WISCONSIN ELECTRIC POWER CO - Annual Report: 2019 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2019
OR
☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from ________________ to ___________________
Commission File Number | Registrant; State of Incorporation; 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
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Serial Preferred Stock, 3.60% Series, $100 Par Value | ||
Six Per Cent. Preferred Stock, $100 Par Value | ||
Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☐ No ☒
Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes ☐ No ☒
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 ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).
Yes ☒ No ☐
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer | ☐ | Accelerated filer | ☐ | |||
Non-accelerated filer | ☒ | 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 ☒
As of June 30, 2019 (and currently), all of the common stock of Wisconsin Electric Power Company is held by WEC Energy Group, Inc.
State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant. | ||
None.
Number of shares outstanding of each class of common stock, as of | ||
January 31, 2020 | ||
Common Stock, $10 par value, 33,289,327 shares outstanding
Documents incorporated by reference:
Portions of Wisconsin Electric Power Company's Definitive information statement on Schedule 14C for its Annual Meeting of Shareholders, to be held on April 30, 2020, are incorporated by reference into Part III hereof.
WISCONSIN ELECTRIC POWER COMPANY
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2019
TABLE OF CONTENTS
Page | |||||
2019 Form 10-K | i | Wisconsin Electric Power Company |
2019 Form 10-K | ii | 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:
Subsidiaries and Affiliates | ||
ATC | American Transmission Company LLC | |
Bluewater | Bluewater Natural Gas Holding, LLC | |
Bostco | Bostco LLC | |
UMERC | Upper Michigan Energy Resources Corporation | |
WBS | WEC Business Services LLC | |
WE | Wisconsin Electric Power Company | |
We Power | W.E. Power, LLC | |
WEC Energy Group | WEC Energy Group, Inc. | |
WG | Wisconsin Gas LLC | |
Wispark | Wispark LLC | |
WPS | Wisconsin Public Service Corporation | |
Federal and State Regulatory Agencies | ||
EPA | United States Environmental Protection Agency | |
FERC | Federal Energy Regulatory Commission | |
IRS | United States Internal Revenue Service | |
MPSC | Michigan Public Service Commission | |
PSCW | Public Service Commission of Wisconsin | |
SEC | Securities and Exchange Commission | |
WDNR | Wisconsin Department of Natural Resources | |
Accounting Terms | ||
AFUDC | Allowance for Funds Used During Construction | |
ARO | Asset Retirement Obligation | |
ASC | Accounting Standards Codification | |
ASU | Accounting Standards Update | |
CWIP | Construction Work in Progress | |
FASB | Financial Accounting Standards Board | |
GAAP | Generally Accepted Accounting Principles | |
OPEB | Other Postretirement Employee Benefits | |
SAB | Staff Accounting Bulletin | |
Environmental Terms | ||
ACE | Affordable Clean Energy | |
Act 141 | 2005 Wisconsin Act 141 | |
BATW | Bottom Ash Transport Water | |
BSER | Best System of Emission Reduction | |
BTA | Best Technology Available | |
CAA | Clean Air Act | |
CO2 | Carbon Dioxide | |
ELG | Steam Electric Effluent Limitation Guidelines | |
FGD | Flue Gas Desulfurization | |
GHG | Greenhouse Gas | |
MATS | Mercury and Air Toxics Standards | |
NAAQS | National Ambient Air Quality Standards | |
NOx | Nitrogen Oxide | |
RTR | Risk and Technology Review | |
SO2 | Sulfur Dioxide | |
2019 Form 10-K | iii | Wisconsin Electric Power Company |
Measurements | ||
Dth | Dekatherm | |
MW | Megawatt | |
MWh | Megawatt-hour | |
Other Terms and Abbreviations | ||
AIA | Affiliated Interest Agreement | |
AMI | Advanced Metering Infrastructure | |
ARR | Auction Revenue Right | |
Badger Hollow II | Badger Hollow Solar Farm II | |
CFR | Code of Federal Regulations | |
Compensation Committee | Compensation Committee of the Board of Directors of WEC Energy Group, Inc. | |
D.C. Circuit Court of Appeals | United States Court of Appeals for the District of Columbia Circuit | |
ERGS | Elm Road Generating Station | |
ER 1 | Elm Road Generating Station Unit 1 | |
ER 2 | Elm Road Generating Station Unit 2 | |
ERP | Enterprise Resource Planning | |
Exchange Act | Securities Exchange Act of 1934, as amended | |
FTR | Financial Transmission Right | |
GCRM | Gas Cost Recovery Mechanism | |
LIBOR | London Interbank Offered Rate | |
LMP | Locational Marginal Price | |
LNG | Liquefied Natural Gas | |
MISO | Midcontinent Independent System Operator, Inc. | |
MISO Energy Markets | MISO Energy and Operating Reserves Market | |
NYMEX | New York Mercantile Exchange | |
OCPP | Oak Creek Power Plant | |
OC 5 | Oak Creek Power Plant Unit 5 | |
OC 6 | Oak Creek Power Plant Unit 6 | |
OC 7 | Oak Creek Power Plant Unit 7 | |
OC 8 | Oak Creek Power Plant Unit 8 | |
Omnibus Stock Incentive Plan | WEC Energy Group 1993 Omnibus Stock Incentive Plan, Amended and Restated Effective as of January 1, 2016 | |
PIPP | Presque Isle Power Plant | |
Point Beach | Point Beach Nuclear Power Plant | |
PWGS | Port Washington Generating Station | |
PWGS 1 | Port Washington Generating Station Unit 1 | |
PWGS 2 | Port Washington Generating Station Unit 2 | |
ROE | Return on Equity | |
RTO | Regional Transmission Organization | |
SOX | Section 404 of the Sarbanes-Oxley Act | |
SSR | System Support Resource | |
Tax Legislation | Tax Cuts and Jobs Act of 2017 | |
Tilden | Tilden Mining Company | |
VAPP | Valley Power Plant | |
2019 Form 10-K | iv | 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 and associated compliance costs, legal proceedings, effective tax rates, pension and OPEB plans, fuel costs, sources of electric energy supply, coal and natural gas deliveries, remediation costs, environmental matters, liquidity and capital resources, and other matters.
Forward-looking statements are subject to a number of risks and uncertainties that could cause our actual results to differ materially from those expressed or implied in the statements. These risks and uncertainties include those described in Item 1A. Risk Factors and those identified below:
• | Factors affecting utility operations such as catastrophic weather-related damage, environmental incidents, unplanned facility outages and repairs and maintenance, and electric transmission or natural gas pipeline system constraints; |
• | Factors affecting the demand for electricity and natural gas, including political developments, unusual weather, changes in economic conditions, customer growth and declines, commodity prices, energy conservation efforts, and continued adoption of distributed generation by customers; |
• | The timing, resolution, and impact of rate cases and negotiations, including recovery of deferred and current costs and the ability to earn a reasonable return on investment, and other regulatory decisions impacting our regulated operations; |
• | The impact of recent and future federal, state, and local legislative and/or regulatory changes, including changes in rate-setting policies or procedures, 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, energy efficiency mandates, and tax laws, including the Tax Legislation as well as those that affect our ability to use production tax credits and investment tax credits; |
• | 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; |
• | Factors affecting the implementation of WEC Energy Group's generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects; |
• | 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 changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities, or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments; |
2019 Form 10-K | 1 | Wisconsin Electric Power Company |
• | 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; |
• | 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 investment performance of our employee benefit plan assets, as well as unanticipated changes in related actuarial assumptions, which could impact future funding requirements; |
• | Factors affecting the employee workforce, including loss of key personnel, internal restructuring, work stoppages, and collective bargaining agreements and negotiations with union employees; |
• | Advances in technology, 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; |
• | Potential business strategies to acquire and dispose of assets, which cannot be assured to be completed timely or within budgets; |
• | The timing and outcome of any audits, disputes, and other proceedings related to taxes; |
• | The ability to maintain effective internal controls in accordance with SOX, while both integrating and continuing to consolidate WEC Energy Group's enterprise systems with those of its other utilities; |
• | The effect of accounting pronouncements issued periodically by standard-setting bodies; and |
• | Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents. |
We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
2019 Form 10-K | 2 | Wisconsin Electric Power Company |
PART I
ITEM 1. BUSINESS
A. INTRODUCTION
In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company. The term "utility" refers to our regulated activities, while the term "non-utility" refers to our activities that are not regulated, as well as the activities of our former subsidiary, Bostco, which was dissolved in October 2018. References to "Notes" are to the Notes to Consolidated Financial Statements included in this Annual Report on Form 10-K. See Note 2, Disposition, for more information on the sale of the remaining assets of Bostco and the dissolution of this entity.
We are a subsidiary of WEC Energy Group and were incorporated in the state of Wisconsin in 1896. We maintain our principal executive offices in Milwaukee, Wisconsin and serve customers in Wisconsin. We conduct our business primarily through our utility reportable segment.
For more information about our utility operations, including financial and geographic information, see Note 17, Segment Information, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.
Available Information
Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports are made available on WEC Energy Group's website, www.wecenergygroup.com, free of charge, as soon as reasonably practicable after they are filed with or furnished to the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov.
B. UTILITY SEGMENT
Electric Utility Operations
We generate and distribute electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin. We also served an iron ore mine customer, Tilden, in the Upper Peninsula of Michigan, through March 31, 2019 when Tilden became a customer of UMERC.
Operating Revenues
The following table shows electric utility operating revenues, including steam operations, disaggregated by customer class for the year ended December 31, 2017. For information about our operating revenues disaggregated by customer class for the years ended December 31, 2019 and 2018, see Note 4, Operating Revenues.
(in millions) | 2017 | |||
Operating revenues | ||||
Residential | $ | 1,178.4 | ||
Small commercial and industrial | 1,015.9 | |||
Large commercial and industrial | 657.3 | |||
Other | 21.2 | |||
Total retail revenues | 2,872.8 | |||
Wholesale | 118.8 | |||
Resale | 238.0 | |||
Steam | 23.3 | |||
Other operating revenues * | 83.3 | |||
Total operating revenues | $ | 3,336.2 | ||
* | Includes SSR revenues, rent income, and ancillary revenues, partially offset by revenues from Tilden that were addressed in our December 2019 Wisconsin rate order. |
2019 Form 10-K | 3 | Wisconsin Electric Power Company |
Electric Sales
Our electric energy deliveries included supply and distribution sales to retail, wholesale, and resale customers. In 2019, retail revenues accounted for 91.4% of total electric operating revenues, wholesale revenues accounted for 3.0% of total electric operating revenues, and resale revenues accounted for 4.3% of total electric operating revenues. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Operating Income for information on MWh sales by customer class.
We are authorized to provide retail electric service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities.
We buy and sell wholesale electric power by participating in the MISO Energy Markets. The cost of our individual generation offered into the MISO Energy Markets compared to our competitors affects how often our generating units are dispatched and whether we buy or sell power based on our customers' needs. We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. For more information, see D. Regulation.
The majority of our sales for resale are sold into an energy market operated by MISO at market rates based on availability of our generation and market demand. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales derived from these opportunity sales.
Steam Sales
We have a steam utility that generates, distributes, and sells steam supplied by the VAPP to customers in metropolitan Milwaukee, Wisconsin. Steam is used by customers for processing, space heating, domestic hot water, and humidification. Annual sales of steam fluctuate from year to year based on system growth and variations in weather conditions.
Electric Sales Forecast
Our service territory experienced a decline in weather-normalized retail electric sales in 2019 due primarily to reduced industrial sales. We currently forecast retail electric sales volumes to grow between 0.5% and 1.0% over the next five years, assuming normal weather. Electric peak demand is expected to grow between flat and 0.5% over the next five years.
Customers
Year Ended December 31 | |||||||||
(in thousands) | 2019 | 2018 | 2017 | ||||||
Electric customers – end of year | |||||||||
Residential | 1,022.0 | 1,016.3 | 1,009.1 | ||||||
Small commercial and industrial | 116.3 | 115.3 | 114.5 | ||||||
Large commercial and industrial | 0.7 | 0.6 | 0.7 | ||||||
Wholesale and other | 2.6 | 2.6 | 2.5 | ||||||
Total electric customers – end of year | 1,141.6 | 1,134.8 | 1,126.8 | ||||||
Steam customers – end of year | 0.4 | 0.4 | 0.4 | ||||||
Electric Commercial and Industrial Retail Customers
We provide electric utility service to a diversified base of customers in industries such as metals and other manufacturing, governmental, food products, health services, education, paper, and retail.
Electric Generation and Supply Mix
Our electric supply strategy is to provide our customers with energy from plants using a diverse fuel mix that is expected to balance a stable, reliable, and affordable supply of electricity with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Through our participation in the MISO Energy Markets, we supply
2019 Form 10-K | 4 | Wisconsin Electric Power Company |
a significant amount of electricity to our customers from power plants that we own or lease from We Power. We supplement our internally generated power supply with long-term power purchase agreements, including the Point Beach power purchase agreement discussed under the heading "Power Purchase Commitments," and through spot purchases in the MISO Energy Markets. We also sell excess power supply into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power. All options, including owned generation resources and purchased power opportunities, are continually evaluated on a real-time basis to select and dispatch the lowest-cost resources available to meet system load requirements.
The table below indicates our sources of electric energy supply as a percentage of sales for the three years ended December 31, as well as estimates for 2020:
Estimate (1) | Actual | |||||||||||
2020 | 2019 | 2018 | 2017 | |||||||||
Company-owned or leased generation units: | ||||||||||||
Coal | 35.6 | % | 36.3 | % | 45.5 | % | 50.8 | % | ||||
Natural gas: | ||||||||||||
Combined cycle | 23.1 | % | 25.1 | % | 17.7 | % | 14.7 | % | ||||
Steam turbine | 1.4 | % | 1.2 | % | 0.8 | % | 1.1 | % | ||||
Natural gas/oil peaking units | 0.2 | % | 0.6 | % | 0.8 | % | 0.5 | % | ||||
Renewables (2) | 4.1 | % | 4.0 | % | 3.7 | % | 3.8 | % | ||||
Total company-owned or leased generation units | 64.4 | % | 67.2 | % | 68.5 | % | 70.9 | % | ||||
Power purchase contracts: | ||||||||||||
Nuclear | 29.0 | % | 28.8 | % | 27.1 | % | 25.2 | % | ||||
Natural gas | 4.2 | % | 2.7 | % | 2.3 | % | 1.8 | % | ||||
Renewables (2) | 1.1 | % | 0.7 | % | 1.3 | % | 1.8 | % | ||||
Total power purchase contracts | 34.3 | % | 32.2 | % | 30.7 | % | 28.8 | % | ||||
Purchased power from MISO | 1.3 | % | 0.6 | % | 0.8 | % | 0.3 | % | ||||
Total purchased power | 35.6 | % | 32.8 | % | 31.5 | % | 29.1 | % | ||||
Total electric utility supply | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||
(1) | The values included in the forecast assume a natural gas price based on the February 2020 NYMEX. |
(2) | Includes hydroelectric, biomass, and wind generation. |
Electric Generation Facilities
Our generation portfolio is a mix of energy resources having different operating characteristics and fuel sources designed to balance providing energy that is stable, reliable, and affordable with environmental stewardship. We own or lease approximately 4,754 MW of generation capacity, including owned and leased facilities. Our facilities include coal-fired plants, natural gas-fired plants, and renewable generation. Certain of our natural gas fired generation units have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our facilities, see Item 2. Properties.
Generation from Leased W.E. Power, LLC Units
We also supply electricity to our customers from power plants that we lease from We Power. These plants include the ERGS units and the PWGS units. Lease payments are billed from We Power to us and then recovered in our rates as authorized by the PSCW and the FERC. We operate the We Power units and are authorized by the PSCW and state law to fully recover prudently incurred operating and maintenance costs in our electric rates. As the operator of the units, we may request We Power to make capital improvements to, or further investments in, the units. Under the lease terms, these capital improvements or further investments will increase lease payments paid by us and should ultimately be recovered in our rates.
Reshaping our Generation Fleet
An integral part of our electric supply strategy is tied to WEC Energy Group's planned reshaping of its generation fleet to balance reliability and customer cost with environmental stewardship. 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. In 2019, WEC Energy Group met and exceeded its 2030 goal of reducing CO2 emissions by 40% below 2005 levels and is re-evaluating its longer-term CO2 reduction goals. We have already retired approximately 1,500 MW of coal-fired generation since the beginning of 2018, including the
2019 Form 10-K | 5 | Wisconsin Electric Power Company |
2018 retirement of the Pleasant Prairie power plant as well as the March 2019 retirement of the PIPP. For more information about the retirement of these plants, see Note 6, Property, Plant, and Equipment.
Renewable Generation
We meet a portion of our electric generation supply with various renewable energy resources, including wind, hydroelectric, biomass, and in the future, solar projects. This helps us maintain compliance with renewable energy legislation. These renewable energy resources also help us maintain diversity in our generation portfolio, which effectively serves as a price hedge against future fuel costs, and will help mitigate the risk of potential unknown costs associated with any future carbon restrictions for electric generators.
In December 2018, we received approval from the PSCW for the Dedicated Renewable Energy Resource pilot program, a program for customers who wish to access a large-scale renewable project located in Wisconsin that we would operate. The project will contribute toward meeting our peak demand, adding up to 150 MW of renewables to our portfolio.
Solar
In December 2018, we received approval from the PSCW for the Solar Now pilot program, which is expected to add 35 MW of solar generation to our portfolio and will allow non-profit and government entities, as well as commercial and industrial customers to site solar arrays on their property. Under this program, in 2019, we constructed 5 MW of solar generation and expects to construct more than double that amount in 2020.
As part of WEC Energy Group's commitment to invest in zero-carbon generation, we, along with an unaffiliated utility, filed an application in August 2019 with the PSCW for approval to acquire an ownership interest in a proposed utility-scale solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to our receipt and review of a final written order from the PSCW. Once constructed, we will own 100 MW of the output of this project. Commercial operation of Badger Hollow II is targeted for the end of 2021.
Electric System Reliability
The PSCW requires us to maintain a planning reserve margin above our projected annual peak demand forecast to help ensure reliability of electric service to our customers. These planning reserve requirements are consistent with the MISO calculated planning reserve margin. In 2008, the PSCW established a 14.5% reserve margin requirement for long-term planning (planning years two through ten). For short-term planning (planning year one), the PSCW requires Wisconsin utilities to follow the planning reserve margin established by MISO. MISO has a 16.8% installed capacity reserve margin requirement for the planning year from June 1, 2019, through May 31, 2020, and an 18.0% installed capacity reserve margin requirement for the planning year from June 1, 2020, through May 31, 2021. MISO's short-term reserve margin requirements experience year-to-year fluctuations, primarily due to changes in the average generation resource mix and forced outage rate of generation within the MISO footprint.
We have adequate capacity through company-owned generation units, leased generating units, and power purchase contracts to meet the MISO calculated planning reserve margin during the current planning year. We also fully anticipate that we will have adequate capacity to meet the planning reserve margin requirements for the upcoming planning year.
Fuel and Purchased Power Costs
Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. For more information about the fuel rules, see D. Regulation.
2019 Form 10-K | 6 | Wisconsin Electric Power Company |
Our average fuel and purchased power costs per MWh by fuel type were as follows for the years ended December 31:
2019 | 2018 | 2017 | ||||||||||
Coal | $ | 22.05 | $ | 22.39 | $ | 22.26 | ||||||
Natural gas combined cycle | 19.35 | 22.05 | 22.85 | |||||||||
Natural gas/oil peaking units | 53.66 | 63.29 | 60.44 | |||||||||
Biomass | 102.99 | 97.33 | 118.76 | |||||||||
Purchased power | 46.90 | 45.66 | 45.50 | |||||||||
We purchase coal under long-term contracts, which helps with price stability. In the past, coal and associated transportation services were exposed to volatility in pricing due to changing domestic and world-wide demand for coal and diesel fuel. We have PSCW approval for a hedging program to moderate this volatility exposure. This program allows us to hedge, over a 36-month period, up to 75% of our potential risks related to rail transportation fuel surcharge exposure. The results of this hedging program, when used, are reflected in the average costs of purchased power.
We purchase natural gas for our plants on the spot market from natural gas marketers, utilities, and producers, and we arrange for transportation of the natural gas to our plants. We have firm and interruptible transportation, as well as balancing and storage agreements, intended to support our plants' variable usage. We also have PSCW approval for a hedging program to moderate volatility related to natural gas price risk. This program allows us to hedge, over a 36-month period, up to 75% of our estimated natural gas use for electric generation. The results of this hedging program are reflected in the average costs of natural gas.
Coal Supply
We diversify the coal supply for our leased and owned electric generating facilities by purchasing coal from several mines in Wyoming and Pennsylvania, as well as from various other states. For 2020, approximately 95% of our total projected coal requirements of 6.9 million tons are contracted under fixed-price contracts. See Note 19, Commitments and Contingencies, for more information on amounts of coal purchases and coal deliveries under contract.
The annual tonnage amounts contracted for the next three years are as follows. We have not entered into any coal contracts for years after 2022.
(in thousands) | Annual Tonnage | ||
2020 | 6,570 | ||
2021 | 3,200 | ||
2022 | 1,500 | ||
Coal Deliveries
All of our 2020 coal requirements are expected to be shipped by our owned or leased unit trains under existing transportation agreements. The unit trains transport the coal for electric generating facilities from mines in Wyoming and Pennsylvania. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.
Power Purchase Commitments
We enter into short and long-term power purchase commitments to meet a portion of our anticipated electric energy supply needs. Our power purchase commitments with unaffiliated parties are 1,279 MW per year for 2020 and 2021 and 1,033 MW per year for 2022 through 2024, which exclude planning capacity purchases. These amounts include 1,033 MW per year related to a long-term power purchase agreement for electricity generated by Point Beach. As part of WEC Energy Group's generation reshaping plan, we recently retired some of our older, less efficient coal-fired generation. To procure additional planning capacity, we purchased capacity from the MISO annual auction to ensure that we maintain our compliance with planning reserve requirements as established by the PSCW and MISO.
Seasonality
Our electric utility sales are impacted by seasonal factors and varying weather conditions. We sell more electricity during the summer months because of the residential cooling load. We continue to upgrade our electric distribution system, including substations, transformers, and lines, to meet the demand of our customers. Our generating plants performed as expected during the
2019 Form 10-K | 7 | Wisconsin Electric Power Company |
warmest periods of the summer, and all power purchase commitments under firm contract were received. During this period, we did not require public appeals for conservation, and we did not interrupt or curtail service to non-firm customers who participate in load management programs. However, during the polar vortex in the first quarter of 2019, we curtailed electric service to certain non-firm customers at MISO's request, in response to widespread regional power supply issues in MISO. These non-firm customers receive a rate credit in return for agreeing to occasional service interruptions.
Competition
We face competition from various entities and other forms of energy sources available to customers, including self-generation by customers and alternative energy sources. We compete with other utilities for sales to municipalities and cooperatives as well as with other utilities and marketers for wholesale electric business.
For more information on competition in our service territory, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.
Natural Gas Utility Operations
We are authorized to provide retail natural gas distribution service in designated territories in the state of Wisconsin, as established by indeterminate permits and boundary agreements with other utilities. We operate in three distinct service areas including west and south of the City of Milwaukee, the Appleton area, and areas within Iron and Vilas Counties, Wisconsin.
We provide natural gas utility service to residential, commercial and industrial, and transportation customers. Major industries served include governmental, food products, education, metals manufacturing, and paper. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Utility Segment Contribution to Operating Income for information on natural gas sales volumes by customer class.
Operating Revenues
The following table shows natural gas utility operating revenues disaggregated by customer class for the year ended December 31, 2017. For information about our operating revenues disaggregated by customer class for the years ended December 31, 2019 and 2018, see Note 4, Operating Revenues.
(in millions) | 2017 | |||
Operating revenues | ||||
Residential | $ | 249.0 | ||
Commercial and industrial | 114.3 | |||
Total retail revenues | 363.3 | |||
Transport | 13.7 | |||
Other operating revenues * | (1.5 | ) | ||
Total operating revenues | $ | 375.5 | ||
* | Includes amounts refunded to customers for purchased gas adjustment costs. |
Natural Gas Sales Forecast
Our service territory experienced growth in weather-normalized retail natural gas deliveries (excluding natural gas deliveries for electric generation) in 2019 due to customer growth. We currently forecast retail natural gas delivery volumes to grow at a rate between flat and 0.5% over the next five years, assuming normal weather.
