we will own 64 MW of this project. If approved, our share of the cost of this project is estimated to be approximately $85 million, with construction expected to begin in 2022 and completed in 2023.
We constructed approximately 46 miles of natural gas transmission main to increase the quantity and reliability of natural gas service in southeastern Wisconsin. This project, which was approved by the PSCW in June 2020, was designated as the Lakeshore Lateral Project. The cost of the project was approximately $130 million. Construction for the project began in December 2020 and was completed in October 2021.
We plan to construct a LNG facility. Subject to PSCW approval, the facility would provide us with approximately one billion cubic foot of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. The facility is expected to reduce the likelihood of constraints on our natural gas system during the highest demand days of winter. The project is estimated to cost approximately $185 million. If approved, construction is expected to begin by the end of 2021 with commercial operation for the LNG facility targeted for the end of 2023.
See Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks – United States Department of Commerce Complaint for information on the DOC complaint that could impact our solar projects.
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09/30/20172021 Form 10-Q | 3439 | Wisconsin Electric Power Company |
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 expenses, results of operations, liquidity, capital expenditures, or capital resources. For additional information, see Note 5,8, Short-Term Debt and Lines of Credit, Note 14, Guarantees, and Note 12,17, 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 20162020 Annual Report on Form 10-K. There were no material changes to our commitments outside the ordinary course of business during the nine months ended September 30, 2021.
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 followingThis 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 20162020 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,competitive markets, environmental matters, critical accounting policies and estimates, and other matters.
Coronavirus Disease – 2019
The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC and has spread globally, including throughout the United States. There are still questions regarding the extent and duration of the COVID-19 pandemic itself, as well as the measures currently in place to try to contain the virus. Shelter-in-place and other orders limiting the capacity of various businesses that were in effect for our service territory have now expired. Similar orders could be adopted in the future depending on how the virus continues to mutate and spread. The effects of the COVID-19 pandemic and related government responses significantly disrupted economic activity in our service territory in 2020 and continue to impact our results in 2021.
Liquidity and Financial Markets
Upon the initial enactment of certain COVID-19 related shelter-in-place orders in early to mid-March 2020, commercial paper markets became more expensive and related terms became less flexible. In response to these signs of market instability, the Federal Reserve implemented certain measures, including a reduction in its benchmark Federal Funds rate and the establishment of various programs to restore liquidity and stability into the short-term funding markets. These measures continue to have a mitigating effect on commercial paper rates and availability. In addition, the initial disruption in the long-term debt markets as a result of the COVID-19 pandemic has subsided.
Allowance for Credit Losses
We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. Risks identified that we do not believe are reflected in historical reserve percentages are assessed on a quarterly basis to determine whether further adjustments are required. Economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates and the inability of some businesses to recover from the pandemic, have caused a higher percentage of accounts receivable to become uncollectible. Although impacts on our results of operations related to uncollectible receivable balances are mitigated by a regulatory mechanism and certain COVID-19 specific regulatory orders we have received, the increase in past due receivables we experienced resulted in higher working capital requirements. However, with normal collection practices underway, our working capital position has improved from where we were at the end of the first quarter of 2021.
Our exposure to credit losses for certain regulated utility customers is mitigated by a regulatory mechanism we have in place. Specifically, our residential tariffs include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) and foregone revenues related to the COVID-19 pandemic. The additional
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| 09/30/2021 Form 10-Q | 40 | Wisconsin Electric Power Company |
protections provided by these COVID-19 specific regulatory orders are still being assessed and will be subject to prudency reviews. See Note 20, Regulatory Environment, for more information.
Loss of Business
We saw a decrease in the consumption of electricity and natural gas by some of our commercial and industrial customers as a result of the COVID-19 pandemic. Although many of these customers have started to recover, the extent to which this decreased consumption continues to impact our results of operations and liquidity is dependent upon the duration of the COVID-19 pandemic and the ability of our customers to resume and continue normal operations.
Supply Chain and Capital Projects
We have not yet experienced a significant disruption in our supply chain as a result of the COVID-19 pandemic. However, if the pandemic significantly impacts our key suppliers’ ability to manufacture or deliver critical equipment and supplies or provide services, we could experience delays in our ability to perform certain maintenance and capital project activities.
We are not currently aware of any major delays or changes related to our capital plan as a result of the COVID-19 pandemic, although we are continuing to monitor potential impacts on an ongoing basis.
Employee Safety
The health and safety of our employees during the COVID-19 pandemic is paramount and enables us to continue to provide critical services to our customers.
We are following CDC guidelines and have taken precautions with regard to employee hygiene and facility cleanliness, imposed travel limitations on our employees, provided additional employee benefits, and implemented remote-work policies where appropriate. We have an incident management team and updated our pandemic continuity plan, which includes identifying critical work groups and ensuring safe-harbor plans are in place. We have minimized the unnecessary risk of exposure to COVID-19 by implementing self-quarantine measures and have adopted additional precautionary measures for our critical work groups.