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Customers
Year Ended December 31 | |||||||||
(in thousands) | 2019 | 2018 | 2017 | ||||||
Customers – end of year | |||||||||
Residential | 452.9 | 449.4 | 445.9 | ||||||
Commercial and industrial | 40.1 | 39.9 | 39.6 | ||||||
Transport | 0.9 | 0.8 | 0.8 | ||||||
Total customers | 493.9 | 490.1 | 486.3 | ||||||
Natural Gas Supply, Pipeline Capacity and Storage
We have been able to meet our contractual obligations with both our suppliers and our customers. For more information on our natural gas utility supply and transportation contracts, see Note 19, Commitments and Contingencies.
Pipeline Capacity and Storage
The interstate pipelines serving Wisconsin originate in major natural gas producing areas of North America: the Oklahoma and Texas basins, western Canada, and the Rocky Mountains. We have contracted for long-term firm capacity from a number of these sources. This strategy reflects management's belief that overall supply security is enhanced by geographic diversification of the supply portfolio.
Due to variations in natural gas usage in Wisconsin, we have also contracted for substantial underground storage capacity, primarily in Michigan. We target storage inventory levels at approximately 40% of forecasted demand for November through March. Diversity of natural gas supply enables us to manage significant changes in demand and to optimize our overall natural gas supply and capacity costs. We generally inject natural gas into storage during the spring and summer months and withdraw it in the winter months.
In June 2017, our parent company completed its acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. We have entered into a long-term service agreement to take a portion of the storage from Bluewater. See Note 3, Related Parties, for more information on this transaction.
We hold daily transportation and storage capacity entitlements with interstate pipeline companies as well as other service providers under varied-length long-term contracts.
Natural gas pipeline capacity and storage and natural gas supplies under contract can be resold in secondary markets. Peak or near-peak demand generally occurs only a few times each year. The secondary markets facilitate utilization of capacity and supply during times when the contracted capacity and supply are in excess of utility demand. The proceeds from these transactions are passed through to customers, subject to our approved GCRM. For information on our GCRM, see Note 1(d), Operating Revenues.
To ensure a reliable supply of natural gas during peak winter conditions, we have LNG and propane facilities located within our distribution system. These facilities are typically utilized during extreme demand conditions to ensure reliable supply to our customers. In addition to our existing facilities, we plan to construct an additional LNG facility. Subject to PSCW approval, the facility would provide us with approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. Commercial operation of the LNG facility is targeted for the end of 2023.
Combined with our storage capability, management believes that the volume of natural gas under contract is sufficient to meet our forecasted firm peak-day and seasonal demand. Our forecasted design peak-day throughput is 10.1 million therms for the 2019 through 2020 heating season. Our peak daily send-out during 2019 was 8.0 million therms on January 30, 2019.
Natural Gas Supply
We have contracts with suppliers for natural gas acquired in the Chicago, Illinois market hub and in the producing areas discussed above. The pricing of the term contracts is based upon first of the month indices.
We expect to continue to make natural gas purchases in the spot market as price and other circumstances dictate. We have supply relationships with a number of sellers from whom we purchase natural gas in the spot market.
2019 Form 10-K | 9 | Wisconsin Electric Power Company |
Hedging Natural Gas Supply Prices
We have PSCW approval to hedge up to 60% of planned winter demand and up to 15% of planned summer demand using a mix of NYMEX-based natural gas options and futures contracts. This approval allows us to pass 100% of the hedging costs (premiums, brokerage fees and losses) and proceeds (gains) to customers through our GCRM.
To the extent that opportunities develop and physical supply operating plans are supportive, we also have PSCW approval to utilize NYMEX-based natural gas derivatives to capture favorable forward market price differentials. That approval provides for 100% of the related proceeds to accrue to our GCRM.
Seasonality
Since the majority of our customers use natural gas for heating, customer use is sensitive to weather and is generally higher during the winter months. Accordingly, we are subject to some variations in earnings and working capital throughout the year as a result of changes in weather.
Our working capital needs are met by cash generated from operations and debt (both long-term and short-term). The seasonality of natural gas revenues causes the timing of cash collections to be concentrated from January through June. A portion of our winter natural gas supply needs is typically purchased and stored from April through November. Also, planned capital spending on our natural gas distribution facilities is concentrated in April through November. Because of these timing differences, the cash flow from customers is typically supplemented with temporary increases in short-term borrowings (from external sources) during the late summer and fall. Short-term debt is typically reduced over the January through June period.
Competition
We face varying degrees of competition from other entities and other forms of energy available to consumers. Many large commercial and industrial customers have the ability to switch between natural gas and alternative fuels. In addition, all of our customers have the opportunity to choose a natural gas supplier other than us. We offer natural gas transportation services for customers that elect to purchase natural gas directly from a third-party supplier. We continue to earn distribution revenues from these transportation customers for their use of our distribution systems to transport natural gas to their facilities. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs.
For more information on competition in our service territory, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.
C. OTHER SEGMENT
Our other segment included Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. See Note 2, Disposition, for more information.
D. REGULATION
In addition to the specific regulations noted below, we are also subject to various other regulations, which primarily consist of regulations, where applicable, of the EPA, the WDNR, and the United States Army Corps of Engineers.
2019 Form 10-K | 10 | Wisconsin Electric Power Company |
Rates
Our rates were regulated by the various commissions shown in the table below during 2019. These commissions have general supervisory and regulatory powers over public utilities in their respective jurisdictions.
Regulated Rates | Regulatory Commission | |
Retail electric, natural gas, and steam | PSCW | |
Retail electric | MPSC * | |
Wholesale power | FERC | |
* | Tilden, an iron-ore mine in the Upper Peninsula of Michigan, was our customer through March 31, 2019. Tilden became a customer of UMERC when UMERC's new natural gas-fired generation in the Upper Peninsula began commercial operation. As a result, we no longer have any retail customers in Michigan and our retail electric rates were not regulated by the MPSC after March 31, 2019. |
Embedded within our electric rates is an amount to recover fuel and purchased power costs. The Wisconsin retail fuel rules require us to defer, for subsequent rate recovery or refund, any under-collection or over-collection of fuel and purchased power costs that are outside of our symmetrical fuel cost tolerance, which the PSCW typically sets at plus or minus 2% of our approved fuel and purchased power cost plan. Our deferred fuel and purchased power costs are subject to an excess revenues test. If our ROE in a given year exceeds the ROE authorized by the PSCW, the recovery of under-collected fuel and purchased power costs would be reduced by the amount by which our return exceeds the authorized amount. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our wholesale electric customers.
Our natural gas utility operates under a GCRM as approved by the PSCW. Generally, the GCRM allows for a dollar-for-dollar recovery of prudently incurred natural gas costs.
See Note 1(d), Operating Revenues, for more information on the significant mechanisms we had in place during 2019 that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts.
We have been subject to an earnings sharing mechanism since January 2016. See Note 21, Regulatory Environment, for more information on our earnings sharing mechanism and on how our rates are set. Orders from our respective regulators can be viewed at the following websites:
Regulatory Commission | Website | |
PSCW | https://psc.wi.gov/ | |
FERC | http://www.ferc.gov/ | |
The material and information contained on these websites are not intended to be a part of, nor are they incorporated by reference into, this Annual Report on Form 10-K.
The following table compares our utility operating revenues by regulatory jurisdiction for each of the three years ended December 31:
2019 | 2018 | 2017 | |||||||||||||||||||
(in millions) | Amount | Percent | Amount | Percent | Amount | Percent | |||||||||||||||
Electric | |||||||||||||||||||||
Wisconsin | $ | 2,840.7 | 91.7 | % | $ | 2,876.8 | 89.4 | % | $ | 2,901.2 | 87.0 | % | |||||||||
Michigan * | 26.1 | 0.9 | % | 83.8 | 2.6 | % | 78.2 | 2.3 | % | ||||||||||||
FERC – Wholesale * | 229.9 | 7.4 | % | 258.2 | 8.0 | % | 356.8 | 10.7 | % | ||||||||||||
Total | 3,096.7 | 100.0 | % | 3,218.8 | 100.0 | % | 3,336.2 | 100.0 | % | ||||||||||||
Natural Gas – Wisconsin | 400.0 | 100.0 | % | 406.2 | 100.0 | % | 375.5 | 100.0 | % | ||||||||||||
Total utility operating revenues | $ | 3,496.7 | $ | 3,625.0 | $ | 3,711.7 | |||||||||||||||
* | Tilden was our customer through March 31, 2019. Tilden became a customer of UMERC when UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. Prior to its new generating units achieving commercial operation, UMERC purchased |
2019 Form 10-K | 11 | Wisconsin Electric Power Company |
a portion of its power from us. The revenues received from UMERC are primarily included in the FERC – Wholesale line above. See Note 3, Related Parties, for additional information on UMERC.
Electric Transmission, Capacity, and Energy Markets
In connection with its status as a FERC-approved RTO, MISO operates bid-based energy markets. MISO has been able to assume significant balancing area responsibilities such as frequency control and disturbance control.
In MISO, base transmission costs are currently being paid by load-serving entities located in the service territories of each MISO transmission owner. The FERC has previously confirmed the use of the current transmission cost allocation methodology. Certain additional costs for new transmission projects are allocated throughout the MISO footprint.
As part of MISO, a market-based platform is used for valuing transmission congestion premised upon the LMP system that is used in certain northeastern and mid-Atlantic states. The LMP system includes the ability to hedge transmission congestion costs through ARRs and FTRs. ARRs are allocated to market participants by MISO, and FTRs are purchased through auctions. A new allocation and auction were completed for the period of June 1, 2019, through May 31, 2020. The resulting ARR allocation and the secured FTRs are expected to mitigate our transmission congestion risk for that period.
MISO has an annual zonal resource adequacy requirement to ensure there is sufficient generation capacity to serve the MISO market. To meet this requirement, capacity resources can be acquired through MISO's annual capacity auction, bilateral contracts for capacity, or provided from generating or demand response resources. All of our capacity requirements during the planning year from June 1, 2019, through May 31, 2020 were met.
Other Electric Regulations
We are subject to the Federal Power Act and the corresponding regulations developed by certain federal agencies. The Energy Policy Act amended the Federal Power Act in 2005 to, among other things, make electric utility industry consolidation more feasible, authorize the FERC to review proposed mergers and the acquisition of generation facilities, change the FERC regulatory scheme applicable to qualifying cogeneration facilities, and modify certain other aspects of energy regulations and federal tax policies applicable to us. Additionally, the Energy Policy Act created an Electric Reliability Organization to be overseen by the FERC, which established mandatory electric reliability standards and has the authority to levy monetary sanctions for failure to comply with these standards.
We are subject to Act 141 in Wisconsin which contains certain minimum requirements for renewable energy generation.
All of our hydroelectric facilities follow FERC guidelines and/or regulations.
Other Natural Gas Regulations
Almost all of the natural gas we distribute is transported to our distribution systems by interstate pipelines. The pipelines' transportation and storage services are regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978. In addition, the Pipeline and Hazardous Materials Safety Administration and the PSCW are responsible for monitoring and enforcing requirements governing our natural gas safety compliance programs for our pipelines under United States Department of Transportation regulations. These regulations include 49 CFR Part 191 (Transportation of Natural and Other Gas by Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports), 49 CFR Part 192 (Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards), and 49 CFR Part 195 (Transportation of Hazardous Liquids by Pipeline).
We are required to provide natural gas service and grant credit (with applicable deposit requirements) to customers within our service territory. We are generally not allowed to discontinue natural gas service during winter moratorium months to residential heating customers who do not pay their bills. Federal and certain state governments have programs that provide for a limited amount of funding for assistance to our low-income customers.
E. ENVIRONMENTAL COMPLIANCE
Our operations, especially as they relate to our coal-fired generating facilities, are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental
2019 Form 10-K | 12 | Wisconsin Electric Power Company |
remediation, and management of natural resources. Costs associated with complying with these requirements are significant. Additional future environmental regulations or revisions to existing laws, including for example, additional regulation related to GHG emissions, coal combustion products, air emissions, water use, or wastewater discharges and other climate change issues, could significantly increase these environmental compliance costs.
Anticipated expenditures for environmental compliance and certain remediation issues for the next three years are included in the estimated capital expenditures described in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Requirements. For a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change, see Note 19, Commitments and Contingencies.
F. EMPLOYEES
As of December 31, 2019, we had 2,562 employees.
As of December 31, 2019, we had employees represented under labor agreements with the following bargaining units:
Number of Employees | Expiration Date of Current Labor Agreement | ||||
Local 2150 of International Brotherhood of Electrical Workers | 1,547 | August 15, 2020 | |||
Local 420 of International Union of Operating Engineers | 351 | September 30, 2021 | |||
Local 2006 Unit 1 of United Steel Workers of America | 103 | October 31, 2021 | |||
Local 510 of International Brotherhood of Electrical Workers | 4 | October 31, 2020 | |||
Total | 2,005 | ||||
2019 Form 10-K | 13 | Wisconsin Electric Power Company |
ITEM 1A. RISK FACTORS
We are subject to a variety of risks, many of which are beyond our control, that may adversely affect our business, financial condition, and results of operations. You should carefully consider the following risk factors, as well as the other information included in this report and other documents filed by us with the SEC from time to time, when making an investment decision.
Risks Related to Legislation and Regulation
Our business is significantly impacted by governmental regulation and oversight.
We are subject to significant state, local, and federal governmental regulation, including regulation by the PSCW and the FERC. These regulations significantly influence our operating environment, may affect our ability to recover costs from utility customers, and cause us to incur substantial compliance and other costs. Changes in regulations, interpretations of regulations, or the imposition of new regulations could also significantly impact us, including requiring us to change our business operations. Many aspects of our operations are regulated and impacted by government regulation, including, but not limited to: the rates we charge our retail electric, natural gas, and steam customers; our authorized rates of return; construction and operation of electric generating facilities and electric and natural gas distribution systems, including the ability to recover such costs; decommissioning generating facilities, the ability to recover the related costs, and continuing to recover the return on the net book value of these facilities; wholesale power service practices; electric reliability requirements and accounting; participation in the interstate natural gas pipeline capacity market; standards of service; issuance of securities; short-term debt obligations; transactions with affiliates; and billing practices. Failure to comply with any applicable rules or regulations may lead to customer refunds, penalties, and other payments, which could materially and adversely affect our results of operations and financial condition.
The rates we are allowed to charge our customers for retail and wholesale services have the most significant impact on our financial condition, results of operations, and liquidity. Rate regulation provides us an opportunity to recover prudently incurred costs and earn a reasonable rate of return on invested capital. However, our ability to obtain rate adjustments in the future is dependent upon regulatory action, and there is no assurance that our regulators will consider all of our costs to have been prudently incurred. In addition, our rate proceedings may not always result in rates that fully recover our costs or provide for a reasonable ROE. We defer certain costs and revenues as regulatory assets and liabilities for future recovery from or refund to customers, as authorized by our regulators. Future recovery of regulatory assets is not assured and is subject to review and approval by our regulators. If recovery of regulatory assets is not approved or is no longer deemed probable, these costs would be recognized in current period expense and could have a material adverse impact on our results of operations, cash flows, and financial condition.
We believe we have obtained the necessary permits, approvals, authorizations, certificates, and licenses for our existing operations, have complied in all material respects with all of their associated terms, and that our business is conducted in accordance with applicable laws. These permits, approvals, authorizations, certificates, and licenses may be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. In addition, existing regulations may be revised or reinterpreted by federal, state, and local agencies, or these agencies may adopt new laws and regulations that apply to us. We cannot predict the impact on our business and operating results of any such actions by these agencies.
If we are unable to recover costs of complying with regulations or other associated costs in customer rates in a timely manner, or if we are unable to obtain, renew, or comply with these governmental permits, approvals, authorizations, certificates, or licenses, our results of operations and financial condition could be materially and adversely affected.
We face significant costs to comply with existing and future environmental laws and regulations.
Our operations are subject to numerous federal and state environmental laws and regulations. These laws and regulations govern, among other things, air emissions (including, but not limited to: CO2, methane, mercury, SO2, and NOx), protection of natural resources, water quality, wastewater discharges, and management of hazardous, toxic, and solid wastes and substances. We incur significant costs to comply with these environmental requirements, including costs associated with the installation of pollution control equipment, environmental monitoring, emissions fees, and permits at our facilities. In addition, if we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines.
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The EPA adopted and implemented (or is in the process of implementing) regulations governing the emission of NOx, SO2, fine particulate matter, mercury, and other air pollutants under the CAA through the NAAQS, the MATS rule, the ACE rule, the Cross-State Air Pollution rule, and other air quality regulations. In addition, the EPA finalized regulations under the Clean Water Act that govern cooling water intake structures at our power plants and revised the effluent guidelines for steam electric generating plants. We continue to assess the potential cost of complying, and to explore different alternatives in order to comply, with these and other environmental regulations. In addition, as a result of the upcoming 2020 federal Presidential election and the lack of final resolution of several environmental standards, there is uncertainty as to what capital expenditures or additional costs may ultimately be required to comply with existing and future environmental laws and regulations.
Existing environmental laws and regulations may be revised or new laws or regulations may be adopted at the federal or state level that could result in significant additional expenditures for our generation units or distribution systems, including, without limitation, costs to further limit GHG emissions from our operations; operating restrictions on our facilities; and increased compliance costs. In addition, the operation of emission control equipment and compliance with rules regulating our intake and discharge of water could increase our operating costs and reduce the generating capacity of our power plants. Any such regulation may also create substantial additional costs in the form of taxes or emission allowances and could affect the availability and/or cost of fossil fuels.
As a result of these environmental laws and regulations and other factors, certain of our coal-fired electric generating facilities have become uneconomical to maintain and operate, which has resulted in these units being retired or converted to an alternative type of fuel. We retired approximately 1,500 MW of coal-fired generation since the beginning of 2018, including the 2018 retirement of the Pleasant Prairie power plant and the 2019 retirement of the PIPP. Certain of our remaining coal-fired electric generating facilities may also be retired or converted in the future. If other generation facility owners in the Midwest retire a significant number of older coal-fired generation facilities, a potential reduction in the region's capacity reserve margin below acceptable risk levels may result. This could impair the reliability of the grid in the Midwest, particularly during peak demand periods. A reduction in available future capacity could also adversely affect our ability to serve our customers' needs.
We are also subject to significant liabilities related to the investigation and remediation of environmental impacts at certain of our current and former facilities and at third-party owned sites. We accrue liabilities and defer costs (recorded as regulatory assets) incurred in connection with our former manufactured gas plant sites. These costs include all costs incurred to date that we expect to recover, management's best estimates of future costs for investigation and remediation, related legal expenses, and are net of amounts recovered (or that may be recovered) from insurance or other third parties. Due to the potential for the imposition of stricter standards and greater regulation in the future, the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, a change in conditions or the discovery of additional contamination, our remediation costs could increase, and the timing of our capital and/or operating expenditures in the future may accelerate or could vary from the amounts currently accrued.
In the event we are not able to recover all of our environmental expenditures and related costs from our customers in the future, our results of operations and financial condition could be adversely affected. Further, increased costs recovered through rates could contribute to reduced demand for electricity and natural gas, which could adversely affect our results of operations, cash flows, and financial condition.
Litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental laws and regulations has become more frequent throughout the United States. In addition to claims relating to our current facilities, we may also be subject to potential liability in connection with the environmental condition of facilities that we previously owned and operated, regardless of whether the liabilities arose before, during, or after the time we owned or operated these facilities. If we fail to comply with environmental laws and regulations or cause (or caused) harm to the environment or persons, that failure or harm may result in the assessment of civil penalties and damages against us. The incurrence of a material environmental liability or a material judgment in any action for personal injury or property damage related to environmental matters could have a significant adverse effect on our results of operations and financial condition.
We may face significant costs to comply with the regulation of greenhouse gas emissions.
Management believes it is reasonably likely that the scientific and political attention to issues concerning the existence and extent of climate change, and the role of human activity in it, will continue, with the potential for further regulation that affects our operations.
The ACE rule became effective in September 2019 and is currently being litigated by multiple states (including Wisconsin), local governments, and non-government organizations. This rule provides existing coal-fired generating units with standards for achieving
2019 Form 10-K | 15 | Wisconsin Electric Power Company |
GHG emission reductions. Every state's plan to implement ACE is required to focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. We are continuing to analyze the GHG emission profile of our electric generation resources and to work with other stakeholders to determine the potential impacts to our operations of the ACE rule and federal and state GHG regulations in general.
There is no guarantee that we will be allowed to fully recover costs incurred to comply with these and other federal and state regulations or that cost recovery will not be delayed or otherwise conditioned. GHG regulations that may be adopted in the future, at either the federal or state level, may cause our environmental compliance spending to differ materially from the amounts currently estimated. These regulations, as well as changes in the fuel markets and advances in technology, could make additional electric generating units uneconomic to maintain or operate, may impact how we operate our existing fossil-fueled power plants and biomass facility, and could affect unit retirement and replacement decisions in the future. These regulations could also adversely affect our future results of operations, cash flows, and financial condition.
In addition, our natural gas delivery systems may generate fugitive gas as a result of normal operations and as a result of excavation, construction, and repair. Fugitive gas typically vents to the atmosphere and consists primarily of methane. CO2 is also a byproduct of natural gas consumption. As a result, future regulation of GHG emissions could increase the price of natural gas, restrict the use of natural gas, cause us to accelerate the replacement and/or updating of our natural gas delivery systems, and adversely affect our ability to operate our natural gas facilities. A significant increase in the price of natural gas may increase rates for our natural gas customers, which could reduce natural gas demand.
We also continue to monitor the feasibility of taking more aggressive action to further reduce GHG emissions in order to limit future global temperature increases. These efforts could impact how we operate our electric generating units and natural gas facilities and lead to increased competition and regulation, all of which could have a material adverse effect on our operations and financial condition.
Changes in federal income tax policy may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings.
We have invested or will be investing in renewable energy generating facilities, several of which generate production tax credits and investment tax credits that we use to reduce our federal tax obligations. The amount of tax credits we earn depends on the level of electricity generated, the applicable tax credit rate, and the amount of the investment in qualifying property. If our tax credits were disallowed in whole or in part as a result of an IRS audit or changes in tax law, we could owe tax liabilities for previously recognized tax credits that could significantly impact our earnings and cash flows.
In addition, if corporate tax rates or policies are changed with future federal or state legislation, we may be required to take material charges against earnings. For example, the Tax Legislation significantly changed the United States Internal Revenue Code, including taxation of United States corporations, by, among other things, reducing the federal corporate income tax rate, limiting interest deductions, and altering the expensing of capital expenditures. Parts of the Tax Legislation still remain unclear and will require additional interpretations and implementing regulations by the Treasury Department and the IRS, as well as state income tax authorities, and the Tax Legislation could continue to be subject to potential amendments and technical corrections, any of which could lessen or increase certain adverse impacts of the Tax Legislation. State and local taxing authorities continue to evaluate the impact of the Tax Legislation, and any changes on the state or local level could lessen or increase the impacts of the Tax Legislation.
There is still uncertainty as to when or how credit rating agencies, capital markets, the FERC, or the PSCW will treat any additional impacts of the Tax Legislation. These impacts could subject us to credit rating downgrades. It is unclear whether additional opportunities may evolve for us to manage the adverse impacts of the Tax Legislation. In addition, certain financial metrics used by credit rating agencies, such as our funds from operations-to-debt percentage, could be negatively impacted by future rulings related to the Tax Legislation.
Based on our current evaluation of the Tax Legislation, we do not expect the limitations on interest deductions to materially adversely affect our earnings. Any amendments to the Tax Legislation or interpretations or implementing regulations by the Treasury Department and/or the IRS contrary to our interpretation of the Tax Legislation could limit our ability to deduct the interest on some of our outstanding debt.
There may be other material adverse effects resulting from the Tax Legislation that we have not yet identified. If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments, or technical corrections exacerbate the adverse impacts of the Tax Legislation, the Tax Legislation could have an
2019 Form 10-K | 16 | Wisconsin Electric Power Company |
adverse effect on our financial condition, results of operations, cash flows, and on the value of investments in our debt securities, and could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings.
We may fail to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act.
We are subject to reporting, disclosure control, and other obligations under SOX. SOX contains provisions requiring our management to report on the effectiveness of our internal control over financial reporting. We have undertaken, and will continue to undertake, a variety of initiatives to integrate, standardize, centralize, and streamline our operations with technology, including, but not limited to, the implementation of several different ERP systems. There is a risk that we will not be able to conclude that our internal control over financial reporting is effective because of the discovery of material weaknesses, with either our current controls and processes or with the implementation of new controls and processes around these new technologies. Any failure to maintain effective internal controls could cause investors to lose confidence in the accuracy or completeness of our financial reports, restrict our access to the capital markets, or subject us to investigations by the SEC or other regulatory authorities.
We could be subject to higher costs and penalties as a result of mandatory reliability standards.
We are subject to mandatory reliability and critical infrastructure protection standards established by the North American Electric Reliability Corporation and enforced by the FERC. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with the mandatory reliability standards could subject us to higher operating costs. If we were ever found to be in noncompliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.
Risks Related to the Operation of Our Business
Our operations are subject to risks arising from the reliability of our electric generation, transmission, and distribution facilities, natural gas infrastructure facilities, and other facilities, as well as the reliability of third-party transmission providers.
Our financial performance depends on the successful operation of our electric generation and natural gas and electric distribution facilities. The operation of these facilities involves many risks, including operator error and the breakdown or failure of equipment or processes. Potential breakdown or failure may occur due to severe weather; catastrophic events (i.e., fires, earthquakes, explosions, tornadoes, floods, droughts, pandemic health events, etc.); significant changes in water levels in waterways; fuel supply or transportation disruptions; accidents; employee labor disputes; construction delays or cost overruns; shortages of or delays in obtaining equipment, material, and/or labor; performance below expected levels; operating limitations that may be imposed by environmental or other regulatory requirements; terrorist attacks; or cyber security intrusions. Any of these events could lead to substantial financial losses.
Because our electric generation facilities are interconnected with third-party transmission facilities, the operation of our facilities could also be adversely affected by events impacting their systems. Unplanned outages at our power plants may reduce our revenues, cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses.
Insurance, warranties, performance guarantees, or recovery through the regulatory process may not cover any or all of these lost revenues or increased expenses, which could adversely affect our results of operations and cash flows.
Our operations are subject to various conditions that can result in fluctuations in energy sales to customers, including customer growth and general economic conditions in our service areas, varying weather conditions, and energy conservation efforts.
Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based upon:
• | Fluctuations in customer growth and general economic conditions in our service areas. Customer growth and energy use can be negatively impacted by population declines as well as economic factors in our service territories, including workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment. We are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn, disruption of financial markets, or reduced incentives by state government for economic development could adversely affect the financial condition of our customers and demand for their products or services. These risks could directly influence the demand for electricity and natural gas as well as the need for |
2019 Form 10-K | 17 | Wisconsin Electric Power Company |
additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.
• | Weather conditions. Demand for electricity is greater in the summer and winter months when cooling and heating is necessary. In addition, demand for natural gas peaks in the winter heating season. As a result, our overall results may fluctuate substantially on a seasonal basis. In addition, milder temperatures during the summer cooling season and during the winter heating season may result in lower revenues and net income. |
• | Our customers' continued focus on energy conservation. Our customers' use of electricity and natural gas has decreased as a result of continued individual conservation efforts, including the use of more energy efficient technologies. Customers could also voluntarily reduce their consumption of energy in response to decreases in their disposable income and increases in energy prices. Conservation of energy can be influenced by certain federal and state programs that are intended to influence how consumers use energy. For example, several states, including Wisconsin, have adopted energy efficiency targets to reduce energy consumption by certain dates. |
As part of our planning process, we estimate the impacts of changes in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced sales from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.
We are actively involved with several significant capital projects, which are subject to a number of risks and uncertainties that could adversely affect project costs and completion of construction projects.
Our business requires substantial capital expenditures for investments in, among other things, capital improvements to our electric generating facilities, electric and natural gas distribution infrastructure, and other projects, including projects for environmental compliance. We also expect to continue investing in renewable energy generating facilities as part of WEC Energy Group's generation reshaping plan.
Achieving the intended benefits of any large construction project is subject to many uncertainties, some of which we will have limited or no control over, that could adversely affect project costs and completion time. These risks include, but are not limited to, the ability to adhere to established budgets and time frames; the availability of labor or materials at estimated costs; the ability of contractors to perform under their contracts; strikes; adverse weather conditions; potential legal challenges; changes in applicable laws or regulations; the impact on global supply chains of pandemic health events; other governmental actions; continued public and policymaker support for such projects; and events in the global economy. In addition, certain of these projects require the approval of our regulators. If construction of commission-approved projects should materially and adversely deviate from the schedules, estimates, and projections on which the approval was based, our regulators may deem the additional capital costs as imprudent and disallow recovery of them through rates, and otherwise available production tax credits and investment tax credits for renewable energy projects could be lost or lose value.
To the extent that delays occur, costs become unrecoverable, tax credits are lost or lose value, or we (or third parties with whom we partner) otherwise become unable to effectively manage and complete our capital projects, our results of operations, cash flows, and financial condition may be adversely affected.
Our operations are subject to risks beyond our control, including but not limited to, cyber security intrusions, terrorist attacks, acts of war, or unauthorized access to personally identifiable information.
We have been subject to attempted cyber attacks from time to time, but these attacks have not had a material impact on our system or business operations. Despite the implementation of security measures, all assets and systems are potentially vulnerable to disability, failures, or unauthorized access due to physical or cyber security intrusions caused by human error, vendor bugs, terrorist attacks, or other malicious acts. These threats against our generation facilities, electric and natural gas distribution infrastructure, our information and technology systems, and network infrastructure, including that of third parties on which we rely, could result in a full or partial disruption of our ability to generate, transmit, purchase, or distribute electricity or natural gas or cause environmental repercussions. If our assets or systems were to fail, be physically damaged, or be breached, and were not recovered in a timely manner, we may be unable to perform critical business functions, and data, including sensitive information, could be compromised.
We operate in an industry that requires the use of sophisticated information technology systems and network infrastructure, which control an interconnected system of generation, distribution, and transmission systems shared with third parties. A successful physical or cyber security intrusion may occur despite our security measures or those that we require our vendors to take, which include compliance with reliability standards and critical infrastructure protection standards. Successful cyber security intrusions,
2019 Form 10-K | 18 | Wisconsin Electric Power Company |
including those targeting the electronic control systems used at our generating facilities and electric and natural gas transmission and distribution systems, could disrupt our operations and result in loss of service to customers. These intrusions may cause unplanned outages at our power plants, which may reduce our revenues or cause us to incur significant costs if we are required to operate our higher cost electric generators or purchase replacement power to satisfy our obligations, and could result in additional maintenance expenses. The risk of such intrusions may also increase our capital and operating costs as a result of having to implement increased security measures for protection of our information technology and infrastructure.
Our continued efforts to integrate, consolidate, and streamline our operations have also resulted in increased reliance on current and recently completed projects for technology systems, including but not limited to, a customer information and billing system, automated meter reading systems, and other similar technological tools and initiatives. We implement procedures to protect our systems, but we cannot guarantee that the procedures we have implemented to protect against unauthorized access to secured data and systems are adequate to safeguard against all security breaches. The failure of any of these or other similarly important technologies, or our inability to support, update, expand, and/or integrate these technologies with those of our affiliates could materially and adversely impact our operations, diminish customer confidence and our reputation, materially increase the costs we incur to protect against these risks, and subject us to possible financial liability or increased regulation or litigation.
Our business requires the collection and retention of personally identifiable information of our customers, shareholders, and employees, who expect that we will adequately protect such information. Security breaches may expose us to a risk of loss or misuse of confidential and proprietary information. A significant theft, loss, or fraudulent use of personally identifiable information may lead to potentially large costs to notify and protect the impacted persons, and/or could cause us to become subject to significant litigation, costs, liability, fines, or penalties, any of which could materially and adversely impact our results of operations as well as our reputation with customers, shareholders, and regulators, among others. In addition, we may be required to incur significant costs associated with governmental actions in response to such intrusions or to strengthen our information and electronic control systems. We may also need to obtain additional insurance coverage related to the threat of such intrusions.
Any operational disruption or environmental repercussions caused by these on-going threats to our assets and technology systems could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially and adversely affect our results of operations, financial condition, and cash flows. The costs of repairing damage to our facilities, operational disruptions, protecting personally identifiable information, and notifying impacted persons, as well as related legal claims, may also not be recoverable in rates, may exceed the insurance limits on our insurance policies, or, in some cases, may not be covered by insurance.
Advances in technology could make our electric generating facilities less competitive.
Advances in new technologies that produce power or reduce power consumption are ongoing and include renewable energy technologies, customer-oriented generation, energy storage devices, and energy efficiency technologies. We generate power at central station power plants to achieve economies of scale and produce power at a competitive cost. There are distributed generation technologies that produce power, including fuel cells, microturbines, wind turbines, and solar cells, which have become more cost competitive than they were in the past. It is possible that legislation or regulations could be adopted supporting the use of these technologies. There is also a risk that advances in technology will continue to reduce the costs of these alternative methods of producing power to a level that is competitive with that of central station power production. If these technologies become cost competitive and achieve economies of scale, our market share could be eroded, and the value of our generating facilities could be reduced. Advances in technology could also change the channels through which our electric customers purchase or use power, which could reduce our sales and revenues or increase our expenses.
We transport and distribute natural gas, which involves numerous risks that may result in accidents and other operating risks and costs.
Inherent in natural gas distribution activities are a variety of hazards and operational risks, such as leaks, accidental explosions, and mechanical problems, which could materially and adversely affect our results of operations, financial condition, and cash flows. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of natural gas pipelines near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation and/or administrative proceedings from time to time, which could result in substantial monetary judgments, fines, or penalties against us, or be resolved on unfavorable terms.
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We may fail to attract and retain an appropriately qualified workforce.
We operate in an industry that requires many of our employees to possess unique technical skill sets. Events such as an aging workforce without appropriate replacements, the mismatch of skill sets to future needs, or the unavailability of contract resources may lead to operating challenges or increased costs. These operating challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In addition, current and prospective employees may determine that they do not wish to work for us. Failure to hire and obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be adversely affected.
Our counterparties may fail to meet their obligations, including obligations under power purchase, natural gas supply, and transportation agreements.
We are exposed to the risk that counterparties to various arrangements who owe us money, electricity, natural gas, or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we may be required to replace the underlying commitment at current market prices or we may be unable to meet all of our customers' electric and natural gas requirements unless or until alternative supply arrangements are put in place. In such event, we may incur losses, and our results of operations, financial position, or liquidity could be adversely affected.
We have entered into several power purchase, natural gas supply, and transportation agreements with non-affiliated companies, and continue to look for additional opportunities to enter into these agreements. Revenues are dependent on the continued performance by the counterparties of their obligations under the power purchase, natural gas supply, and transportation agreements. Although we have a comprehensive credit evaluation process and contractual protections, it is possible that one or more counterparties could fail to perform their obligations under these agreements. If this were to occur, we generally would expect that any operating and other costs that were initially allocated to a defaulting customer's power purchase, natural gas supply, or transportation agreement would be reallocated among our retail customers. To the extent these costs are not allowed to be reallocated by our regulators or there is any regulatory delay in adjusting rates, a counterparty default under these agreements could have a negative impact on our results of operations and cash flows.
We may not be able to fully use tax credits, net operating losses, and/or charitable contribution carryforwards.
We have significantly reduced our federal and state income tax liability in the past through tax credits, net operating losses, and charitable contribution deductions available under the applicable tax codes. We have not fully used the allowed tax credits, net operating losses, and charitable contribution deductions in our previous tax filings. We may not be able to fully use the tax credits, net operating losses, and charitable contribution deductions available as carryforwards if our future federal and state taxable income and related income tax liability is insufficient to permit their use. In addition, any future disallowance of some or all of those tax credits, net operating losses, or charitable contribution carryforwards as a result of legislation or an adverse determination by one of the applicable taxing jurisdictions could materially affect our tax obligations and financial results.
Risks Related to Economic and Market Volatility
Our business is dependent on our ability to successfully access capital markets.
We rely on access to credit and capital markets to support our capital requirements, including expenditures for our utility infrastructure and to comply with future regulatory requirements, to the extent not satisfied by the cash flow generated by our operations. We have historically secured funds from a variety of sources, including the issuance of short-term and long-term debt securities. Successful implementation of our long-term business strategies, including capital investment, is dependent upon our ability to access the capital markets, including the banking and commercial paper markets, on competitive terms and rates. In addition, we rely on a committed bank credit agreement as back-up liquidity, which allows us to access the low cost commercial paper markets.
Our access to the credit and capital markets could be limited, or our cost of capital significantly increased, due to any of the following risks and uncertainties:
• | A rating downgrade; |
• | An economic downturn or uncertainty; |
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• | Prevailing market conditions and rules; |
• | Concerns over foreign economic conditions; |
• | Changes in tax policy; |
• | Changes in investment criteria of institutional investors; |
• | War or the threat of war; |
• | The overall health and view of the utility and financial institution industries; and |
• | Changes in the method of determining LIBOR or the replacement of LIBOR with an alternative reference rate. |
Our bank credit agreement provides for interest at variable interest rates, primarily based on LIBOR. LIBOR is the subject of recent national, international, and other regulatory guidance and proposals for reform, which may cause LIBOR to cease to exist after 2021 or to perform differently than in the past. While we expect that reasonable alternatives to LIBOR will be implemented prior to the 2021 target date, we cannot predict the consequences and timing of the development of alternative reference rates. The transition to alternative reference rates could include an increase in our interest expense and/or reduction in our interest income.
If any of these risks or uncertainties limit our access to the credit and capital markets or significantly increase our cost of capital, it could limit our ability to implement, or increase the costs of implementing, our business plan, which, in turn, could materially and adversely affect our results of operations, cash flows, and financial condition.
A downgrade in our credit ratings could negatively affect our ability to access capital at reasonable costs and/or require the posting of collateral.
There are a number of factors that impact our credit ratings, including, but not limited to, capital structure, regulatory environment, the ability to cover liquidity requirements, and other requirements for capital. We could experience a downgrade in ratings if the rating agencies determine that the level of business or financial risk of us or the utility industry has deteriorated. Changes in rating methodologies by the rating agencies could also have a negative impact on credit ratings.
Any downgrade by the rating agencies could:
• | Increase borrowing costs under our existing credit facility; |
• | Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors; |
• | Decrease funding sources by limiting our access to the commercial paper market; |
• | Limit the availability of adequate credit support for our operations; and |
• | Trigger collateral requirements in various contracts. |
See the risk factor titled "Changes in federal income tax policy may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings" above for information about how the Tax Legislation could impact our credit ratings.
Fluctuating commodity prices could negatively impact our electric and natural gas utility operations.
Our operating and liquidity requirements are impacted by changes in the forward and current market prices of natural gas, coal, electricity, renewable energy credits, and ancillary services.
We burn natural gas in several of our electric generation plants, and as a supplemental fuel at several coal-fired plants. In many instances the cost of purchased power is tied to the cost of natural gas. The cost of natural gas may increase because of disruptions in the supply of natural gas due to a curtailment in production or distribution, international market conditions, the demand for natural gas, and the availability of shale gas and potential regulations affecting its accessibility.
For Wisconsin retail electric customers, we bear the risk for the recovery of fuel and purchased power costs within a symmetrical 2% fuel tolerance band compared to the forecast of fuel and purchased power costs established in our rate structure. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our wholesale electric customers. We receive dollar-for-dollar recovery of prudently incurred natural gas costs from our natural gas customers.
Changes in commodity prices could result in:
• | Higher working capital requirements, particularly related to natural gas inventory, accounts receivable, and cash collateral postings; |
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• | Reduced profitability to the extent that lower revenues, increased bad debt, and interest expense are not recovered through rates; |
• | Higher rates charged to our customers, which could impact our competitive position; |
• | Reduced demand for energy, which could impact revenues and operating expenses; and |
• | Shutting down of generation facilities if the cost of generation exceeds the market price for electricity. |
We may not be able to obtain an adequate supply of coal, which could limit our ability to operate our coal-fired facilities.
We own and operate several coal-fired electric generating units. Although we generally carry sufficient coal inventory at our generating facilities to protect against an interruption or decline in supply, there can be no assurance that the inventory levels will be adequate. While we have coal supply and transportation contracts in place, we cannot assure that the counterparties to these agreements will be able to fulfill their obligations to supply coal to us or that we will be able to take delivery of all the coal volume contracted for. If we are unable to obtain our coal requirements under our coal supply and transportation contracts, we may be required to purchase coal at higher prices or we may be forced to reduce generation at our coal-fired units, which could lead to increased fuel costs. The increase in fuel costs could result in either reduced margins on net sales into the MISO Energy Markets, a reduction in the volume of net sales into the MISO Energy Markets, and/or an increase in net power purchases in the MISO Energy Markets. There is no guarantee that we would be able to fully recover any increased costs in rates or that recovery would not otherwise be delayed, either of which could adversely affect our cash flows.
Our use of derivative contracts could result in financial losses.
We use derivative instruments such as swaps, options, futures, and forwards to manage commodity price exposure. We could recognize financial losses as a result of volatility in the market value of these contracts or if a counterparty fails to perform. These risks are managed through risk management policies, which might not work as planned and cannot entirely eliminate the risks associated with these activities. In addition, although our hedging programs must be approved by the PSCW, derivative contracts entered into for hedging purposes might not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments can involve management's judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Restructuring in the regulated energy industry and competition in the retail and wholesale markets could have a negative impact on our business and revenues.
The regulated energy industry continues to experience significant structural changes. Deregulation or other changes in law in the states where we serve our customers could allow third-party suppliers to contract directly with customers for their natural gas and electric supply requirements. This increased competition in the retail and wholesale markets could have a significant adverse financial impact on us.
The FERC continues to support the existing RTOs that affect the structure of the wholesale market within these RTOs. In connection with its status as a FERC-approved RTO, MISO implemented bid-based energy markets that are part of the MISO Energy Markets. All market participants, including us, must submit day-ahead and/or real-time bids and offers for energy at locations across the MISO region. MISO then calculates the most efficient solution for all of the bids and offers made into the market that day and establishes an LMP that reflects the market price for energy. We are required to follow MISO's instructions when dispatching generating units to support MISO's responsibility for maintaining the stability of the transmission system. MISO also implemented an ancillary services market for operating reserves that schedules energy and ancillary services at the same time as part of the energy market, allowing for more efficient use of generation assets in the MISO Energy Markets. These market designs continue to have the potential to increase the costs of transmission, the costs associated with inefficient generation dispatching, the costs of participation in the MISO Energy Markets, and the costs associated with estimated payment settlements.
The FERC rules related to transmission are designed to facilitate competition in the wholesale electricity markets among regulated utilities, non-utility generators, wholesale power marketers, and brokers by providing greater flexibility and more choices to wholesale customers, including initiatives designed to encourage the integration of renewable sources of supply. In addition, along with transactions contemplating physical delivery of energy, financial laws and regulations impact hedging and trading based on futures contracts and derivatives that are traded on various commodities exchanges, as well as over-the-counter. Technology changes in the power and fuel industries also have significant impacts on wholesale transactions and related costs. We currently cannot predict the impact of these and other developments or the effect of changes in levels of wholesale supply and demand, which are driven by factors beyond our control.
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We may experience poor investment performance of benefit plan holdings due to changes in assumptions and market conditions.
We have significant obligations related to pension and OPEB plans. If WEC Energy Group is unable to successfully manage our benefit plan assets and medical costs, our cash flows, financial condition, or results of operations could be adversely impacted. Our cost of providing these plans is dependent upon a number of factors, including actual plan experience, changes made to the plans, and assumptions concerning the future. Types of assumptions include earnings on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation, estimated withdrawals by retirees, and our required or voluntary contributions to the plans. Plan assets are subject to market fluctuations and may yield returns that fall below projected return rates. In addition, medical costs for both active and retired employees may increase at a rate that is significantly higher than we currently anticipate. Our funding requirements could be impacted by a decline in the market value of plan assets, changes in interest rates, changes in demographics (including the number of retirements) or changes in life expectancy assumptions.
We may be unable to obtain insurance on acceptable terms or at all, and the insurance coverage we do obtain may not provide protection against all significant losses.
Our ability to obtain insurance, as well as the cost and coverage of such insurance, could be affected by developments affecting our business; international, national, state, or local events; and the financial condition of insurers and our contractors that are required to acquire and maintain insurance for our benefit. Insurance coverage may not continue to be available at all or at rates or terms similar to those presently available to us. In addition, our insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. Any losses for which we are not fully insured or that are not covered by insurance at all could materially adversely affect our results of operations, cash flows, and financial position.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
2019 Form 10-K | 23 | Wisconsin Electric Power Company |
ITEM 2. PROPERTIES
We own our principal properties outright. However, the major portion of our electric utility distribution lines, steam utility distribution mains and natural gas utility distribution mains and services are located on or under streets and highways, on land owned by others, and are generally subject to granted easements, consents, or permits. In addition, we lease the ERGS and PWGS generating units from We Power.
Electric Facilities
The following table summarizes information on generating assets we owned or leased from We Power as of December 31, 2019:
Name | Location | Fuel | Number of Generating Units | Rated Capacity In MW (1) | |||||||
Coal-fired plants | |||||||||||
ERGS | Oak Creek, WI | Coal | 2 | 1,054 | (2) | ||||||
OCPP | Oak Creek, WI | Coal | 4 | 1,075 | |||||||
Total coal-fired plants | 6 | 2,129 | |||||||||
Natural gas-fired plants | |||||||||||
Concord Combustion Turbines | Watertown, WI | Natural Gas/Oil | 4 | 361 | |||||||
Germantown Combustion Turbines | Germantown, WI | Natural Gas/Oil | 5 | 273 | |||||||
Paris Combustion Turbines | Union Grove, WI | Natural Gas/Oil | 4 | 358 | |||||||
PWGS | Port Washington, WI | Natural Gas | 2 | 1,228 | |||||||
VAPP | Milwaukee, WI | Natural Gas | 2 | 265 | |||||||
Total natural gas-fired plants | 17 | 2,485 | |||||||||
Renewables | |||||||||||
Hydro Plants (13 in number) | WI and MI | Hydro | 30 | 51 | (3) | ||||||
Rothschild Biomass Plant | Rothschild, WI | Biomass | 1 | 46 | (4) | ||||||
Wind Sites (3 in number) | WI | Wind | 198 | 43 | |||||||
Total renewables | 229 | 140 | |||||||||
Total system | 252 | 4,754 | |||||||||
(1) | Capacity for our electric generation facilities is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2020 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. |
(2) | This facility is jointly owned by We Power and two other unaffiliated entities. Our share of capacity is equal to We Power's ownership interest of 83.34%. |
(3) | All of our hydroelectric facilities follow FERC guidelines and/or regulations. |
(4) | We have a biomass power plant that uses wood waste and wood shavings to produce electric power as well as steam to support the paper mill's operations. Fuel for the power plant is supplied by both the paper mill and through contracts with biomass suppliers. The plant also has the ability to burn natural gas if wood waste and wood shavings are not available. |
As of December 31, 2019, we operated approximately 19,700 miles of overhead distribution lines and approximately 25,300 miles of underground distribution cable, as well as approximately 300 electric distribution substations and approximately 291,300 line transformers.