Additional protocols have been implemented for our field employees who travel to customer premises in order to protect them, our customers, and the public. We have modified our work protocols to ensure compliance with social distancing and face covering recommendations.
We continue to provide our employees with educational information regarding the COVID-19 vaccine and will be providing incentives and imposing surcharges on our medical plan to encourage employees to obtain the vaccine. We are developing return-to-the workplace strategies for those employees currently working remotely, taking into consideration factors such as any updated CDC guidelines, the Delta variant, any increases in COVID-19 cases in our service territory, and the overall level of risk to our employees and customers.
All of these safety measures have caused us to incur additional costs that, depending upon the duration of the COVID-19 pandemic, could have a material impact on our results of operations and liquidity.
Regulatory Environment
We took actions to ensure that essential utility services were available to our customers during the COVID-19 pandemic. In addition, the PSCW issued written orders requiring certain actions by all public utilities in the state of Wisconsin. See Note 20, Regulatory Environment, for more information on these orders and the potential recovery of expenditures incurred as a result of the measures taken.
Market Risks and Other Significant Risks
We are exposed to market and other significant risks as a result of the nature of our business and the environment in which we operate. These risks include, but are not limited to, the regulatory matter described below. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Market Risks and Other Significant Risks in our 2020 Annual Report on Form 10-K for a discussion of other significant risks applicable to us.
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| 09/30/2021 Form 10-Q | 41 | Wisconsin Electric Power Company |
United States Department of Commerce Complaint
In August 2021, a group of anonymous domestic solar manufacturers filed a petition with the DOC seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claim that Chinese solar manufacturers are shifting products to these countries to avoid the tariffs required on products imported from China. In September 2021, the DOC asked that the anonymous group amend its petition to provide more detail and asked the group to identify its members. On October 13, 2021, in its response to the DOC, the anonymous group refused and argued that identifying its members could expose them to retribution from the Chinese solar industry, which dominates the global solar supply chain for critical solar panel components. The DOC has indicated it will make its decision within 45 days of receiving the response. If imposed, the new tariffs are expected to disrupt the United States' supply of solar modules and could impact the cost and timing of our solar projects.
Environmental Matters
See Note 14,18, 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.
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09/30/2017 Form 10-Q | 35 | Wisconsin Electric Power Company |
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 2020 Annual Report on Form 10-K for the year ended December 31, 2016.10-K. In addition to the Form 10-K disclosures, see Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Coronavirus Disease – 2019 and Market Risks and Other Significant Risks in Item 2 of Part I of this report, as well as Note 7,12, Fair Value Measurements, Note 13, Derivative Instruments, and Note 8, Derivative Instruments,14, Guarantees, in this report for information concerning our market risk exposures.
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
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 20172021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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09/30/20172021 Form 10-Q | 3642 | Wisconsin Electric Power Company |
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 20162020 Annual Report on Form 10-K. See Note 14,18, Commitments and Contingencies, and Note 20, Regulatory Environment, in this report for moreadditional information on material legal proceedings and matters related to us.
In addition to those legal proceedings referenced above,discussed in Note 18, Commitments and Contingencies, and Note 20, Regulatory Environment, 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 additional 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.
ITEM 1A. RISK FACTORS
There were no material changes from the risk factors presenteddisclosed in our Annual Report on Form 10-K for the year ended December 31, 2016. See Item 1A. Risk Factors in Part I of our 20162020 Annual Report on Form 10-K for a discussion of certain risk factors applicable to us.10-K.
ITEM 5. OTHER INFORMATION
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
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| ITEM 6. EXHIBITS |
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31 | | |
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| 31 | | Rule 13a-14(a) / 15d-14(a) Certifications |
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| 32 | | Section 1350 Certifications |
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| 101 | | Interactive Data Files |
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| | 101.INS | Inline XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
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| | 101.SCH | Inline XBRL Taxonomy Extension Schema |
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| | 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase |
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| | 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase |
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| | 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase |
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| | 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase |
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| 104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) |
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09/30/20172021 Form 10-Q | 3743 | Wisconsin Electric Power Company |
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.
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| | WISCONSIN ELECTRIC POWER COMPANY |
| | (Registrant) |
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| | WISCONSIN ELECTRIC POWER COMPANY |
| | (Registrant) |
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| | /s/ WILLIAM J. GUC |
| Date: | November 3, 20174, 2021 | William J. Guc |
| | Vice President, Controller, and ControllerAssistant Corporate Secretary |
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| | (Duly Authorized Officer and Chief Accounting Officer) |
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09/30/20172021 Form 10-Q | 3844 | Wisconsin Electric Power Company |