Natural Gas Facilities
As of December 31, 2019, our natural gas properties were located in three distinct service areas including west and south of the City of Milwaukee, the Appleton area, and areas within Iron and Vilas Counties, Wisconsin, and consisted of the following:
• | Approximately 11,800 miles of natural gas distribution mains, |
• | Approximately 415,800 natural gas lateral services, |
• | Approximately 30 gas distribution gate stations, and |
2019 Form 10-K | 24 | Wisconsin Electric Power Company |
• | LNG storage plant with a total send-out capability of 70,000 Dth per day. |
Our natural gas distribution and gas storage systems included distribution mains connected to the pipeline transmission systems of ANR Pipeline Company, Great Lakes Transmission Company, Guardian Pipeline L.L.C., Natural Gas Pipeline Company of America, and Northern Natural Gas Company. Our LNG storage plant converts and stores, in liquefied form, natural gas received during periods of low consumption.
We also own office buildings, natural gas regulating and metering stations, and major service centers, including garage and warehouse facilities, in certain communities we serve. Where distribution lines and services and natural gas distribution mains and services occupy private property, we have in some, but not all instances, obtained consents, permits or easements for these installations from the apparent owners or those in possession of those properties, generally without an examination of ownership records or title.
Steam Facilities
As of December 31, 2019, the steam system supplied by the VAPP consisted of approximately 40 miles of both high pressure and low pressure steam piping, approximately four miles of walkable tunnels, and other pressure regulating equipment.
ITEM 3. LEGAL PROCEEDINGS
In addition to those legal proceedings discussed in Note 19, Commitments and Contingencies, and Note 21, 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 4. MINE SAFETY DISCLOSURES
Not applicable.
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INFORMATION ABOUT OUR EXECUTIVE OFFICERS
The names, ages, and positions of our executive officers at December 31, 2019 are listed below along with their business experience during the past five years. All officers are appointed until they resign, die, or are removed pursuant to our Bylaws. There are no family relationships among these officers, nor is there any agreement or understanding between any officer and any other person pursuant to which the officer was selected.
J. Kevin Fletcher. Age 61.
• | WEC Energy Group — Director and Chief Executive Officer since February 2019. President since October 2018. |
• | WE — Chairman of the Board and Chief Executive Officer since February 2019. Director since June 2015. President from May 2016 to November 2018. Executive Vice President - Customer Service and Operations from June 2015 to April 2016. Senior Vice President - Customer Operations from October 2011 to June 2015. |
Robert M. Garvin. Age 53.
• | WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015. |
• | WE — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015. |
William J. Guc. Age 50.
• | WEC Energy Group — Controller since October 2015. Vice President since June 2015. |
• | WE — Vice President and Controller since October 2015. |
• | Integrys Energy Group — Vice President and Treasurer from December 2010 to June 2015. |
Margaret C. Kelsey. Age 55.
• | WEC Energy Group — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Executive Vice President from September 2017 to January 2018. |
• | WE — Executive Vice President, Corporate Secretary and General Counsel since January 2018. Director since January 2018. |
• | Modine Manufacturing Company – General Counsel, Corporate Secretary, and Vice President - Legal from April 2008 to August 2017. Vice President - Corporate Communications from April 2014 to August 2017. |
Scott J. Lauber. Age 54.
• | WEC Energy Group — Senior Executive Vice President and Chief Financial Officer since October 2019. Senior Executive Vice President, Chief Financial Officer and Treasurer from February 2019 to October 2019. Executive Vice President, Chief Financial Officer and Treasurer from October 2018 to February 2019. Executive Vice President and Chief Financial Officer from April 2016 to October 2018. Vice President and Treasurer from February 2013 to March 2016. |
• | WE — Executive Vice President and Chief Financial Officer since October 2019, and from April 2016 to October 2018. Director since April 2016. Executive Vice President, Chief Financial Officer and Treasurer from October 2018 to October 2019. Vice President and Treasurer from February 2013 to March 2016. |
Tom Metcalfe. Age 52.
• | WE — President since November 2018. Director since January 2018. Executive Vice President - Generation from April 2016 to November 2018. Senior Vice President - Power Generation from January 2014 to March 2016. |
Anthony L. Reese. Age 38.
• | WEC Energy Group — Vice President and Treasurer since October 2019. |
• | WE — Vice President and Treasurer since October 2019. |
• | Controller - Illinois from September 2015 to September 2019. Manager - Financial Planning and Analysis from May 2011 to September 2015. |
Certain executive officers also hold officer and/or director positions at WEC Energy Group's other significant subsidiaries.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There is no established public trading market for our common stock, as WEC Energy Group owns all of our outstanding common stock. See Note 8, Common Equity, for more information.
ITEM 6. SELECTED FINANCIAL DATA
WISCONSIN ELECTRIC POWER COMPANY
COMPARATIVE FINANCIAL DATA AND OTHER STATISTICS
As of or for Year Ended December 31 | ||||||||||||||||||||
(in millions) | 2019 | 2018 | 2017 * | 2016 | 2015 | |||||||||||||||
Operating revenues | $ | 3,496.7 | $ | 3,625.0 | $ | 3,711.7 | $ | 3,792.8 | $ | 3,854.1 | ||||||||||
Net income attributed to common shareholder | 362.1 | 358.3 | 335.6 | 364.3 | 375.7 | |||||||||||||||
Total assets | 13,360.8 | 13,538.3 | 13,121.6 | 13,371.5 | 13,139.6 | |||||||||||||||
Long-term debt and finance and capital lease obligations (excluding current portion) | 5,542.3 | 5,266.8 | 5,236.1 | 5,417.6 | 5,351.3 | |||||||||||||||
* | Reflects the impact of the transfer of our investment in ATC to another subsidiary of WEC Energy Group and the transfer of net assets to UMERC in 2017. See Note 3, Related Parties for more information on these transactions. |
2019 Form 10-K | 27 | Wisconsin Electric Power Company |
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CORPORATE DEVELOPMENTS
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 conduct our business primarily through our utility reportable segment. See Note 17, Segment Information, for more information on our reportable business segments.
Prior to April 1, 2019, we provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 after UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation.
Corporate Strategy
Our goal is to continue to build and sustain long-term value for our customers and shareholders by focusing on the fundamentals of our business: reliability; operating efficiency; financial discipline; customer care; and safety.
Reshaping Our Generation Fleet
WEC Energy Group has developed and is executing a plan to reshape its generation portfolio. This plan balances reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation. In 2019, WEC Energy Group met and exceeded its 2030 goal of reducing CO2 emissions by 40% below 2005 levels, and is re-evaluating its longer-term CO2 reduction goals. WEC Energy Group has already retired more than 1,800 MW of coal-fired generation since the beginning of 2018 across its electric utilities, and expects to continue adding natural gas-fired generating units and renewable generation, including utility-scale solar projects. This plan included the March 2019 retirement of the Presque Isle power plant as well as the 2018 retirement of the Pleasant Prairie power plant. See Note 6, Property, Plant, and Equipment, for information related to the plant retirements as part of WEC Energy Group's plan.
As part of WEC Energy Group's commitment to invest in zero-carbon generation, we, along with an unaffiliated utility filed an application with the PSCW for approval to acquire an ownership interest in a proposed utility-scale solar project, Badger Hollow Solar Farm II, that will be located in Iowa County, Wisconsin. At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to our receipt and review of a final written order from the PSCW. Once constructed, we will own 100 MW of the output of this project. Commercial operation of Badger Hollow Solar Farm II is targeted for the end of 2021.
In December 2018, we received approval from the PSCW for two renewable energy pilot programs. The Solar Now pilot is expected to add 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, in 2019, we constructed 5 MW of solar generation and we expect to construct more than double that amount in 2020. 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.
As the cost of renewable energy generation continues to decline, these pilot programs and the utility-scale solar project have become cost effective opportunities for us and our customers to participate in renewable energy.
WEC Energy Group also has a goal to decrease the rate of methane emissions from the natural gas distribution lines in its network by 30% per mile by the year 2030 from a 2011 baseline. WEC Energy Group was over half way toward meeting that goal at the end of 2019.
Reliability
We have made significant reliability-related investments in recent years, and plan to continue strengthening and modernizing our generation fleet and distribution networks to further improve reliability. Our investments, coupled with our commitment to
2019 Form 10-K | 28 | Wisconsin Electric Power Company |
operating efficiency and customer care, resulted in We Energies being recognized in 2019 by PA Consulting Group, an independent consulting firm, as the most reliable utility in the Midwest for the ninth year in a row. We Energies is the trade name under which we and WG, another wholly owned subsidiary of WEC Energy Group, operate.
We plan to construct an additional LNG facility. Subject to PSCW approval, the facility would provide us with approximately one billion cubic feet 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. Commercial operation of the LNG facility is targeted for the end of 2023.
Operating Efficiency
We continually look for ways to optimize the operating efficiency of our company. For example, we are making progress on our Advanced Metering Infrastructure program, replacing aging meter-reading equipment on both our network and customer property. An integrated system of smart meters, communication networks, and data management programs enables two-way communication between us and our customers. This program reduces the manual effort for disconnects and reconnects and enhances outage management capabilities.
WEC Energy Group continues to focus on integrating resources of its businesses and finding the best and most efficient processes while meeting all applicable legal and regulatory requirements. We also strive to provide the best value to our customers and WEC Energy Group's shareholders by embracing constructive change, leveraging capabilities and expertise, and using creative solutions to meet or exceed our customers' expectations.
Financial Discipline
A strong adherence to financial discipline is essential to earning our authorized ROE and maintaining a strong balance sheet, stable cash flows, and quality credit ratings.
We follow an asset management strategy that focuses on investing in and acquiring assets consistent with our strategic plans, as well as disposing of assets, including property, plants, and equipment, that are no longer performing as intended, or have an unacceptable risk profile. See Note 2, Disposition, for information on the sale of Bostco's remaining real estate holdings.
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.
Safety
We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. 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
The following discussion and analysis of our Results of Operations includes comparisons of our results for the year ended December 31, 2019 with the year ended December 31, 2018. For a similar discussion that compares our results for the year ended December 31, 2018 with the year ended December 31, 2017, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations in Part II of our 2018 Annual Report on Form 10-K.
2019 Form 10-K | 29 | Wisconsin Electric Power Company |
Consolidated Earnings
The following table compares our consolidated results for the year ended December 31, 2019 with the year ended December 31, 2018, including favorable or better, "B", and unfavorable or worse, "W", variances:
Year Ended December 31 | ||||||||||||||||||||||||
(in millions) | 2019 | 2018 | B (W) | Change Related to Flow Through of Tax Repairs | Change Related to Adoption of New Lease Guidance (Topic 842) | Remaining Change B (W) | ||||||||||||||||||
Operating revenues | $ | 3,496.7 | $ | 3,625.0 | $ | (128.3 | ) | $ | (13.7 | ) | $ | — | $ | (114.6 | ) | |||||||||
Cost of sales | 1,190.7 | 1,262.1 | 71.4 | — | 8.2 | 63.2 | ||||||||||||||||||
Other operation and maintenance | 1,053.1 | 1,502.4 | 449.3 | 10.6 | 363.3 | 75.4 | ||||||||||||||||||
Depreciation and amortization | 384.4 | 348.1 | (36.3 | ) | — | (20.6 | ) | (15.7 | ) | |||||||||||||||
Property and revenue taxes | 108.3 | 109.9 | 1.6 | — | — | 1.6 | ||||||||||||||||||
Operating income | 760.2 | 402.5 | 357.7 | (3.1 | ) | 350.9 | 9.9 | |||||||||||||||||
Other income, net | 22.7 | 20.2 | 2.5 | — | — | 2.5 | ||||||||||||||||||
Interest expense | 477.4 | 120.1 | (357.3 | ) | — | (350.9 | ) | (6.4 | ) | |||||||||||||||
Income before income taxes | 305.5 | 302.6 | 2.9 | (3.1 | ) | — | 6.0 | |||||||||||||||||
Income tax benefit | (57.8 | ) | (56.9 | ) | 0.9 | 3.1 | — | (2.2 | ) | |||||||||||||||
Preferred stock dividend requirements | 1.2 | 1.2 | — | — | — | — | ||||||||||||||||||
Net income attributed to common shareholder | $ | 362.1 | $ | 358.3 | $ | 3.8 | $ | — | $ | — | $ | 3.8 | ||||||||||||
Our consolidated earnings increased $3.8 million during 2019, compared with 2018. The table above shows the income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the adoption of ASU 2016-02, Leases (Topic 842), effective January 1, 2019. As shown in the table above, the changes related to these items had no impact on net income attributed to common shareholder, but did significantly impact our operating income. See Note 21, Regulatory Environment, for more information on the flow through of tax repairs and Note 12, Leases, for more information on the adoption of Topic 842. See below for additional information on the $3.8 million increase in consolidated earnings.
Non-GAAP Financial Measures
The discussion below addresses the operating income contribution of our utility segment and includes financial information prepared in accordance with GAAP, as well as electric margins and natural gas margins, which are not measures of financial performance under GAAP. Electric margin (electric revenues less fuel and purchased power costs) and natural gas margin (natural gas revenues less cost of natural gas sold) are non-GAAP financial measures because they exclude other operation and maintenance expense, depreciation and amortization, and property and revenue taxes.
We believe that electric and natural gas margins provide a useful basis for evaluating utility operations 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 years ended December 31, 2019 and 2018 was $760.2 million and $402.5 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.
2019 Form 10-K | 30 | Wisconsin Electric Power Company |
Utility Segment Contribution to Operating Income
Year Ended December 31 | ||||||||||||
(in millions) | 2019 | 2018 | B (W) | |||||||||
Electric revenues | $ | 3,096.7 | $ | 3,218.8 | $ | (122.1 | ) | |||||
Fuel and purchased power | 949.7 | 1,010.1 | 60.4 | |||||||||
Total electric margins | 2,147.0 | 2,208.7 | (61.7 | ) | ||||||||
Natural gas revenues | 400.0 | 406.2 | (6.2 | ) | ||||||||
Cost of natural gas sold | 241.0 | 252.0 | 11.0 | |||||||||
Total natural gas margins | 159.0 | 154.2 | 4.8 | |||||||||
Total electric and natural gas margins | 2,306.0 | 2,362.9 | (56.9 | ) | ||||||||
Other operation and maintenance | 1,053.1 | 1,502.4 | 449.3 | |||||||||
Depreciation and amortization | 384.4 | 348.1 | (36.3 | ) | ||||||||
Property and revenue taxes | 108.3 | 109.9 | 1.6 | |||||||||
Operating income | $ | 760.2 | $ | 402.5 | $ | 357.7 | ||||||
The following table shows a breakdown of other operation and maintenance:
Year Ended December 31 | ||||||||||||
(in millions) | 2019 | 2018 | B (W) | |||||||||
Operation and maintenance not included in line items below | $ | 381.5 | $ | 442.7 | $ | 61.2 | ||||||
We Power (1) | 140.9 | 506.9 | 366.0 | |||||||||
Transmission (2) | 254.8 | 265.1 | 10.3 | |||||||||
Transmission expense related to the flow through of tax repairs (3) | 67.2 | 77.8 | 10.6 | |||||||||
Transmission expense related to Tax Legislation (4) | 65.2 | 67.7 | 2.5 | |||||||||
Regulatory amortizations and other pass through expenses (5) | 98.2 | 98.1 | (0.1 | ) | ||||||||
Earnings sharing mechanism (6) | 38.6 | 37.2 | (1.4 | ) | ||||||||
Other | 6.7 | 6.9 | 0.2 | |||||||||
Total other operation and maintenance | $ | 1,053.1 | $ | 1,502.4 | $ | 449.3 | ||||||
(1) | Represents costs associated with the We Power generation units, including operating and maintenance costs we incurred. During 2018, the amount also included the lease payments that were billed from We Power to us and then recovered in our rates. We adopted ASU 2016-02, Leases (Topic 842), effective January 1, 2019, which revised the previous guidance regarding the accounting for leases. As a result of this adoption, during 2019, $363.3 million of lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as $15.8 million and $347.5 million of depreciation and amortization and interest expense, respectively, in accordance with Topic 842. |
During 2019, $134.8 million of operating and maintenance 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. During 2018, $485.3 million of both lease and operating and maintenance 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.
(2) | Represents transmission expense that we are authorized to collect in rates, in accordance with the PSCW's approval of 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 2019 and 2018, $329.4 million and $286.3 million, respectively, of costs were billed to us by transmission providers. |
(3) | Represents additional transmission expense associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018, in accordance with a settlement agreement with the PSCW, to maintain certain regulatory asset balances at their December 31, 2017 levels. See Note 21, Regulatory Environment, for more information. The decrease in transmission expense associated with the flow through of tax benefits is offset in income taxes. |
(4) | Represents additional transmission expense associated with the May 2018 PSCW order requiring us to use 80% of our current 2018 tax benefit, including the amortization associated with the revaluation of deferred taxes, to reduce our transmission regulatory asset balance. See Note 21, Regulatory Environment, for more information. |
2019 Form 10-K | 31 | Wisconsin Electric Power Company |
(5) | Regulatory amortizations and other pass through expenses are substantially offset in margins and therefore do not have a significant impact on operating income. |
(6) | See Note 21, Regulatory Environment, for more information about our earnings sharing mechanism. |
The following tables provide information on delivered volumes by customer class and weather statistics:
Year Ended December 31 | |||||||||
MWh (in thousands) | |||||||||
Electric Sales Volumes | 2019 | 2018 | B (W) | ||||||
Customer class | |||||||||
Residential | 7,818.1 | 8,025.1 | (207.0 | ) | |||||
Small commercial and industrial | 8,701.4 | 8,920.6 | (219.2 | ) | |||||
Large commercial and industrial | 7,221.8 | 8,457.9 | (1,236.1 | ) | |||||
Other | 134.8 | 138.7 | (3.9 | ) | |||||
Total retail | 23,876.1 | 25,542.3 | (1,666.2 | ) | |||||
Wholesale | 1,298.4 | 1,688.5 | (390.1 | ) | |||||
Resale | 5,213.8 | 4,931.9 | 281.9 | ||||||
Total sales in MWh | 30,388.3 | 32,162.7 | (1,774.4 | ) | |||||
Year Ended December 31 | |||||||||
Therms (in millions) | |||||||||
Natural Gas Sales Volumes | 2019 | 2018 | B (W) | ||||||
Customer class | |||||||||
Residential | 404.7 | 383.2 | 21.5 | ||||||
Commercial and industrial | 224.6 | 217.9 | 6.7 | ||||||
Total retail | 629.3 | 601.1 | 28.2 | ||||||
Transport | 343.4 | 339.2 | 4.2 | ||||||
Total sales in therms | 972.7 | 940.3 | 32.4 | ||||||
Year Ended December 31 | |||||||||
Degree Days | |||||||||
Weather * | 2019 | 2018 | B (W) | ||||||
Heating (6,556 normal) | 6,835 | 6,685 | 2.2 | % | |||||
Cooling (739 normal) | 727 | 929 | (21.7 | )% | |||||
* | Normal degree days are based on a 20-year moving average of monthly temperatures from Mitchell International Airport in Milwaukee, Wisconsin. |
2019 Compared with 2018
Electric Utility Margins
Electric utility margins decreased $61.7 million during 2019, compared with 2018. The significant factors impacting the lower electric utility margins were:
• | A $40.9 million decrease in margins related to lower sales volumes, primarily driven by cooler summer weather during 2019 compared with 2018. As measured by cooling degree days, 2019 was 21.7% cooler than 2018. |
• | A $13.7 million decrease in margins associated with the flow through of tax benefits of our repair-related deferred tax liabilities starting in 2018 in accordance with a settlement agreement with the PSCW to maintain certain regulatory assets at their December 31, 2017 levels. This decrease in margins was offset in income taxes. See Note 21, Regulatory Environment, for more information. |
2019 Form 10-K | 32 | Wisconsin Electric Power Company |
• | An $11.3 million decrease in margins related to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. Tilden, who was our customer, became a customer of UMERC after UMERC's new natural gas-fired generating units began commercial operation on March 31, 2019. |
Natural Gas Utility Margins
Natural gas utility margins increased $4.8 million during 2019, compared with 2018. The most significant factor impacting the higher natural gas utility margins was higher sales volumes, due in part to colder winter weather, customer growth, and higher use per retail customer during 2019, compared with 2018. As measured by heating degree days, 2019 was 2.2% colder than 2018.
Operating Income
Operating income at the utility segment increased $357.7 million during 2019, compared with 2018. This increase was driven by $414.6 million of lower operating expenses (which include other operation and maintenance, depreciation and amortization, and property and revenue taxes), partially offset by the $56.9 million net decrease in margins discussed above.
The utility segment experienced lower overall operating expenses related to efficiencies and effective cost control. The other significant factors impacting the decrease in operating expenses during 2019, compared with 2018, were:
• | A $363.3 million decrease in other operation and maintenance expense resulting from the adoption of the new lease guidance. As discussed under the other operation and maintenance table above, the adoption of Topic 842, effective January 1, 2019, required us to change the income statement classification of our lease payments related to the We Power leases. During 2019, the lease expense related to the We Power leases was no longer classified within other operation and maintenance, but was instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842. |
• | A $70.0 million decrease in other operation and maintenance expense related to our power plants, driven by lower maintenance and labor costs associated with our 2019 and 2018 plant retirements, and increases to certain plant-related regulatory assets resulting from decisions included in our December 2019 Wisconsin rate order. Plant retirements included the 2019 retirement of the PIPP and the 2018 retirement of the Pleasant Prairie power plant. See Note 6, Property, Plant, and Equipment, for more information on the plant retirements. See Note 21, Regulatory Environment, for more information on our Wisconsin rate order. |
• | A $10.6 million decrease in transmission expense in 2019 related to the flow through of tax repairs, as discussed in the other operation and maintenance table above. This decrease in transmission expense was offset in income taxes. |
• | A $10.3 million decrease in transmission expense in 2019 related to Tilden. Tilden, who was our customer, became a customer of UMERC after UMERC's natural gas-fired generating units began commercial operation on March 31, 2019. |
These decreases in operating expenses were partially offset by:
• | A $36.3 million increase in depreciation and amortization, driven by assets being placed into service as we continue to execute on our capital plan and additional expense recognized related to the adoption of Topic 842, as discussed in the other operation and maintenance table above. |
• | A $14.4 million net increase in benefit costs, primarily related to higher deferred compensation costs in 2019. |
Consolidated Other Income, Net
Year Ended December 31 | ||||||||||||
(in millions) | 2019 | 2018 | B (W) | |||||||||
AFUDC – Equity | $ | 3.7 | $ | 3.9 | $ | (0.2 | ) | |||||
Non-service components of net periodic benefit costs | 9.2 | 5.7 | 3.5 | |||||||||
Interest income | 2.2 | 2.2 | — | |||||||||
Other, net | 7.6 | 8.4 | (0.8 | ) | ||||||||
Other income, net | $ | 22.7 | $ | 20.2 | $ | 2.5 | ||||||
2019 Form 10-K | 33 | Wisconsin Electric Power Company |
2019 Compared with 2018
Other income, net increased $2.5 million during 2019, compared with 2018. The increase was primarily driven by higher net credits from the non-service components of our net periodic pension and OPEB costs. See Note 16, Employee Benefits, for more information on our benefit costs.
Consolidated Interest Expense
Year Ended December 31 | ||||||||||||
(in millions) | 2019 | 2018 | B(W) | |||||||||
Interest expense | $ | 477.4 | $ | 120.1 | $ | (357.3 | ) | |||||
Interest expense increased $357.3 million during 2019, compared with 2018. The increase was primarily due to the adoption of ASU 2016-02, Leases (Topic 842). Effective January 1, 2019, minimum lease payments were no longer classified within cost of sales or other operation and maintenance, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 842. As a result of the adoption, for the year ended December 31, 2019, $350.9 million of minimum lease payments were recorded as interest expense on finance lease liabilities. See Note 12, Leases, for more information.
Consolidated Income Tax Benefit
Year Ended December 31 | |||||||||
2019 | 2018 | B (W) | |||||||
Effective tax rate | (18.9 | )% | (18.8 | )% | 0.1 | % | |||
2019 Compared with 2018
Our effective tax rate decreased by 0.1% during for the year ended December 31, 2019, compared with the same period in 2018. The decrease in the effective tax rate was primarily due to the increased benefit from the flow through of tax repairs in connection with the 2017 Wisconsin rate settlement, and the impact of the 2018 PSCW order regarding the benefits associated with the Tax Legislation. The impacts of the 2018 PSCW order related to the Tax Legislation and the flow through of tax repairs were offset in operating income at the utility segment. See Note 13, Income Taxes, and Note 21, Regulatory Environment, for more information.
We expect our 2020 annual effective tax rate to be between 12% and 13%, which includes an estimated 10% 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 2020 range would be between 22% and 23%.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion and analysis of our Liquidity and Capital Resources includes comparisons of our cash flows for the year ended December 31, 2019 with the year ended December 31, 2018. For a similar discussion that compares our cash flows for the year ended December 31, 2018 with the year ended December 31, 2017, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources in Part II of our 2018 Annual Report on Form 10-K.
Cash Flows
The following table summarizes our cash flows during the years ended December 31:
(in millions) | 2019 | 2018 | Change in 2019 Over 2018 | |||||||||
Cash provided by (used in): | ||||||||||||
Operating activities | $ | 854.4 | $ | 962.2 | $ | (107.8 | ) | |||||
Investing activities | (576.9 | ) | (640.4 | ) | 63.5 | |||||||
Financing activities | (278.6 | ) | (313.9 | ) | 35.3 | |||||||
2019 Form 10-K | 34 | Wisconsin Electric Power Company |
Operating Activities
2019 Compared with 2018
Net cash provided by operating activities decreased $107.8 million during 2019, compared with 2018. Cash paid for interest increased $360.2 million during 2019, compared with 2018, as a result of our adoption of ASU 2016-02, Leases (Topic 842), on January 1, 2019. This increase was offset by a corresponding decrease in cash paid for other operation and maintenance. As a result, this reclassification did not have a significant impact on our cash flows from operating activities and is not reflected in the following discussion. As shown below, the only cash flow item significantly impacted by Topic 842 related to the classification of our principal payments for finance leases. See Note 12, Leases, for more information. The $107.8 million decrease in net cash provided by operating activities was driven by:
• | A $109.1 million decrease in cash related to lower overall collections from customers, primarily due to lower sales volumes driven by cooler summer weather during 2019, compared with 2018. Also contributing to this decrease was the transfer of a customer to UMERC. Tilden, the owner of an iron ore mine in the Upper Peninsula of Michigan, became a customer of UMERC on April 1, 2019. |
• | A $38.2 million decrease in cash due to higher collateral requirements in 2019, compared with 2018, driven by funding for both open natural gas contracts and settled natural gas contracts. See Note 15, Derivative Instruments, for more information. |
• | A $28.1 million decrease in cash related to an increase in cash paid for income taxes during 2019, compared with 2018. This decrease in cash was primarily due to the utilization of fewer than expected wind production tax credits in our 2018 federal income tax return, which we filed during 2019. |
These decreases in net cash provided by operating activities were partially offset by:
• | A $50.5 million increase in cash related to a change in the cash flow classification of our principal payments for finance lease obligations due to our adoption of Topic 842. Under Topic 842, our principal payments for finance lease obligations were no longer classified as cash outflows from operating activities during 2019, but were instead classified as cash outflows from financing activities. See Note 12, Leases, for more information on Topic 842 and our finance lease obligations. |
• | A $26.7 million increase in cash primarily related to lower payments for fuel and purchased power during 2019, compared with 2018. Our payments for fuel and purchased power decreased due to the cooler summer weather during 2019 and due to the retirements of the Pleasant Prairie power plant in April 2018 and the PIPP in March 2019. |
Investing Activities
2019 Compared with 2018
Net cash used in investing activities decreased $63.5 million during 2019, compared with 2018, driven by:
• | Net payments of $51.0 million to affiliates during 2018 related to transfers of an ERP system, other software, and equipment. |
• | A $12.6 million decrease in cash paid for capital expenditures during 2019, compared with 2018, which is discussed in more detail below. |
Capital Expenditures
Capital expenditures for the years ended December 31 were as follows:
(in millions) | 2019 | 2018 | Change in 2019 Over 2018 | |||||||||
Capital expenditures | $ | 590.6 | $ | 603.2 | $ | (12.6 | ) | |||||
2019 Form 10-K | 35 | Wisconsin Electric Power Company |
2019 Compared with 2018
The decrease in cash paid for capital expenditures during 2019, compared with 2018, was primarily driven by projects at the OCPP and upgrades to our electric distribution system during 2018. These decreases in cash paid for capital expenditures were partially offset by increased capital expenditures during 2019 for an information technology project created to improve our billing, call center, and credit collection functions.
See Capital Resources and Requirements – Capital Requirements – Significant Capital Projects below for more information.
Financing Activities
2019 Compared with 2018
Net cash used in financing activities decreased $35.3 million during 2019, compared with 2018, driven by:
• | A $77.0 million increase in equity contributions received from our parent during 2019, compared with 2018, to balance our capital structure. |
• | A $56.6 million increase in cash related to lower net repayments of commercial paper during 2019, compared with 2018. |
These increases in cash were partially offset by:
• | A $50.5 million decrease in cash related to a change in the cash flow classification of our principal payments for finance lease obligations due to our adoption of Topic 842, as discussed above. |
• | A $50.0 million decrease in cash due to higher dividends paid to our parent during 2019, compared with 2018, to balance our capital structure. |
Significant Financing Activities
For more information on our financing activities, see Note 10, Short-Term Debt and Lines of Credit, and Note 11, 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 both internally and externally to meet our capital requirements. Our ability to attract the necessary financial capital at reasonable terms is critical to our overall strategic plan. We currently believe that we have adequate capacity to fund our operations for the foreseeable future through our existing borrowing arrangements, access to capital markets, and internally generated cash.
We maintain a bank back-up credit facility, which provides liquidity support for our obligations with respect to commercial paper and for general corporate purposes. We review our bank back-up credit facility needs on an ongoing basis and expect to be able to maintain adequate credit facilities to support our operations. See Note 10, Short-Term Debt and Lines of Credit, for more information on our credit facility.
At December 31, 2019, we were in compliance with all covenants related to outstanding short-term and long-term debt. We expect to be in compliance with all such debt covenants for the foreseeable future. See Note 11, Long-Term Debt, for more information.
2019 Form 10-K | 36 | Wisconsin Electric Power Company |
Working Capital
Although not the case as of December 31, 2019, our current liabilities sometimes exceed our current assets. We do not expect this to have any impact on our liquidity since we believe we have adequate back-up lines of credit in place for our ongoing operations. We also believe that we can access the capital markets to finance our construction programs and to refinance current maturities of long-term debt, if necessary.
Credit Rating Risk
We do not have any credit agreements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. However, we have certain agreements in the form of commodity contracts and employee benefit plans that could require collateral or a termination payment in the event of a credit rating change to below BBB- at S&P Global Ratings and/or Baa3 at Moody's Investors Service. We also have other commodity contracts that, in the event of a credit rating downgrade, could result in a reduction of our unsecured credit granted by counterparties.
In addition, access to capital markets at a reasonable cost is determined in large part by credit quality. Any credit ratings downgrade could impact our ability to access capital markets.
Subject to other factors affecting the credit markets as a whole, we believe our current ratings should provide a significant degree of flexibility in obtaining funds on competitive terms. However, these security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell, or hold securities. Any rating can be revised upward or downward or withdrawn at any time by a rating agency.
If we are unable to successfully take actions to manage any adverse impacts of the Tax Legislation, or if additional interpretations, regulations, amendments or technical corrections exacerbate the adverse impacts of the Tax Legislation, the legislation could result in credit rating agencies placing our credit ratings on negative outlook or downgrading our credit ratings. Any such actions by credit rating agencies may make it more difficult and costly for us to issue future debt securities and certain other types of financing and could increase borrowing costs under our credit facility.
Capital Requirements
Contractual Obligations
We have the following contractual obligations and other commercial commitments as of December 31, 2019:
Payments Due by Period (1) | ||||||||||||||||||||
(in millions) | Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |||||||||||||||
Long-term debt obligations (2) | $ | 5,246.0 | $ | 118.7 | $ | 526.0 | $ | 519.5 | $ | 4,081.8 | ||||||||||
Finance lease obligations (3) | 7,225.7 | 401.7 | 799.2 | 785.0 | 5,239.8 | |||||||||||||||
Operating lease obligations (4) | 18.0 | 2.6 | 1.2 | 1.0 | 13.2 | |||||||||||||||
Energy and transportation purchase obligations (5) | 9,627.8 | 782.3 | 1,517.8 | 1,360.0 | 5,967.7 | |||||||||||||||
Purchase orders (6) | 378.8 | 161.9 | 114.7 | 49.6 | 52.6 | |||||||||||||||
Pension and OPEB funding obligations (7) | 11.0 | 3.8 | 7.2 | — | — | |||||||||||||||
Total contractual obligations | $ | 22,507.3 | $ | 1,471.0 | $ | 2,966.1 | $ | 2,715.1 | $ | 15,355.1 | ||||||||||
(1) | The amounts included in the table are calculated using current market prices, forward curves, and other estimates. |
(2) | Principal and interest payments on long-term debt (excluding finance lease obligations). |
(3) | Finance lease obligations for power purchase commitments and the leases with We Power. See Note 12, Leases, for more information. |
(4) | Operating lease obligations for land and rail car leases. See Note 12, Leases, for more information. |
(5) | Energy and transportation purchase obligations under various contracts for the procurement of fuel, power, gas supply, and associated transportation related to utility operations. |
(6) | Purchase obligations related to normal business operations, information technology, and other services. |
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(7) | Obligations for pension and OPEB plans cannot reasonably be estimated beyond 2022. |
The table above does not reflect estimated future payments related to the manufactured gas plant remediation liability of $12.1 million at December 31, 2019, as the amount and timing of payments are uncertain. We expect to incur costs annually to remediate these sites. See Note 19, Commitments and Contingencies, for more information about environmental liabilities.
AROs in the amount of $65.0 million are not included in the above table. Settlement of these liabilities cannot be determined with certainty, but we believe the majority of these liabilities will be settled in more than five years. See Note 7, Asset Retirement Obligations, for more information.
Obligations for utility operations have historically been included as part of the rate-making process and therefore are generally recoverable from customers.
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, impacts from the Tax Legislation, additional changes in tax laws and regulations, acquisition and development opportunities, market volatility, and economic trends. Our estimated capital expenditures for the next three years are as follows:
(in millions) | ||||
2020 | $ | 701.9 | ||
2021 | 1,189.5 | |||
2022 | 926.7 | |||
Total | $ | 2,818.1 | ||
The majority of spending consists of upgrading our electric and natural gas distribution systems to enhance reliability. These upgrades include the AMI program. AMI is an integrated system of smart meters, communication networks, and data management systems that enable two-way communication between utilities and customers.
Additionally, as part of our commitment to invest in zero-carbon generation, we, along with an unaffiliated utility filed an application with the PSCW for approval to acquire an ownership interest in a proposed utility-scale solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to our receipt and review of a final written order from the PSCW. Once constructed, we will own 100 MW of the output of this project. Our share of the cost of this project is estimated to be $130 million. Commercial operation of Badger Hollow II is targeted for the end of 2021. Solar generation technology has greatly improved, has become more cost-effective, and it complements our summer demand curve.
We plan to construct a LNG facility. Subject to PSCW approval, the facility would provide us with approximately one billion cubic feet 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. Commercial operation of the LNG facility is targeted for the end of 2023.
Common Stock Matters
For information related to our common stock matters, see Note 8, Common Equity.
Investments in Outside Trusts
We use outside trusts to fund our pension and certain OPEB obligations. These trusts had investments of approximately $1.3 billion as of December 31, 2019. These trusts hold investments that are subject to the volatility of the stock market and interest rates. We contributed $5.5 million and $6.3 million to our pension and OPEB plans in 2019 and 2018, respectively. Future contributions to the plans will be dependent upon many factors, including the performance of existing plan assets and long-term discount rates. For additional information, see Note 16, Employee Benefits.
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Off-Balance Sheet Arrangements
We are a party to various financial instruments with off-balance sheet risk as a part of our normal course of business, including letters of credit that primarily support our commodity contracts. We believe that these agreements do not have, and are not reasonably likely to have, a current or future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources. See Note 1(p), Guarantees, Note 10, Short-Term Debt and Lines of Credit, and Note 18, Variable Interest Entities, for more information.
FACTORS AFFECTING RESULTS, LIQUIDITY, AND CAPITAL RESOURCES
Market Risks and Other Significant Risks
We are exposed to market and other significant risks as a result of the nature of our businesses and the environments in which those businesses operate. These risks, described in further detail below, include but are not limited to:
Regulatory Recovery
We account for our regulated operations in accordance with accounting guidance under the Regulated Operations Topic of the FASB ASC. Our rates are determined by the PSCW. See Item 1. Business – D. Regulation for more information on our rates. See Note 21, Regulatory Environment, for additional information regarding recent rate proceedings and orders.
Regulated entities are allowed to defer certain costs that would otherwise be charged to expense if the regulated entity believes the recovery of those costs is probable. We record regulatory assets pursuant to specific orders or by a generic order issued by our regulators. Recovery of the deferred costs in future rates is subject to the review and approval by those regulators. We assume the risks and benefits of ultimate recovery of these items in future rates. If the recovery of the deferred costs is not approved by our regulators, the costs would be charged to income in the current period. In general, our regulatory assets are recovered over a period of between one to twenty years. Regulators can impose liabilities on a prospective basis for amounts previously collected from customers and for amounts that are expected to be refunded to customers. We record these items as regulatory liabilities. As of December 31, 2019, our regulatory assets were $2,755.2 million, and our regulatory liabilities were $1,756.2 million.
Due to the Tax Legislation, we remeasured our deferred taxes and recorded a tax benefit of $1,102 million. We have been returning this tax benefit to ratepayers through bill credits and reductions to other regulatory assets, which we expect to continue. See Note 13, Income Taxes, and Note 21, Regulatory Environment, for more information.
Commodity Costs
In the normal course of providing energy, we are subject to market fluctuations in the costs of coal, natural gas, purchased power, and fuel oil used in the delivery of coal. We manage our fuel and natural gas supply costs through a portfolio of short and long-term procurement contracts with various suppliers for the purchase of coal, natural gas, and fuel oil. In addition, we manage the risk of price volatility through natural gas and electric hedging programs.
Embedded within our rates are amounts to recover fuel, natural gas, and purchased power costs. We have recovery mechanisms in place that allow us to recover or refund all or a portion of the changes in prudently incurred fuel, natural gas, and purchased power costs from rate case-approved amounts. See Item 1. Business – D. Regulation for more information on these mechanisms.
Higher commodity costs can increase our working capital requirements, result in higher gross receipts taxes, and lead to increased energy efficiency investments by our customers to reduce utility usage and/or fuel substitution. Higher commodity costs combined with slower economic conditions also expose us to greater risks of accounts receivable write-offs as more customers are unable to pay their bills. See Note 1(d), Operating Revenues, for more information on our mechanism that allows for cost recovery or refund of uncollectible expense.
Weather
Our utility rates are based upon estimated normal temperatures. Our electric utility margins are unfavorably sensitive to below normal temperatures during the summer cooling season and, to some extent, to above normal temperatures during the winter heating season. Our natural gas utility margins are unfavorably sensitive to above normal temperatures during the winter heating
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season. A summary of actual weather information in our service territory during 2019 and 2018, as measured by degree days, may be found in Results of Operations.
Interest Rates
We are exposed to interest rate risk resulting from our short-term borrowings and projected near-term debt financing needs. We manage exposure to interest rate risk by limiting the amount of our variable rate obligations and continually monitoring the effects of market changes on interest rates. When it is advantageous to do so, we enter into long-term fixed rate debt.
Based on our variable rate debt outstanding at December 31, 2019, and December 31, 2018, a hypothetical increase in market interest rates of one percentage point would have increased annual interest expense by $1.2 million and $1.4 million in 2019 and 2018, respectively. This sensitivity analysis was performed assuming a constant level of variable rate debt during the period and an immediate increase in interest rates, with no other changes for the remainder of the period.
Marketable Securities Return
We use various trusts to fund our pension and OPEB obligations. These trusts invest in debt and equity securities. Changes in the market prices of these assets can affect future pension and OPEB expenses. Additionally, future contributions can also be affected by the investment returns on trust fund assets. We believe that the financial risks associated with investment returns would be partially mitigated through future rate actions by the PSCW.
The fair value of our trust fund assets and expected long-term returns were approximately:
(in millions) | As of December 31, 2019 | Expected Return on Assets in 2020 | |||||
Pension trust funds | $ | 1,094.6 | 6.75 | % | |||
OPEB trust funds | $ | 228.5 | 7.00 | % | |||
Fiduciary oversight of the pension and OPEB trust fund investments is the responsibility of an Investment Trust Policy Committee. The Committee works with external actuaries and investment consultants on an ongoing basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target asset allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. The targeted asset allocations are intended to reduce risk, provide long-term financial stability for the plans, and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Investment strategies utilize a wide diversification of asset types and qualified external investment managers.
WEC Energy Group consults with its investment advisors on an annual basis to help it forecast expected long-term returns on plan assets by reviewing actual historical returns and calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the funds.
Economic Conditions
Our service territories are within the state of Wisconsin. As such, we are exposed to market risks in the regional Midwest economy. In addition, any economic downturn or disruption of national or international markets could adversely affect the financial condition of our customers and demand for their products, which could affect their demand for our products.
Inflation
We continue to monitor the impact of inflation, especially with respect to the costs of medical plans, fuel, transmission access, construction costs, and regulatory and environmental compliance in order to minimize its effects in future years through pricing strategies, productivity improvements, and cost reductions. We do not believe the impact of general inflation will have a material impact on our future results of operations.
For additional information concerning risk factors, including market risks, see the Cautionary Statement Regarding Forward-Looking Information at the beginning of this report and Item 1A. Risk Factors.
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Competitive Markets
Electric Utility Industry
The FERC supports large RTOs, which directly impacts the structure of the wholesale electric market. Due to the FERC's support of RTOs, MISO uses the MISO Energy Markets to carry out its operations, including the use of LMP to value electric transmission congestion and losses. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, could have a significant and adverse financial impact on us.
Electric utility revenues in Wisconsin are regulated by the PSCW. The PSCW continues to maintain the position that the question of whether to implement electric retail competition in Wisconsin should ultimately be decided by the Wisconsin legislature. No such legislation has been introduced in Wisconsin to date, and it is uncertain when, if at all, retail choice might be implemented in Wisconsin.
Natural Gas Utility Industry
Due to the PSCW's previous proceedings on natural gas industry regulation in a competitive environment, the PSCW currently provides all Wisconsin customer classes with competitive markets the option to choose a third-party natural gas supplier. All of our Wisconsin customer classes have competitive market choices and, therefore, can purchase natural gas directly from either a third-party supplier or us. Since third-party suppliers can be used in Wisconsin, the PSCW has also adopted standards for transactions between a utility and its natural gas marketing affiliates.
We offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change. We offer natural gas transportation services to our customers that elect to purchase natural gas directly from a third-party supplier. Since these transportation customers continue to use our distribution systems to transport natural gas to their facilities, we earn distribution revenues from them. As such, the loss of revenue associated with the cost of natural gas that our transportation customers purchase from third-party suppliers has little impact on our net income, as it is offset by an equal reduction to natural gas costs. We are currently unable to predict the impact, if any, of potential future industry restructuring on our results of operations or financial position.
Environmental Matters
See Note 19, Commitments and Contingencies, for a discussion of certain environmental matters affecting us, including rules and regulations relating to air quality, water quality, land quality, and climate change.
Other Matters
Tax Cuts and Jobs Act of 2017
In December 2017, the Tax Legislation was signed into law. In May 2018, the PSCW issued a written order regarding how to refund certain tax savings from the Tax Legislation to our ratepayers in Wisconsin. The various remaining impacts of the Tax Legislation on our Wisconsin operations were addressed in our recent rate order issued by the PSCW in December 2019. See Note 21, Regulatory Environment, for more information on our rate orders. In addition, the MPSC approved a settlement in May 2018 with Tilden that addressed all base rate impacts of the Tax Legislation. Tilden owns the iron ore mine located in the Upper Peninsula of Michigan that we provided retail electric service to prior to April 1, 2019. We are also working with the FERC to modify our formula rate tariff for the impacts of the Tax Legislation, and we expect to receive FERC approval for the modified tariff in 2020.
Bonus Depreciation Provisions
Bonus depreciation is an additional amount of first-year tax deductible depreciation that is awarded above what would normally be available. The bonus depreciation deduction available for public utility property subject to rate-making by a government entity or public utility commission was modified by the Tax Legislation. Based on the provisions of the Tax Legislation, bonus depreciation can no longer be deducted for public utility property acquired and placed in service after December 31, 2017.
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Critical Accounting Policies and Estimates
Preparation of financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions. In addition, the financial and operating environment may also have a significant effect, not only on the operation of our business, but on our results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies applied have not changed.
The following is a list of accounting policies that are most significant to the portrayal of our financial condition and results of operations and that require management's most difficult, subjective or complex judgments:
Regulatory Accounting
Our utility operations follow the guidance under the Regulated Operations Topic of the FASB ASC (Topic 980). Our financial statements reflect the effects of the rate-making principles followed by the jurisdictions regulating us. Certain items that would otherwise be immediately recognized as revenues and expenses are deferred as regulatory assets and regulatory liabilities for future recovery or refund to customers, as authorized by our regulators.
Future recovery of regulatory assets is not assured and is generally subject to review by regulators in rate proceedings for matters such as prudence and reasonableness. Once approved, the regulatory assets and liabilities are amortized into earnings over the rate recovery or refund period. If recovery or refund of costs is not approved or is no longer considered probable, these regulatory assets or liabilities are recognized in current period earnings. Management regularly assesses whether these regulatory assets and liabilities are probable of future recovery or refund by considering factors such as changes in the regulatory environment, earnings from our electric and natural gas utility operations, and the status of any pending or potential deregulation legislation.
The application of the Regulated Operations Topic of the FASB ASC would be discontinued if all or a separable portion of our utility operations no longer met the criteria for application. Our regulatory assets and liabilities would be written off to income as an unusual or infrequently occurring item in the period in which discontinuation occurred. As of December 31, 2019, we had $2,755.2 million in regulatory assets and $1,756.2 million in regulatory liabilities. See Note 5, Regulatory Assets and Liabilities, for more information.
Long-Lived Assets
In accordance with ASC 980-360, Regulated Operations – Property, Plant, and Equipment, we periodically assess the recoverability of certain long-lived assets when events or changes in circumstances indicate that the carrying amount of those long-lived assets may not be recoverable. Examples of events or changes in circumstances include, but are not limited to, a significant decrease in the market price, a significant change in use, adverse legal factors or a change in business climate, operating or cash flow losses, or an expectation that the asset might be sold. These assessments require significant assumptions and judgments by management. Long-lived assets that would be subject to an impairment assessment would generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future.
In accordance with ASC 980-360, when it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. As a result, the remaining net book value of these assets can be significant. If a generating unit meets applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery or a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers.
Pleasant Prairie power plant was retired during 2018. PIPP was retired during 2019. Effective with our rate order issued by the PSCW in December 2019, we received approval to collect a return of and on the entire net book value of the PIPP and we received approval to collect a full return of and on all but $100 million of the net book value of the Pleasant Prairie power plant. In accordance with our
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PSCW rate order received in December 2019, we will seek a financing order from the PSCW to securitize the remaining $100 million. See Note 6, Property, Plant, and Equipment, and Note 21, Regulatory Environment, for more information on our retired generating units, including various approvals we received from the FERC and the PSCW.
Pension and Other Postretirement Employee Benefits
The costs of providing non-contributory defined pension benefits and OPEB, described in Note 16, Employee Benefits, are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience.
Pension and OPEB costs are impacted by actual employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans, and earnings on plan assets. Pension and OPEB costs may also be significantly affected by changes in key actuarial assumptions, including anticipated rates of return on plan assets, mortality and discount rates, and expected health care cost trends. Changes made to the plan provisions may also impact current and future pension and OPEB costs.
Pension and OPEB plan assets are primarily made up of equity and fixed income investments. Fluctuations in actual equity and fixed income market returns, as well as changes in general interest rates, may result in increased or decreased benefit costs in future periods. We believe that such changes in costs would be recovered or refunded through the rate-making process.
The following table shows how a given change in certain actuarial assumptions would impact the projected benefit obligation and the reported net periodic pension cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
Actuarial Assumption (in millions, except percentages) | Percentage-Point Change in Assumption | Impact on Projected Benefit Obligation | Impact on 2019 Pension Cost | |||||||
Discount rate | (0.5) | $ | 63.9 | $ | 3.5 | |||||
Discount rate | 0.5 | (54.8 | ) | (3.0 | ) | |||||
Rate of return on plan assets | (0.5) | N/A | 5.1 | |||||||
Rate of return on plan assets | 0.5 | N/A | (5.1 | ) | ||||||
The following table shows how a given change in certain actuarial assumptions would impact the accumulated OPEB obligation and the reported net periodic OPEB cost. Each factor below reflects an evaluation of the change based on a change in that assumption only.
Actuarial Assumption (in millions, except percentages) | Percentage-Point Change in Assumption | Impact on Postretirement Benefit Obligation | Impact on 2019 Postretirement Benefit Cost | |||||||
Discount rate | (0.5) | $ | 14.1 | $ | 2.1 | |||||
Discount rate | 0.5 | (12.2 | ) | (2.1 | ) | |||||
Health care cost trend rate | (0.5) | (6.1 | ) | (2.0 | ) | |||||
Health care cost trend rate | 0.5 | 7.1 | 2.3 | |||||||
Rate of return on plan assets | (0.5) | N/A | 1.0 | |||||||
Rate of return on plan assets | 0.5 | N/A | (1.0 | ) | ||||||
The discount rates are selected based on hypothetical bond portfolios consisting of noncallable, high-quality corporate bonds across the full maturity spectrum. From the hypothetical bond portfolios, a single rate is determined that equates the market value of the bonds purchased to the discounted value of the plans' expected future benefit payments.
We establish our expected return on assets based on consideration of historical and projected asset class returns, as well as the target allocations of the benefit trust portfolios. The assumed long-term rate of return on pension plan assets was 7.00% in 2019, 2018, and 2017. The actual rate of return on pension plan assets, net of fees, was 15.83%, (2.91)%, and 11.48%, in 2019, 2018, and 2017, respectively.
In selecting assumed health care cost trend rates, past performance and forecasts of health care costs are considered. For more information on health care cost trend rates and a table showing future payments that we expect to make for our pension and OPEB, see Note 16, Employee Benefits.
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Unbilled Revenues
We record utility operating revenues when energy is delivered to our customers. However, the determination of energy sales to individual customers is based upon the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and corresponding unbilled revenues are calculated. This unbilled revenue is estimated each month based upon actual generation and throughput volumes, recorded sales, estimated customer usage by class, weather factors, estimated line losses, and applicable customer rates. Significant fluctuations in energy demand for the unbilled period or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. Total utility operating revenues during 2019 of approximately $3.5 billion included accrued utility revenues of $205.6 million as of December 31, 2019.
Income Tax Expense
We are required to estimate income taxes for each of the jurisdictions in which we operate as part of the process of preparing consolidated financial statements. This process involves estimating current income tax liabilities together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for income tax and accounting purposes. These differences result in deferred income tax assets and liabilities, which are included within our balance sheets. We also assess the likelihood that our deferred income tax assets will be recovered through future taxable income. To the extent we believe that realization is not likely, we establish a valuation allowance, which is offset by an adjustment to income tax expense in our income statements.
Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals requires that judgments and estimates be made in the accrual process and in the calculation of effective tax rates. Only income tax benefits that meet the "more likely than not" recognition threshold may be recognized or continue to be recognized. Unrecognized tax benefits are re-evaluated quarterly and changes are recorded based on new information, including the issuance of relevant guidance by the courts or tax authorities and developments occurring in the examinations of our tax returns.
Significant management judgment is required in determining our provision for income taxes, deferred income tax assets and liabilities, the liability for unrecognized tax benefits, and any valuation allowance recorded against deferred income tax assets. The assumptions involved are supported by historical data, reasonable projections, and interpretations of applicable tax laws and regulations across multiple taxing jurisdictions. Significant changes in these assumptions could have a material impact on our financial condition and results of operations. See Note 1(m), Income Taxes, and Note 13, Income Taxes, for a discussion of accounting for income taxes.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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, as well as Note 1(n), Fair Value Measurements, Note 1(o), Derivative Instruments, and Note 1(p), Guarantees, for information concerning potential market risks to which we are exposed.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholder and the Board of Directors of Wisconsin Electric Power Company
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Wisconsin Electric Power Company and subsidiary (the "Company") as of December 31, 2019 and 2018, the related consolidated statements of income, equity, and cash flows, for each of the three years in the period ended December 31, 2019, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/DELOITTE & TOUCHE LLP
Milwaukee, Wisconsin
February 27, 2020
We have served as the Company's auditor since 2002.
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B. CONSOLIDATED INCOME STATEMENTS
Year Ended December 31 | ||||||||||||
(in millions) | 2019 | 2018 | 2017 | |||||||||
Operating revenues | $ | 3,496.7 | $ | 3,625.0 | $ | 3,711.7 | ||||||
Operating expenses | ||||||||||||
Cost of sales | 1,190.7 | 1,262.1 | 1,286.4 | |||||||||
Other operation and maintenance | 1,053.1 | 1,502.4 | 1,352.0 | |||||||||
Depreciation and amortization | 384.4 | 348.1 | 331.6 | |||||||||
Property and revenue taxes | 108.3 | 109.9 | 109.6 | |||||||||
Total operating expenses | 2,736.5 | 3,222.5 | 3,079.6 | |||||||||
Operating income | 760.2 | 402.5 | 632.1 | |||||||||
Other income, net | 22.7 | 20.2 | 13.2 | |||||||||
Interest expense | 477.4 | 120.1 | 117.3 | |||||||||
Other expense | (454.7 | ) | (99.9 | ) | (104.1 | ) | ||||||
Income before income taxes | 305.5 | 302.6 | 528.0 | |||||||||
Income tax expense (benefit) | (57.8 | ) | (56.9 | ) | 191.2 | |||||||
Net income | 363.3 | 359.5 | 336.8 | |||||||||
Preferred stock dividend requirements | 1.2 | 1.2 | 1.2 | |||||||||
Net income attributed to common shareholder | $ | 362.1 | $ | 358.3 | $ | 335.6 | ||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2019 Form 10-K | 46 | Wisconsin Electric Power Company |
C. CONSOLIDATED BALANCE SHEETS
At December 31 | ||||||||
(in millions, except share and per share amounts) | 2019 | 2018 | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | 19.1 | $ | 20.2 | ||||
Accounts receivable and unbilled revenues, net of reserves of $38.1 and $40.9, respectively | 434.6 | 472.3 | ||||||
Accounts receivable from related parties | 86.5 | 112.4 | ||||||
Materials, supplies, and inventories | 229.8 | 241.4 | ||||||
Prepaid taxes | 104.4 | 138.4 | ||||||
Other | 33.6 | 31.6 | ||||||
Current assets | 908.0 | 1,016.3 | ||||||
Long-term assets | ||||||||
Property, plant, and equipment, net of accumulated depreciation and amortization of $4,564.0 and $4,505.5, respectively | 9,586.7 | 9,528.9 | ||||||
Regulatory assets | 2,755.2 | 2,902.2 | ||||||
Other | 110.9 | 90.9 | ||||||
Long-term assets | 12,452.8 | 12,522.0 | ||||||
Total assets | $ | 13,360.8 | $ | 13,538.3 | ||||
Liabilities and Equity | ||||||||
Current liabilities | ||||||||
Short-term debt | $ | 115.5 | $ | 134.9 | ||||
Current portion of long-term debt | — | 250.0 | ||||||
Current portion of finance and capital lease obligations | 57.8 | 49.9 | ||||||
Accounts payable | 267.6 | 248.9 | ||||||
Accounts payable to related parties | 184.5 | 226.0 | ||||||
Accrued payroll and benefits | 51.3 | 50.4 | ||||||
Accrued taxes | 12.3 | 13.6 | ||||||
Other | 105.6 | 103.2 | ||||||
Current liabilities | 794.6 | 1,076.9 | ||||||
Long-term liabilities | ||||||||
Long-term debt | 2,759.2 | 2,459.6 | ||||||
Finance and capital lease obligations | 2,783.1 | 2,807.2 | ||||||
Deferred income taxes | 1,347.4 | 1,298.3 | ||||||
Regulatory liabilities | 1,744.2 | 2,002.3 | ||||||
Pension and OPEB obligations | 59.8 | 118.5 | ||||||
Other | 281.0 | 284.3 | ||||||
Long-term liabilities | 8,974.7 | 8,970.2 | ||||||
Commitments and contingencies (Note 19) | ||||||||
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 | 929.5 | 831.3 | ||||||
Retained earnings | 2,298.7 | 2,296.6 | ||||||
Common shareholder's equity | 3,561.1 | 3,460.8 | ||||||
Preferred stock | 30.4 | 30.4 | ||||||
Total liabilities and equity | $ | 13,360.8 | $ | 13,538.3 | ||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2019 Form 10-K | 47 | Wisconsin Electric Power Company |
D. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31 | ||||||||||||
(in millions) | 2019 | 2018 | 2017 | |||||||||
Operating activities | ||||||||||||
Net income | $ | 363.3 | $ | 359.5 | $ | 336.8 | ||||||
Reconciliation to cash provided by operating activities | ||||||||||||
Depreciation and amortization | 384.4 | 348.1 | 331.6 | |||||||||
Deferred income taxes and investment tax credits, net | (131.2 | ) | (0.7 | ) | 109.7 | |||||||
Contributions and payments related to pension and OPEB plans | (5.5 | ) | (6.3 | ) | (8.3 | ) | ||||||
Payments for liabilities transferred to affiliates | (4.5 | ) | (10.1 | ) | (0.3 | ) | ||||||
Change in – | ||||||||||||
Accounts receivable and unbilled revenues | 60.3 | 34.8 | (64.9 | ) | ||||||||
Materials, supplies, and inventories | 11.6 | 9.3 | 20.3 | |||||||||
Prepaid taxes | 34.0 | (28.3 | ) | 0.5 | ||||||||
Other current assets | (5.2 | ) | 13.5 | (11.8 | ) | |||||||
Accounts payable | (22.4 | ) | 13.2 | 45.8 | ||||||||
Accrued taxes | (1.3 | ) | (41.1 | ) | 12.8 | |||||||
Other current liabilities | (1.1 | ) | (5.2 | ) | 12.2 | |||||||
Other, net | 172.0 | 275.5 | (86.4 | ) | ||||||||
Net cash provided by operating activities | 854.4 | 962.2 | 698.0 | |||||||||
Investing activities | ||||||||||||
Capital expenditures | (590.6 | ) | (603.2 | ) | (596.1 | ) | ||||||
Proceeds from the sale of assets | 2.0 | 1.7 | 22.9 | |||||||||
Proceeds from assets transferred to affiliates | 0.1 | 8.8 | — | |||||||||
Payments for assets transferred from affiliates | — | (59.8 | ) | — | ||||||||
Other, net | 11.6 | 12.1 | 5.0 | |||||||||
Net cash used in investing activities | (576.9 | ) | (640.4 | ) | (568.2 | ) | ||||||
Financing activities | ||||||||||||
Change in short-term debt | (19.4 | ) | (76.0 | ) | 51.9 | |||||||
Repayment of subsidiary note to parent | — | — | (18.5 | ) | ||||||||
Issuance of long-term debt | 300.0 | 300.0 | — | |||||||||
Retirement of long-term debt | (250.0 | ) | (250.0 | ) | — | |||||||
Payments for finance lease obligations | (50.5 | ) | — | — | ||||||||
Equity contribution from parent | 105.0 | 28.0 | 75.0 | |||||||||
Payment of dividends to parent | (360.0 | ) | (310.0 | ) | (240.0 | ) | ||||||
Other, net | (3.7 | ) | (5.9 | ) | (1.3 | ) | ||||||
Net cash used in financing activities | (278.6 | ) | (313.9 | ) | (132.9 | ) | ||||||
Net change in cash and cash equivalents | (1.1 | ) | 7.9 | (3.1 | ) | |||||||
Cash and cash equivalents at beginning of year | 20.2 | 12.3 | 15.4 | |||||||||
Cash and cash equivalents at end of year | $ | 19.1 | $ | 20.2 | $ | 12.3 | ||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2019 Form 10-K | 48 | Wisconsin Electric Power Company |
E. CONSOLIDATED STATEMENTS OF EQUITY
Wisconsin Electric Power Company Common Shareholder's Equity | ||||||||||||||||||||||||
Common Stock | Additional Paid-In Capital | Retained Earnings | Total Common Shareholder's Equity | Preferred Stock | Total Equity | |||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Balance at December 31, 2016 | $ | 332.9 | $ | 1,020.1 | $ | 2,140.8 | $ | 3,493.8 | $ | 30.4 | $ | 3,524.2 | ||||||||||||
Net income attributed to common shareholder | — | — | 335.6 | 335.6 | — | 335.6 | ||||||||||||||||||
Payment of dividends to parent | — | — | (240.0 | ) | (240.0 | ) | — | (240.0 | ) | |||||||||||||||
Cumulative effect adjustment from adoption of ASU 2016-09 | — | — | 11.9 | 11.9 | — | 11.9 | ||||||||||||||||||
Equity contribution from parent | — | 75.0 | — | 75.0 | — | 75.0 | ||||||||||||||||||
Transfer of net assets to UMERC | — | (61.1 | ) | — | (61.1 | ) | — | (61.1 | ) | |||||||||||||||
Transfer of ATC ownership interest and related taxes | — | (228.6 | ) | — | (228.6 | ) | — | (228.6 | ) | |||||||||||||||
Settlement of a short-term note receivable between Bostco and our parent company | — | (4.8 | ) | — | (4.8 | ) | — | (4.8 | ) | |||||||||||||||
Stock-based compensation and other | — | 2.1 | — | 2.1 | — | 2.1 | ||||||||||||||||||
Balance at December 31, 2017 | $ | 332.9 | $ | 802.7 | $ | 2,248.3 | $ | 3,383.9 | $ | 30.4 | $ | 3,414.3 | ||||||||||||
Net income attributed to common shareholder | — | — | 358.3 | 358.3 | — | 358.3 | ||||||||||||||||||
Payment of dividends to parent | — | — | (310.0 | ) | (310.0 | ) | — | (310.0 | ) | |||||||||||||||
Equity contribution from parent | — | 28.0 | — | 28.0 | — | 28.0 | ||||||||||||||||||
Stock-based compensation and other | — | 0.6 | — | 0.6 | — | 0.6 | ||||||||||||||||||
Balance at December 31, 2018 | $ | 332.9 | $ | 831.3 | $ | 2,296.6 | $ | 3,460.8 | $ | 30.4 | $ | 3,491.2 | ||||||||||||
Net income attributed to common shareholder | — | — | 362.1 | 362.1 | — | 362.1 | ||||||||||||||||||
Payment of dividends to parent | — | — | (360.0 | ) | (360.0 | ) | — | (360.0 | ) | |||||||||||||||
Equity contribution from parent | — | 105.0 | — | 105.0 | — | 105.0 | ||||||||||||||||||
Transfer of net assets to UMERC | — | (7.3 | ) | — | (7.3 | ) | — | (7.3 | ) | |||||||||||||||
Stock-based compensation and other | — | 0.5 | — | 0.5 | — | 0.5 | ||||||||||||||||||
Balance at December 31, 2019 | $ | 332.9 | $ | 929.5 | $ | 2,298.7 | $ | 3,561.1 | $ | 30.4 | $ | 3,591.5 | ||||||||||||
The accompanying Notes to Consolidated Financial Statements are an integral part of these financial statements.
2019 Form 10-K | 49 | Wisconsin Electric Power Company |
F. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Nature of Operations—We are an electric, natural gas, and steam utility company that serves electric and natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. Prior to April 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 after UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. WEC Energy Group owns all of our outstanding common stock.
As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted.
Through October 2018, we had one wholly owned subsidiary, Bostco. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. See Note 2, Disposition, for more information. The financial statements include our accounts and the accounts of our former wholly owned subsidiary. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method.
(b) Basis of Presentation—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.
(d) Operating Revenues—The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues.
Revenues from Contracts with Customers
Electric Utility Operating Revenues
Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity.
The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. In addition, 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.
Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of
2019 Form 10-K | 50 | Wisconsin Electric Power Company |
electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.
The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.
We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.
For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.
Natural Gas Utility Operating Revenues
We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.
The transaction price of the performance obligations for our natural gas customers is valued using rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.
Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. In addition, 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.
Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.
2019 Form 10-K | 51 | Wisconsin Electric Power Company |
Other Operating Revenues
Alternative Revenues
Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.
Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.
(e) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:
(in millions) | 2019 | 2018 | ||||||
Materials and supplies | $ | 148.3 | $ | 146.1 | ||||
Fossil fuel | 51.1 | 58.7 | ||||||
Natural gas in storage | 30.4 | 36.6 | ||||||
Total | $ | 229.8 | $ | 241.4 | ||||
Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting.
(f) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the rate-making process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.
The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 5, Regulatory Assets and Liabilities, for more information.
(g) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.
We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW that include estimates for salvage value and removal costs. Annual utility composite depreciation rates were 3.11%, 3.18%, and 2.95% in 2019, 2018, and 2017, respectively.
We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.
For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment.
Third parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.
2019 Form 10-K | 52 | Wisconsin Electric Power Company |
See Note 6, Property, Plant, and Equipment, for more information.
(h) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net.
Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2019, 2018, and 2017. Our average AFUDC wholesale rates were 5.11%, 3.63%, and 5.94% for 2019, 2018, and 2017, respectively.
We recorded the following AFUDC for the years ended December 31:
(in millions) | 2019 | 2018 | 2017 | |||||||||
AFUDC – Debt | $ | 1.5 | $ | 1.5 | $ | 1.2 | ||||||
AFUDC – Equity | 3.7 | 3.9 | 3.1 | |||||||||
(i) Asset Impairment—We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. Long-lived assets that would be subject to an impairment assessment would generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.
When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers. See Note 6, Property, Plant, and Equipment, for more information.
(j) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 7, Asset Retirement Obligations, for more information.
(k) Stock-Based Compensation—Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million.
2019 Form 10-K | 53 | Wisconsin Electric Power Company |
Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period.
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modified 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 increase retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. As allowed under this ASU, we have elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.
Stock Options
Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant.
WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models:
2019 | 2018 | 2017 | ||||||||||
Stock options granted | 59,404 | 81,730 | 80,770 | |||||||||
Estimated weighted-average fair value per stock option | $ | 8.60 | $ | 7.26 | $ | 7.12 | ||||||
Assumptions used to value the options: | ||||||||||||
Risk-free interest rate | 2.5% – 2.7% | 1.6% – 2.5% | 0.7% – 2.5% | |||||||||
Dividend yield | 3.6 | % | 3.5 | % | 3.5 | % | ||||||
Expected volatility | 17.0 | % | 18.0 | % | 19.0 | % | ||||||
Expected life (years) | 8.5 | 5.1 | 6.2 | |||||||||
The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience.
Restricted Shares
WEC Energy Group restricted shares granted to our employees have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards.
Performance Units
Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics as may be determined by the Compensation Committee. Participants may earn between 0% and 175% of the performance unit award based on WEC Energy Group's total shareholder return. Pursuant to the terms of the plan, these percentages can be adjusted upwards or downwards based on WEC Energy Group's performance against additional performance measures, if any, adopted by the Compensation Committee. Performance units also accrue forfeitable dividend equivalents in the form of additional performance units.
2019 Form 10-K | 54 | Wisconsin Electric Power Company |
All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years.
See Note 8, Common Equity, for more information on WEC Energy Group's stock-based compensation plans.
(l) Leases—In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded.
As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance.
• | We did not reassess whether any expired or existing contracts were leases or contained leases. |
• | We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases). |
• | We did not reassess the accounting for initial direct costs for any existing leases. |
We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with ASC 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract.
We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842.
In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842.
In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842.
Right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were each $13.0 million. Regarding our finance leases, while the adoption of Topic 842 changed the classification of expense related to these leases on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the finance lease assets and related liability amounts recorded on our balance sheets.
Significant Judgments and Other Information
We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind farms. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.
2019 Form 10-K | 55 | Wisconsin Electric Power Company |
As of February 27, 2020, we have not entered into any material leases that have not yet commenced.
See Note 12, Leases, for more information.
(m) Income Taxes—We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.
Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 13, Income Taxes, for more information.
We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements.
(n) 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.
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-developed inputs.
See Note 14, Fair Value Measurements, for more information.
(o) 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.
2019 Form 10-K | 56 | Wisconsin Electric Power Company |
We record derivative instruments on our balance sheets as assets or liabilities 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.
We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.
Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 15, Derivative Instruments, for more information.
(p) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. As of December 31, 2019, 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.
(q) Employee Benefits—The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 16, Employee Benefits, for more information.
(r) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.
Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.
(s) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 7, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 19, Commitments and Contingencies, for more information regarding manufactured gas plant sites.
We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.
We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the PSCW's approval.
We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.
2019 Form 10-K | 57 | Wisconsin Electric Power Company |
(t) Customer Concentrations of Credit Risk—We provide regulated electric, natural gas, and steam service to customers in Wisconsin. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. As a result, we did not have any significant concentrations of credit risk at December 31, 2019. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2019.
NOTE 2—DISPOSITION
Other Segment – Sale of Bostco LLC Real Estate Holdings
In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space, and in October 2018, Bostco was dissolved. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
NOTE 3—RELATED PARTIES
We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities.
We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group pursuant to an AIA that became effective January 1, 2017. The AIA was approved by the appropriate regulators, including the PSCW. During 2017, all of the applicable state commissions approved modifications to the AIA to incorporate WEC Energy Group's acquisition of Bluewater. See below for more information on the acquisition. In accordance with the AIA, WBS provides several categories of services to us (including financial, human resource, and administrative services).
In March 2017, we sold the remaining real estate holdings of Bostco. Wispark, a subsidiary of WEC Energy Group, provided $7.0 million of financing to the buyer and established a corresponding note receivable. The financing resulted in Bostco having a $7.0 million related party receivable from Wispark, which was paid in April 2017. See Note 2, Disposition, for more information on the real estate sale.
Prior to January 1, 2017, we held a 23% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. On January 1, 2017, we transferred our $402.0 million investment in ATC, and the $13.4 million related receivable for distributions approved and recorded in December 2016, to another subsidiary of WEC Energy Group. In addition, during 2017 we transferred $186.8 million of related deferred income tax liabilities to another subsidiary of WEC Energy Group. 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.
Our balance sheets included the following receivables and payables related to transactions entered into with ATC:
(in millions) | 2019 | 2018 | ||||||
Accounts receivable | ||||||||
Services provided to ATC | $ | 1.7 | $ | 2.2 | ||||
Accounts payable | ||||||||
Services received from ATC | 19.9 | 19.4 | ||||||
2019 Form 10-K | 58 | Wisconsin Electric Power Company |
The following table shows activity associated with our related party transactions for the years ended December 31:
(in millions) | 2019 | 2018 | 2017 | |||||||||
Lease agreements | ||||||||||||
Lease payments to We Power (1) | $ | 393.2 | $ | 373.7 | $ | 420.5 | ||||||
CWIP billed to We Power | 35.1 | 39.5 | 57.3 | |||||||||
Transactions with WBS | ||||||||||||
Billings to WBS (2) | 102.6 | 61.5 | 255.7 | |||||||||
Billings from WBS (2) | 205.3 | 243.4 | (6) | 215.4 | ||||||||
Transactions with WPS | ||||||||||||
Natural gas related purchases from WPS (3) | 2.0 | 1.9 | 1.6 | |||||||||
Billings to WPS (2) | 13.2 | 17.8 | 28.2 | |||||||||
Billings from WPS (2) | 9.3 | 10.9 | 4.5 | |||||||||
Transactions with WG | ||||||||||||
Natural gas related purchases from WG (3) | 5.4 | 5.3 | 5.3 | |||||||||
Billings to WG (2) | 41.1 | 59.0 | (7) | 64.0 | ||||||||
Billings from WG (2) | 30.1 | 32.6 | 23.1 | |||||||||
Transactions with UMERC | ||||||||||||
Electric sales to UMERC (4) | 7.9 | 29.6 | 30.8 | |||||||||
Billings to UMERC (2) | 10.5 | 15.8 | 125.5 | |||||||||
Transactions with Bluewater (5) | ||||||||||||
Storage service fees | 14.2 | 15.0 | 2.7 | |||||||||
Natural gas related sales to Bluewater (3) | 2.3 | — | — | |||||||||
Transactions with ATC | ||||||||||||
Charges to ATC for services and construction | 14.9 | 13.9 | 10.9 | |||||||||
Charges from ATC for network transmission services | 230.6 | 232.0 | 241.4 | |||||||||
Refund from ATC related to a FERC audit | — | 15.4 | — | |||||||||
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. Lease payments were reduced in 2018 as a result of tax savings related to the Tax Legislation. |
(2) | Includes amounts billed for services, pass through costs, asset and liability transfers, and other items in accordance with the approved AIAs. As required by FERC regulations for centralized service companies, WBS renders services at cost. In addition, all services provided by any regulated subsidiary to another regulated subsidiary or WBS are priced at cost. |
(3) | Includes amounts related to the purchase or sale of natural gas and/or pipeline capacity. |
(4) | On March 31, 2019, UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan began commercial operation. Prior to its generating units achieving commercial operation, UMERC purchased a portion of its power from us. See below for more information on UMERC. |
(5) | WEC Energy Group's acquisition of Bluewater was completed on June 30, 2017. See below for more information. |
(6) | Includes $10.0 million for the transfer of certain benefit-related liabilities to WBS and $59.8 million for the transfer of certain software assets from WBS. |
(7) | Includes $5.3 million for the transfer of certain software assets to WG. |
Parent Company's Acquisition of Natural Gas Storage Facilities in Michigan
In June 2017, our parent company completed its acquisition of Bluewater for $226.0 million. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we entered into a long-term service agreement with a wholly owned subsidiary of Bluewater to take a portion of the storage, which was then approved by the PSCW in November 2017. See Note 21, Regulatory Environment, for more information.
2019 Form 10-K | 59 | Wisconsin Electric Power Company |
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 the related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of the net assets, including the related deferred income tax liabilities, transferred to UMERC from us in 2017, was $61.1 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.
On March 31, 2019, UMERC began generating electricity when its new 187 MW natural gas-fired generation achieved commercial operation. Prior to its generating units achieving commercial operation, UMERC met its market obligations through power purchase agreements with us and WPS.
We retired the PIPP generating units on March 31, 2019. As a result, the net book value of the PIPP was reclassified as a regulatory asset on our balance sheet. In the second quarter of 2019, $12.5 million of the regulatory asset, along with the related deferred taxes and a portion of the cost of removal reserve, was transferred to UMERC for recovery from its retail customers. See Note 6, Property, Plant, and Equipment, for more information on the retirement of the PIPP.
NOTE 4—OPERATING REVENUES
For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues.
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. For our utility segment, 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 are impacted by regulatory activities within their jurisdictions.
Comparable amounts have not been presented for the year ended December 31, 2017, due to our adoption of ASU 2014-09, Revenues from Contracts with Customers, under the modified retrospective method.
Wisconsin Electric Power Company Consolidated | ||||||||
Year Ended December 31 | ||||||||
(in millions) | 2019 | 2018 | ||||||
Electric utility | $ | 3,088.3 | $ | 3,212.7 | ||||
Natural gas utility | 399.0 | 405.1 | ||||||
Total revenues from contracts with customers | 3,487.3 | 3,617.8 | ||||||
Other operating revenues | 9.4 | 7.2 | ||||||
Total operating revenues | $ | 3,496.7 | $ | 3,625.0 | ||||
2019 Form 10-K | 60 | Wisconsin Electric Power Company |
Revenues from Contracts with Customers
Electric Utility Operating Revenues
The following table disaggregates electric utility operating revenues into customer class:
Electric Utility Operating Revenues | ||||||||
Year Ended December 31 | ||||||||
(in millions) | 2019 | 2018 | ||||||
Residential | $ | 1,206.7 | $ | 1,220.8 | ||||
Small commercial and industrial | 1,010.9 | 1,020.0 | ||||||
Large commercial and industrial | 583.9 | 656.6 | ||||||
Other | 20.6 | 20.7 | ||||||
Total retail revenues | 2,822.1 | 2,918.1 | ||||||
Wholesale | 93.8 | 108.5 | ||||||
Resale | 132.7 | 153.7 | ||||||
Steam | 23.3 | 24.1 | ||||||
Other utility revenues | 16.4 | 8.3 | ||||||
Total electric utility operating revenues | $ | 3,088.3 | $ | 3,212.7 | ||||
Natural Gas Utility Operating Revenues
The following table disaggregates natural gas utility operating revenues into customer class:
Natural Gas Utility Operating Revenues | ||||||||
Year Ended December 31 | ||||||||
(in millions) | 2019 | 2018 | ||||||
Residential | $ | 261.7 | $ | 264.3 | ||||
Commercial and industrial | 121.2 | 126.3 | ||||||
Total retail revenues | 382.9 | 390.6 | ||||||
Transport | 13.6 | 13.4 | ||||||
Other utility revenues | 2.5 | 1.1 | ||||||
Total natural gas utility operating revenues | $ | 399.0 | $ | 405.1 | ||||
Other Operating Revenues
Other operating revenues consist primarily of the following:
Year Ended December 31 | ||||||||
(in millions) | 2019 | 2018 | ||||||
Late payment charges | $ | 8.2 | $ | 8.2 | ||||
Leases | 2.9 | 2.9 | ||||||
Alternative revenues * | (1.7 | ) | (3.9 | ) | ||||
Total other operating revenues | $ | 9.4 | $ | 7.2 | ||||
* | 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 customers subject to wholesale true-ups, as discussed in Note 1(d), Operating Revenues. |
2019 Form 10-K | 61 | Wisconsin Electric Power Company |
NOTE 5—REGULATORY ASSETS AND LIABILITIES
The following regulatory assets were reflected on our balance sheets as of December 31:
(in millions) | 2019 | 2018 | See Note | |||||||
Regulatory assets (1) (2) | ||||||||||
Finance and capital leases | $ | 930.5 | $ | 869.3 | 12 | |||||
Plant retirements (3) | 788.8 | 754.1 | 6 | |||||||
Pension and OPEB costs (4) | 459.4 | 490.6 | 16 | |||||||
Income tax related items (5) | 403.2 | 317.9 | 13 | |||||||
SSR (6) | 151.5 | 316.7 | 21 | |||||||
Electric transmission costs | — | 57.8 | 21 | |||||||
Other, net | 21.8 | 95.9 | ||||||||
Total regulatory assets | $ | 2,755.2 | $ | 2,902.3 | ||||||
Balance sheet presentation | ||||||||||
Other current assets | $ | — | $ | 0.1 | ||||||
Regulatory assets | 2,755.2 | 2,902.2 | ||||||||
Total regulatory assets | $ | 2,755.2 | $ | 2,902.3 | ||||||
(1) | Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. |
(2) | As of December 31, 2019, we had $10.0 million of regulatory assets not earning a return, $28.6 million of regulatory assets earning a return based on short-term interest rates, and $151.5 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. The other regulatory assets in the table either earn a return at our weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. |
(3) | In accordance with our rate order issued by the PSCW in December 2019, amounts previously collected from customers for the future removal of our recently retired plants were used to reduce our unrecovered plant balances during December 2019. Any additional removal costs that we incur will increase our plant retirement regulatory assets. |
(4) | Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan. |
(5) | For information on the flow through of tax repairs and the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment. |
(6) | As a result of the rate order we received from the PSCW in December 2019, the regulatory liability related to our mines deferral was offset against our SSR regulatory asset during December 2019. The rate order also authorized recovery of our SSR regulatory asset over a 15-year period that began on January 1, 2020. |
2019 Form 10-K | 62 | Wisconsin Electric Power Company |
The following regulatory liabilities were reflected on our balance sheets as of December 31:
(in millions) | 2019 | 2018 | See Note | |||||||
Regulatory liabilities | ||||||||||
Income tax related items (1) | $ | 888.1 | $ | 1,024.8 | 13 | |||||
Removal costs (2) | 654.7 | 748.1 | ||||||||
Pension and OPEB benefits (3) | 120.4 | 74.7 | 16 | |||||||
Electric transmission costs (4) | 38.6 | — | 21 | |||||||
Uncollectible expense (5) | 28.8 | 16.4 | 1(d) | |||||||
Energy efficiency programs (6) | 15.8 | 13.5 | ||||||||
Mines deferral (7) | — | 120.8 | ||||||||
Other, net | 9.8 | 15.9 | ||||||||
Total regulatory liabilities | $ | 1,756.2 | $ | 2,014.2 | ||||||
Balance sheet presentation | ||||||||||
Other current liabilities | $ | 12.0 | $ | 11.9 | ||||||
Regulatory liabilities | 1,744.2 | 2,002.3 | ||||||||
Total regulatory liabilities | $ | 1,756.2 | $ | 2,014.2 | ||||||
(1) | For information on the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment. |
(2) | Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 7, Asset Retirement Obligations, for more information on our legal obligations. |
(3) | Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. |
(4) | Based on orders received from the PSCW, we were required to apply the refunds due to customers from our earnings sharing mechanism to our electric transmission escrow through 2019. As a result, $38.6 million of our earnings sharing refunds were reflected in our electric transmission regulatory liability at December 31, 2019, and $37.2 million of our earnings sharing refunds were netted against our electric transmission regulatory asset at December 31, 2018. |
(5) | Represents amounts refundable to customers related to our uncollectible expense tracking mechanism. This mechanism allows us to recover or refund the difference between actual uncollectible write-offs and the amounts recovered in rates. |
(6) | Represents amounts refundable to customers related to programs designed to meet energy efficiency standards. |
(7) | Represents the deferral of revenues less the associated cost of sales related to Tilden, which were not included in the PSCW's 2015 rate order. As a result of the rate order we received from the PSCW in December 2019, this regulatory liability was offset against our SSR regulatory asset during December 2019. |
2019 Form 10-K | 63 | Wisconsin Electric Power Company |
NOTE 6—PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following at December 31:
(in millions) | 2019 | 2018 | ||||||
Electric – generation | $ | 3,623.4 | $ | 3,560.0 | ||||
Electric – distribution | 5,086.4 | 4,837.9 | ||||||
Natural gas – distribution, storage, and transmission | 1,358.0 | 1,269.6 | ||||||
Property, plant, and equipment to be retired | — | 174.8 | ||||||
Other | 803.2 | 801.8 | ||||||
Less: Accumulated depreciation | 3,397.0 | 3,239.4 | ||||||
Net | 7,474.0 | 7,404.7 | ||||||
CWIP | 190.8 | 124.7 | ||||||
Net utility property, plant, and equipment | 7,664.8 | 7,529.4 | ||||||
Property under finance/capital leases | 3,077.4 | 3,043.5 | ||||||
Less: Accumulated amortization | 1,167.0 | 1,055.6 | ||||||
Net leased facilities | 1,910.4 | 1,987.9 | ||||||
Non-utility and other property, plant, and equipment | 11.5 | 11.6 | ||||||
Total property, plant, and equipment | $ | 9,586.7 | $ | 9,528.9 | ||||
Pleasant Prairie Power Plant
The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $615.1 million at December 31, 2019, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $20.6 million. The net amount of $594.5 million was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $172.1 million related to the retired Pleasant Prairie power plant. Effective with our rate order issued by the PSCW in December 2019, we will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. We have FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. Collection of the return of and on the net book value is no longer subject to refund as the FERC completed its prudency review and concluded that the retirement of this plant was prudent. We received approval from the PSCW in December 2019 to collect a full return of and on all but $100 million of the net book value of the Pleasant Prairie power plant. In accordance with our PSCW rate order received in December 2019, we will seek a financing order from the PSCW to securitize the remaining $100 million. See Note 21, Regulatory Environment, for more information.
Presque Isle Power Plant
Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The net book value of the PIPP was $162.7 million at December 31, 2019, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $6.4 million. The net amount of $156.3 million was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $46.5 million related to the retired PIPP. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. Effective with our rate order issued by the PSCW in December 2019, we received approval to collect a return of and on our share of the net book value of the PIPP, and as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. Amortization is included in depreciation and amortization in the income statement. We have FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the net book value. However, this approval is subject to refund pending the outcome of settlement proceedings. See Note 21, Regulatory Environment, for more information.
2019 Form 10-K | 64 | Wisconsin Electric Power Company |
Severance Liability for Plant Retirements
In December 2017, a severance liability of $25.8 million was recorded in other current liabilities on our balance sheets related to these plant retirements. Activity related to this severance liability for the years ended December 31 was as follows:
(in millions) | 2019 | 2018 | ||||||
Severance liability at January 1 | $ | 12.9 | $ | 25.8 | ||||
Severance payments | (5.7 | ) | (9.9 | ) | ||||
Other | (5.1 | ) | (3.0 | ) | ||||
Total severance liability at December 31 | $ | 2.1 | $ | 12.9 | ||||
NOTE 7—ASSET RETIREMENT OBLIGATIONS
We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities, the removal and dismantlement of biomass and hydro generation facilities, and the closure of fly-ash landfills at our generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the PSCW.
On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31:
(in millions) | 2019 | 2018 | 2017 | |||||||||
Balance as of January 1 | $ | 70.7 | $ | 68.3 | $ | 61.5 | ||||||
Accretion | 3.6 | 3.3 | 3.2 | |||||||||
Additions and revisions to estimated cash flows | (8.4 | ) | * | 1.0 | 5.5 | |||||||
Liabilities settled | (0.9 | ) | (1.9 | ) | (1.9 | ) | ||||||
Balance as of December 31 | $ | 65.0 | $ | 70.7 | $ | 68.3 | ||||||
* | AROs decreased $7.3 million due to revisions made to estimated cash flows for the abatement of asbestos. |
NOTE 8—COMMON EQUITY
Stock-Based Compensation Plans
The following table summarizes our pre-tax stock-based compensation expense, including amounts allocated from WBS, and the related tax benefit recognized in income for the years ended December 31:
(in millions) | 2019 | 2018 | 2017 | |||||||||
Stock options | $ | 1.7 | $ | 2.0 | $ | 1.3 | ||||||
Restricted stock | 2.7 | 3.0 | 0.8 | |||||||||
Performance units | 17.9 | 9.6 | 9.9 | |||||||||
Stock-based compensation expense | $ | 22.3 | $ | 14.6 | $ | 12.0 | ||||||
Related tax benefit | $ | 6.1 | $ | 4.0 | $ | 4.8 | ||||||
Stock-based compensation costs capitalized during 2019, 2018, and 2017 were not significant.
2019 Form 10-K | 65 | Wisconsin Electric Power Company |
Stock Options
The following is a summary of our employees' WEC Energy Group stock option activity during 2019:
Stock Options | Number of Options | Weighted-Average Exercise Price | Weighted-Average Remaining Contractual Life (in years) | Aggregate Intrinsic Value (in millions) | |||||||||
Outstanding as of January 1, 2019 | 698,814 | $ | 43.64 | ||||||||||
Granted | 59,404 | $ | 68.18 | ||||||||||
Exercised | (183,459 | ) | $ | 34.50 | |||||||||
Transferred | 53,399 | $ | 48.30 | ||||||||||
Forfeited | (1,897 | ) | $ | 63.86 | |||||||||
Outstanding as of December 31, 2019 | 626,261 | $ | 48.98 | 5.1 | $ | 27.1 | |||||||
Exercisable as of December 31, 2019 | 470,982 | $ | 43.85 | 4.1 | $ | 22.8 | |||||||
The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2019. This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2019, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2019, 2018, and 2017 was $8.0 million, $12.9 million, and $11.2 million, respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $6.3 million, $10.0 million, and $7.7 million during the years ended December 31, 2019, 2018, and 2017, respectively. The actual tax benefit from option exercises for the same periods was approximately $2.2 million, $2.7 million, and $4.5 million, respectively.
As of December 31, 2019, we expected to recognize approximately $0.8 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.6 years on a weighted-average basis.
During the first quarter of 2020, the Compensation Committee awarded 59,511 non-qualified WEC Energy Group stock options with an exercise price of $91.49 and a weighted-average grant date fair value of $10.82 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.
Restricted Shares
The following is a summary of our employees' WEC Energy Group restricted stock activity during 2019:
Restricted Shares | Number of Shares | Weighted-Average Grant Date Fair Value | |||||
Outstanding and unvested as of January 1, 2019 | 9,851 | $ | 60.53 | ||||
Granted | 5,181 | $ | 68.18 | ||||
Released | (5,220 | ) | $ | 58.32 | |||
Transferred | 360 | $ | 59.94 | ||||
Forfeited | (436 | ) | $ | 64.52 | |||
Outstanding and unvested as of December 31, 2019 | 9,736 | $ | 65.58 | ||||
The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.4 million for each of the years ended December 31, 2019 and 2018, and $0.5 million for the year ended December 31, 2017. The actual tax benefit from released restricted shares was $0.1 million for each of the years ended December 31, 2019 and 2018, and $0.2 million for the year ended December 31, 2017.
As of December 31, 2019, we expected to recognize approximately $1.0 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group restricted stock over the next 1.6 years on a weighted-average basis.
During the first quarter of 2020, the Compensation Committee awarded 4,371 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $91.49 per share.
2019 Form 10-K | 66 | Wisconsin Electric Power Company |
Performance Units
During 2019, 2018, and 2017, the Compensation Committee awarded 22,452; 32,650; and 34,765 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan.
Performance units with an intrinsic value of $2.3 million, $2.0 million, and $1.4 million were settled during 2019, 2018, and 2017, respectively. The actual tax benefit from the distribution of performance units was approximately $0.5 million for the year ended December 31, 2019 and $0.4 million for each of the years ended December 31, 2018 and 2017.
At December 31, 2019, our employees held 66,051 WEC Energy Group performance units, including dividend equivalents. A liability of $6.6 million was recorded on our balance sheet at December 31, 2019 related to these outstanding units. As of December 31, 2019, we expected to recognize approximately $9.8 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 1.6 years on a weighted-average basis.
During the first quarter of 2020, performance units held by our employees with an intrinsic value of $3.7 million were settled. The actual tax benefit from the distribution of these awards was $0.9 million. In January 2020, the Compensation Committee also awarded 18,952 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation.
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.
In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 52.5%. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level.
We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.
See Note 10, Short-Term Debt and Lines of Credit, for a discussion of certain financial covenants related to our short-term debt obligations.
As of December 31, 2019, our restricted retained earnings totaled approximately $2.2 billion.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
NOTE 9—PREFERRED STOCK
The following table shows preferred stock authorized and outstanding at December 31, 2019 and 2018:
(in millions, except share and per share amounts) | Shares Authorized | Shares Outstanding | Redemption Price Per Share | Total | ||||||||||
$100 par value, Six Per Cent. Preferred Stock | 45,000 | 44,498 | — | $ | 4.4 | |||||||||
$100 par value, Serial Preferred Stock 3.60% Series | 2,286,500 | 260,000 | $ | 101 | 26.0 | |||||||||
$25 par value, Serial Preferred Stock | 5,000,000 | — | — | — | ||||||||||
Total | $ | 30.4 | ||||||||||||
2019 Form 10-K | 67 | Wisconsin Electric Power Company |
NOTE 10—SHORT-TERM DEBT AND LINES OF CREDIT
The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:
(in millions, except percentages) | 2019 | 2018 | ||||||
Commercial paper | ||||||||
Amount outstanding at December 31 | $ | 115.5 | $ | 134.9 | ||||
Average interest rate on amounts outstanding at December 31 | 2.03 | % | 2.96 | % | ||||
Our average amount of commercial paper borrowings based on daily outstanding balances during 2019 was $47.4 million, with a weighted-average interest rate during the period of 2.44%.
We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 65% or less. As of December 31, 2019, we were in compliance with this ratio.
The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31:
(in millions) | Maturity | 2019 | ||||
Revolving credit facility | October 2022 | $ | 500.0 | |||
Less: | ||||||
Letters of credit issued inside credit facility | $ | 1.0 | ||||
Commercial paper outstanding | 115.5 | |||||
Available capacity under existing agreement | $ | 383.5 | ||||
This facility has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year.
Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control.
2019 Form 10-K | 68 | Wisconsin Electric Power Company |
NOTE 11—LONG-TERM DEBT
The following table is a summary of our long-term debt outstanding as of December 31:
(in millions) | 2019 | 2018 | ||||||||
Long-term debt | Interest Rate | Year Due | ||||||||
Debentures (unsecured) | 4.25% | 2019 | — | 250.0 | ||||||
2.95% | 2021 | 300.0 | 300.0 | |||||||
2.05% | 2024 | 300.0 | — | |||||||
3.10% | 2025 | 250.0 | 250.0 | |||||||
6.50% | 2028 | 150.0 | 150.0 | |||||||
5.625% | 2033 | 335.0 | 335.0 | |||||||
5.70% | 2036 | 300.0 | 300.0 | |||||||
3.65% | 2042 | 250.0 | 250.0 | |||||||
4.25% | 2044 | 250.0 | 250.0 | |||||||
4.30% | 2045 | 250.0 | 250.0 | |||||||
4.30% | 2048 | 300.0 | 300.0 | |||||||
6.875% | 2095 | 100.0 | 100.0 | |||||||
Total | 2,785.0 | 2,735.0 | ||||||||
Unamortized debt issuance costs | (8.0 | ) | (6.0 | ) | ||||||
Unamortized discount, net | (17.8 | ) | (19.4 | ) | ||||||
Total long-term debt, including current portion | 2,759.2 | 2,709.6 | ||||||||
Current portion of long-term debt | — | (250.0 | ) | |||||||
Total long-term debt | 2,759.2 | 2,459.6 | ||||||||
We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.
In December 2019, we issued $300.0 million of 2.05% Debentures due December 15, 2024, and used the net proceeds to repay our $250.0 million of 4.25% Debentures which matured in December 2019, to repay short-term debt, and for working capital and other corporate purposes.
The following table shows the future maturities of our long-term debt outstanding as of December 31, 2019:
(in millions) | ||||
2020 | $ | — | ||
2021 | 300.0 | |||
2022 | — | |||
2023 | — | |||
2024 | 300.0 | |||
Thereafter | 2,185.0 | |||
Total | $ | 2,785.0 | ||
Our long-term debt obligations contain covenants related to payment of principal and interest when due and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.
NOTE 12—LEASES
Obligations Under Operating Leases
We have recorded right of use assets and lease liabilities associated with the following operating leases.
• | Land we are leasing related to our Rothschild biomass plant through June 2051. |
• | Rail cars we are leasing to transport coal to various generating facilities through February 2021. |
• | Various office space leases. |
2019 Form 10-K | 69 | Wisconsin Electric Power Company |
The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement.
Obligations Under Finance Leases
We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under finance lease accounting, we have recorded the leased plants and corresponding obligations as right of use assets and lease liabilities on our balance sheets. We treat these agreements as operating leases for rate-making purposes.
Prior to our adoption of Topic 842 on January 1, 2019, we accounted for these finance leases under Topic 980-840, Regulated Operations – Leases, as follows:
• | We recorded our minimum lease payments under the power purchase contract as purchased power expense in cost of sales on our income statements. |
• | We recorded our minimum lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements. |
• | We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. |
In conjunction with our adoption of Topic 842, while the timing of expense recognition related to our finance leases did not change, the classification of the lease expense changed as follows:
• | Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within cost of sales in our income statements, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases. |
• | Similarly, the lease payments related to our leases with We Power were no longer classified within other operation and maintenance in our income statements, but were also divided between depreciation and amortization expense and interest expense in accordance with Topic 980-842. |
• | In accordance with Topic 980-842, the timing of lease expense did not change for these finance leases upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, as the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842. |
• | We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets. |
Power Purchase Commitment
In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years, purchase the generating facility at fair market value, or allow the contract to expire. At lease inception we recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities.
As previously discussed, we treat the long-term power purchase contract as an operating lease for rate-making purposes. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $18.4 million at December 31, 2019, and will decrease to zero over the remaining life of the contract.
Port Washington Generating Station
We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units, which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis
2019 Form 10-K | 70 | Wisconsin Electric Power Company |
over the original 25-year term of the leases. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.4 million in the year 2021 for PWGS 1 and to approximately $126.3 million in the year 2023 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases for the units was $617.8 million as of December 31, 2019, and will decrease to zero over the remaining lives of the contracts.
The only variability associated with the PWGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes is generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.
When the PWGS 1 and PWGS 2 contracts expire in 2030 and 2033, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.
Elm Road Generating Station
We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8 generating units, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30-year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $525.4 million in the year 2028 for ER 1 and to approximately $431.9 million in the year 2029 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases was $2,204.7 million as of December 31, 2019, and will decrease to zero over the remaining lives of the contracts.
The only variability associated with the ERGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840.
When the ER 1 and ER 2 contracts expire in 2040 and 2041, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire.
2019 Form 10-K | 71 | Wisconsin Electric Power Company |
Amounts Recognized in the Financial Statements
The components of lease expense and supplemental cash flow information related to our leases for the year ended December 31 are as follows:
(in millions) | 2019 | 2018 | 2017 | |||||||||
Long-term power purchase commitment | $ | 8.2 | $ | 7.7 | $ | 7.2 | ||||||
We Power leases | 363.3 | 363.3 | 363.3 | |||||||||
Total finance/capital lease expense (1) | $ | 371.5 | $ | 371.0 | $ | 370.5 | ||||||
Operating lease expense (2) | 2.6 | 2.7 | 3.7 | |||||||||
Total lease expense | $ | 374.1 | $ | 373.7 | $ | 374.2 | ||||||
Other information | ||||||||||||
Cash paid for amounts included in the measurement of lease liabilities | ||||||||||||
Operating cash flows for finance/capital leases (3) | $ | 350.9 | $ | 381.4 | $ | 427.7 | ||||||
Operating cash flows for operating leases | $ | 2.6 | $ | 2.7 | $ | 3.5 | ||||||
Financing cash flows for finance leases (3) | $ | 50.5 | ||||||||||
Non-cash activity – right of use assets obtained in exchange for operating lease liabilities | $ | 13.0 | ||||||||||
Weighted-average remaining lease term – finance leases | 18.6 years | |||||||||||
Weighted-average remaining lease term – operating leases | 25.0 years | |||||||||||
Weighted-average discount rate – finance leases (4) | 13.9 | % | ||||||||||
Weighted average discount rate – operating leases (4) | 4.5 | % | ||||||||||
(1) | For the year ended December 31, 2019, total finance lease expense included amortization of right of use assets in the amount of $20.6 million (included in depreciation and amortization expense), and interest on lease liabilities of $350.9 million (included in interest expense). For the years ended December 31, 2018, and 2017, total capital lease cost related to the long-term power purchase agreement was included in cost of sales and total capital lease cost related to the PWGS and ERGS units was included in other operation and maintenance. |
(2) | Operating lease expense was included as a component of operation and maintenance for the years ended December 31, 2019, 2018, and 2017. |
(3) | Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to capital leases were recorded as a component of operating cash flows. |
(4) | Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our finance leases, the rate implicit in each lease was readily determinable. |
2019 Form 10-K | 72 | Wisconsin Electric Power Company |
The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets:
(in millions) | December 31, 2019 | December 31, 2018 | ||||||
Long-term power purchase commitment | ||||||||
Under finance/capital lease | $ | 140.3 | $ | 140.3 | ||||
Accumulated amortization | (126.6 | ) | (120.9 | ) | ||||
Total long-term power purchase commitment | $ | 13.7 | $ | 19.4 | ||||
PWGS | ||||||||
Under finance/capital lease | $ | 742.7 | $ | 736.9 | ||||
Accumulated amortization | (367.6 | ) | (335.9 | ) | ||||
Total PWGS | $ | 375.1 | $ | 401.0 | ||||
ERGS | ||||||||
Under finance/capital lease | $ | 2,194.4 | $ | 2,166.3 | ||||
Accumulated amortization | (672.8 | ) | (598.8 | ) | ||||
Total ERGS | $ | 1,521.6 | $ | 1,567.5 | ||||
Total finance lease right of use assets/capital lease assets | $ | 1,910.4 | $ | 1,987.9 | ||||
Right of use assets related to operating leases were $10.6 million at December 31, 2019, and were included in other long-term assets on our balance sheets.
Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of December 31, 2019, were as follows:
(in millions) | Total Operating Leases | Power Purchase Commitment | PWGS | ERGS | Total Finance Leases | |||||||||||||||
2020 | $ | 2.6 | $ | 8.8 | $ | 98.5 | $ | 294.4 | $ | 401.7 | ||||||||||
2021 | 0.7 | 9.4 | 98.5 | 294.4 | 402.3 | |||||||||||||||
2022 | 0.5 | 4.2 | 98.5 | 294.2 | 396.9 | |||||||||||||||
2023 | 0.5 | — | 98.5 | 294.1 | 392.6 | |||||||||||||||
2024 | 0.5 | — | 98.4 | 294.0 | 392.4 | |||||||||||||||
Thereafter | 13.2 | — | 681.7 | 4,558.1 | 5,239.8 | |||||||||||||||
Total minimum lease payments | 18.0 | 22.4 | 1,174.1 | 6,029.2 | 7,225.7 | |||||||||||||||
Less: Interest | (7.4 | ) | (4.0 | ) | (556.3 | ) | (3,824.5 | ) | (4,384.8 | ) | ||||||||||
Present value of minimum lease payments | 10.6 | 18.4 | 617.8 | 2,204.7 | 2,840.9 | |||||||||||||||
Less: Short-term lease liabilities | (2.2 | ) | (6.3 | ) | (25.4 | ) | (26.1 | ) | (57.8 | ) | ||||||||||
Long-term lease liabilities | $ | 8.4 | $ | 12.1 | $ | 592.4 | $ | 2,178.6 | $ | 2,783.1 | ||||||||||
Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively.
NOTE 13—INCOME TAXES
Income Tax Expense
The following table is a summary of income tax expense for each of the years ended December 31:
(in millions) | 2019 | 2018 | 2017 | |||||||||
Current tax expense (benefit) | $ | 73.4 | $ | (56.2 | ) | $ | 81.5 | |||||
Deferred income tax expense (benefit), net | (128.9 | ) | 0.1 | 110.6 | ||||||||
Investment tax credit, net | (2.3 | ) | (0.8 | ) | (0.9 | ) | ||||||
Total income tax expense (benefit) | $ | (57.8 | ) | $ | (56.9 | ) | $ | 191.2 | ||||
2019 Form 10-K | 73 | Wisconsin Electric Power Company |
Statutory Rate Reconciliation
The provision for income taxes for each of the years ended December 31 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:
2019 | 2018 | 2017 | |||||||||||||||||||
(in millions) | Amount | Effective Tax Rate | Amount | Effective Tax Rate | Amount | Effective Tax Rate | |||||||||||||||
Statutory federal income tax | $ | 63.9 | 21.0 | % | $ | 63.3 | 21.0 | % | $ | 184.4 | 35.0 | % | |||||||||
State income taxes net of federal tax benefit | 20.2 | 6.6 | % | 19.6 | 6.5 | % | 27.9 | 5.3 | % | ||||||||||||
Tax repairs * | (122.9 | ) | (40.1 | )% | (120.7 | ) | (39.9 | )% | — | — | % | ||||||||||
Federal excess amortization | (16.1 | ) | (5.3 | )% | (15.5 | ) | (5.1 | )% | — | — | % | ||||||||||
Wind production tax credits | (9.3 | ) | (3.0 | )% | (9.4 | ) | (3.1 | )% | (17.6 | ) | (3.3 | )% | |||||||||
Investment tax credit restored | (2.3 | ) | (0.8 | )% | (0.8 | ) | (0.3 | )% | (0.9 | ) | (0.2 | )% | |||||||||
AFUDC – Equity | (0.8 | ) | (0.3 | )% | (0.8 | ) | (0.3 | )% | (1.1 | ) | (0.2 | )% | |||||||||
Domestic production activities deferral (deduction) | 6.1 | 2.0 | % | 6.1 | 2.0 | % | (7.8 | ) | (1.5 | )% | |||||||||||
Other, net | 3.4 | 1.0 | % | 1.3 | 0.4 | % | 6.3 | 1.1 | % | ||||||||||||
Total income tax expense (benefit) | $ | (57.8 | ) | (18.9 | )% | $ | (56.9 | ) | (18.8 | )% | $ | 191.2 | 36.2 | % | |||||||
* | In accordance with a 2017 settlement agreement with the PSCW, we flowed through the tax benefit of our repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. The flow through treatment of the repair related deferred tax liabilities offset the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. See Note 21, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate order. |
Deferred Income Tax Assets and Liabilities
On December 22, 2017, the Tax Legislation was signed into law. For businesses, the Tax Legislation reduced the corporate federal tax rate from a maximum of 35% to a 21% rate effective January 1, 2018. In December 2017, we recorded a tax benefit related to the re-measurement of our deferred taxes in the amount of approximately $1,065 million. Accordingly, this amount was recorded as both an increase to regulatory liabilities as well as a decrease to certain existing regulatory assets as of December 31, 2017.
On December 22, 2017, the SEC staff issued guidance in SAB 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation were considered "provisional" and subject to revision at December 31, 2017, and through 2018, as discussed in SAB 118.
In 2018, we considered all available guidance from industry and income tax authorities related to these tax items, analyzed the impact on Alternative Minimum Tax Credit carryforwards, and revised our estimates for re-measurement of deferred income taxes related to guidance on bonus depreciation. See Note 21, Regulatory Environment, for more information on the re-measurement of deferred income taxes. At December 31, 2018, we no longer considered any amounts related to bonus depreciation and future tax benefit utilization "provisional," subject to any additional amendments or technical corrections to the Tax Legislation.
In 2019, we considered all available guidance from industry and income tax authorities related to these tax items and did not have any changes to our prior interpretations. Any further amendments or technical corrections to the Tax Legislation could subject these tax items to revision.
2019 Form 10-K | 74 | Wisconsin Electric Power Company |
The components of deferred income taxes as of December 31 were as follows:
(in millions) | 2019 | 2018 | ||||||
Deferred tax assets | ||||||||
Tax gross up – regulatory items | $ | 152.7 | $ | 203.0 | ||||
Deferred revenues | 126.8 | 129.3 | ||||||
Future tax benefits | 41.0 | 15.9 | ||||||
Regulatory deferrals | 1.3 | 97.3 | ||||||
Other | 63.2 | 59.3 | ||||||
Total deferred tax assets | $ | 385.0 | $ | 504.8 | ||||
Deferred tax liabilities | ||||||||
Property-related | $ | 1,368.9 | $ | 1,365.9 | ||||
Deferred costs – Plant retirements | 215.5 | 176.0 | ||||||
Employee benefits and compensation | 55.8 | 55.9 | ||||||
Deferred costs – SSR | 51.1 | 110.7 | ||||||
Other | 41.1 | 94.6 | ||||||
Total deferred tax liabilities | 1,732.4 | 1,803.1 | ||||||
Deferred tax liability, net | $ | 1,347.4 | $ | 1,298.3 | ||||
Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities.
The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2019 and 2018 are summarized in the tables below:
2019 (in millions) | Gross Value | Deferred Tax Effect | Earliest Year of Expiration | |||||||
Future tax benefits as of December 31, 2019 | ||||||||||
Federal tax credit | $ | — | $ | 37.1 | 2037 | |||||
State net operating loss | 52.4 | 3.3 | 2035 | |||||||
Other state benefits | — | 0.6 | 2019 | |||||||
Balance as of December 31, 2019 | $ | 52.4 | $ | 41.0 | ||||||
2018 (in millions) | Gross Value | Deferred Tax Effect | Earliest Year of Expiration | |||||||
Future tax benefits as of December 31, 2018 | ||||||||||
Federal tax credit | $ | — | $ | 11.6 | 2038 | |||||
State net operating loss | 68.7 | 4.3 | 2035 | |||||||
Balance as of December 31, 2018 | $ | 68.7 | $ | 15.9 | ||||||
Unrecognized Tax Benefits
We had no unrecognized tax benefits at December 31, 2019 and 2018.
We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2019.
For the years ended December 31, 2019 and 2018, we recognized no interest expense related to unrecognized tax benefits in our income statements. For the year ended December 31, 2017, we recognized $0.7 million of interest income related to unrecognized tax benefits in our income statements. For the years ended December 31, 2019, 2018, and 2017, we recognized no penalties related to unrecognized tax benefits in our income statements. For the years ended December 31, 2019 and 2018, we had no interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets.
We do not anticipate any significant increases in the total amount of unrecognized tax benefits within the next 12 months.
2019 Form 10-K | 75 | Wisconsin Electric Power Company |
Our primary tax jurisdictions include federal and the state of Wisconsin. With a few exceptions we are no longer subject to federal income tax examinations by the IRS for years prior to 2015. As of December 31, 2019, we were subject to examination by the Wisconsin taxing authority for tax years 2015 through 2019.
NOTE 14—FAIR VALUE MEASUREMENTS
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:
December 31, 2019 | ||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Derivative assets | ||||||||||||||||
Natural gas contracts | $ | 0.4 | $ | — | $ | — | $ | 0.4 | ||||||||
FTRs | — | — | 1.5 | 1.5 | ||||||||||||
Coal contracts | — | 0.1 | — | 0.1 | ||||||||||||
Total derivative assets | $ | 0.4 | $ | 0.1 | $ | 1.5 | $ | 2.0 | ||||||||
Derivative liabilities | ||||||||||||||||
Natural gas contracts | $ | 5.2 | $ | — | $ | — | $ | 5.2 | ||||||||
Coal contracts | — | 0.2 | — | 0.2 | ||||||||||||
Total derivative liabilities | $ | 5.2 | $ | 0.2 | $ | — | $ | 5.4 | ||||||||
December 31, 2018 | ||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Derivative assets | ||||||||||||||||
Natural gas contracts | $ | 0.7 | $ | — | $ | — | $ | 0.7 | ||||||||
FTRs | — | — | 4.4 | 4.4 | ||||||||||||
Total derivative assets | $ | 0.7 | $ | — | $ | 4.4 | $ | 5.1 | ||||||||
Derivative liabilities | ||||||||||||||||
Natural gas contracts | $ | 1.2 | $ | — | $ | — | $ | 1.2 | ||||||||
Coal contracts | — | 0.1 | — | 0.1 | ||||||||||||
Total derivative liabilities | $ | 1.2 | $ | 0.1 | $ | — | $ | 1.3 | ||||||||
The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:
(in millions) | 2019 | 2018 | 2017 | |||||||||
Balance at the beginning of the period | $ | 4.4 | $ | 2.4 | $ | 3.1 | ||||||
Purchases | 6.8 | 9.4 | 6.9 | |||||||||
Settlements | (9.7 | ) | (7.4 | ) | (7.6 | ) | ||||||
Balance at the end of the period | $ | 1.5 | $ | 4.4 | $ | 2.4 | ||||||
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
December 31, 2019 | December 31, 2018 | |||||||||||||||
(in millions) | Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Preferred stock | $ | 30.4 | $ | 29.5 | $ | 30.4 | $ | 28.3 | ||||||||
Long-term debt, including current portion | 2,759.2 | 3,209.5 | 2,709.6 | 2,881.6 | ||||||||||||
The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
2019 Form 10-K | 76 | Wisconsin Electric Power Company |
NOTE 15—DERIVATIVE INSTRUMENTS
The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. None of our derivatives are designated as hedging instruments.
December 31, 2019 | December 31, 2018 | |||||||||||||||
(in millions) | Derivative Assets | Derivative Liabilities | Derivative Assets | Derivative Liabilities | ||||||||||||
Other current | ||||||||||||||||
Natural gas contracts | $ | 0.4 | $ | 5.1 | $ | 0.7 | $ | 1.2 | ||||||||
FTRs | 1.5 | — | 4.4 | — | ||||||||||||
Coal contracts | — | 0.2 | — | 0.1 | ||||||||||||
Total other current | 1.9 | 5.3 | 5.1 | 1.3 | ||||||||||||
Other long-term | ||||||||||||||||
Natural gas contracts | — | 0.1 | — | — | ||||||||||||
Coal contracts | 0.1 | — | — | — | ||||||||||||
Total other long-term | 0.1 | 0.1 | — | — | ||||||||||||
Total | $ | 2.0 | $ | 5.4 | $ | 5.1 | $ | 1.3 | ||||||||
Realized gains (losses) on derivatives are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows for the years ended:
December 31, 2019 | December 31, 2018 | December 31, 2017 | ||||||||||||||||
(in millions) | Volume | Gains (Losses) | Volume | Gains | Volume | Gains (Losses) | ||||||||||||
Natural gas contracts | 61.6 Dth | $ | (11.3 | ) | 53.4 Dth | $ | 9.7 | 26.9 Dth | $ | (1.0 | ) | |||||||
Petroleum products contracts | — gallons | — | 4.2 gallons | 1.2 | 16.7 gallons | (1.4 | ) | |||||||||||
FTRs | 21.7 MWh | 8.7 | 21.2 MWh | 3.4 | 27.1 MWh | 7.6 | ||||||||||||
Total | $ | (2.6 | ) | $ | 14.3 | $ | 5.2 | |||||||||||
At December 31, 2019 and 2018, we had posted cash collateral of $8.5 million and $1.1 million, respectively, in our margin accounts.
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
December 31, 2019 | December 31, 2018 | ||||||||||||||||
(in millions) | Derivative Assets | Derivative Liabilities | Derivative Assets | Derivative Liabilities | |||||||||||||
Gross amount recognized on the balance sheet | $ | 2.0 | $ | 5.4 | $ | 5.1 | $ | 1.3 | |||||||||
Gross amount not offset on the balance sheet | (0.4 | ) | (5.2 | ) | (1) | (0.6 | ) | (1.3 | ) | (2) | |||||||
Net amount | $ | 1.6 | $ | 0.2 | $ | 4.5 | $ | — | |||||||||
(1) | Includes cash collateral posted of $4.8 million. |
(2) | Includes cash collateral posted of $0.7 million. |
NOTE 16—EMPLOYEE BENEFITS
Pension and Other Postretirement Employee Benefits
We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.
Generally, employees who started with us after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. New
2019 Form 10-K | 77 | Wisconsin Electric Power Company |
management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.
We use a year-end measurement date to measure the funded status of all of the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset.
The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets:
Pension Benefits | OPEB Benefits | ||||||||||||||||
(in millions) | 2019 | 2018 | 2019 | 2018 | |||||||||||||
Change in benefit obligation | |||||||||||||||||
Obligation at January 1 | $ | 1,099.4 | $ | 1,193.9 | $ | 227.7 | $ | 303.5 | |||||||||
Service cost | 12.6 | 13.2 | 4.5 | 6.9 | |||||||||||||
Interest cost | 45.2 | 42.3 | 9.5 | 11.1 | |||||||||||||
Participant contributions | — | — | 6.1 | 7.6 | |||||||||||||
Plan amendments | — | — | 2.7 | — | |||||||||||||
Net transfer to affiliates | (5.3 | ) | (1) | (4.5 | ) | (1) | — | — | |||||||||
Actuarial loss (gain) | 81.5 | (62.7 | ) | (29.8 | ) | (86.2 | ) | ||||||||||
Benefit payments | (85.1 | ) | (82.8 | ) | (16.2 | ) | (22.8 | ) | |||||||||
Federal subsidy on benefits paid | N/A | N/A | 1.1 | 0.9 | |||||||||||||
Transfer | — | — | 1.7 | (2) | 6.7 | (2) | |||||||||||
Obligation at December 31 | $ | 1,148.3 | $ | 1,099.4 | $ | 207.3 | $ | 227.7 | |||||||||
Change in fair value of plan assets | |||||||||||||||||
Fair value at January 1 | $ | 1,019.8 | $ | 1,134.1 | $ | 201.5 | $ | 220.1 | |||||||||
Actual return on plan assets | 156.7 | (31.0 | ) | 35.4 | (5.7 | ) | |||||||||||
Employer contributions | 3.8 | 4.0 | 1.7 | 2.3 | |||||||||||||
Participant contributions | — | — | 6.1 | 7.6 | |||||||||||||
Net transfer to affiliates | (0.6 | ) | (1) | (4.5 | ) | (1) | — | — | |||||||||
Benefit payments | (85.1 | ) | (82.8 | ) | (16.2 | ) | (22.8 | ) | |||||||||
Fair value at December 31 | $ | 1,094.6 | $ | 1,019.8 | $ | 228.5 | $ | 201.5 | |||||||||
Funded status at December 31 | $ | (53.7 | ) | $ | (79.6 | ) | $ | 21.2 | $ | (26.2 | ) | ||||||
(1) | Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 3, Related Parties, for more information. |
(2) | Represents a premium medical account that was transferred into the OPEB benefit obligation. |
The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:
Pension Benefits | OPEB Benefits | |||||||||||||||
(in millions) | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Other long-term assets | $ | 6.1 | $ | 12.7 | $ | 21.2 | $ | — | ||||||||
Pension and OPEB obligations | 59.8 | 92.3 | — | 26.2 | ||||||||||||
Total net (liabilities) assets | $ | (53.7 | ) | $ | (79.6 | ) | $ | 21.2 | $ | (26.2 | ) | |||||
The accumulated benefit obligation for all defined benefit pension plans was $1,147.0 million and $1,097.9 million as of December 31, 2019 and 2018, respectively.
The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:
(in millions) | 2019 | 2018 | ||||||
Projected benefit obligation | $ | 1,040.7 | $ | 997.0 | ||||
Accumulated benefit obligation | 1,039.5 | 995.5 | ||||||
Fair value of plan assets | 980.9 | 904.7 | ||||||
2019 Form 10-K | 78 | Wisconsin Electric Power Company |
The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31:
Pension Benefits | OPEB Benefits | |||||||||||||||
(in millions) | 2019 | 2018 | 2019 | 2018 | ||||||||||||
Net regulatory assets (liabilities) | ||||||||||||||||
Net actuarial loss (gain) | $ | 460.1 | $ | 491.0 | $ | (115.3 | ) | $ | (66.6 | ) | ||||||
Prior service credits | (2.3 | ) | (1.8 | ) | (1.5 | ) | (6.1 | ) | ||||||||
Total | $ | 457.8 | $ | 489.2 | $ | (116.8 | ) | $ | (72.7 | ) | ||||||
The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2020:
(in millions) | Pension Benefits | OPEB Benefits | ||||||
Net actuarial loss (gain) | $ | 36.6 | $ | (9.5 | ) | |||
Prior service credits | (0.1 | ) | (0.6 | ) | ||||
Total 2020 – estimated amortization | $ | 36.5 | $ | (10.1 | ) | |||
The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows:
Pension Benefits | OPEB Benefits | |||||||||||||||||||||||
(in millions) | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | ||||||||||||||||||
Service cost | $ | 12.6 | $ | 13.2 | $ | 12.2 | $ | 4.5 | $ | 6.9 | $ | 7.0 | ||||||||||||
Interest cost | 45.2 | 42.3 | 47.0 | 9.5 | 11.1 | 12.1 | ||||||||||||||||||
Expected return on plan assets | (72.4 | ) | (75.2 | ) | (76.6 | ) | (14.3 | ) | (15.5 | ) | (14.7 | ) | ||||||||||||
Plan settlement | — | — | 4.1 | — | — | — | ||||||||||||||||||
Amortization of prior service cost (credit) | 0.5 | 0.8 | 1.1 | (1.9 | ) | (2.2 | ) | (1.4 | ) | |||||||||||||||
Amortization of net actuarial loss (gain) | 28.0 | 38.0 | 35.4 | (2.1 | ) | — | — | |||||||||||||||||
Net periodic benefit cost (credit) | $ | 13.9 | $ | 19.1 | $ | 23.2 | $ | (4.3 | ) | $ | 0.3 | $ | 3.0 | |||||||||||
The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:
Pension Benefits | OPEB Benefits | |||||||
2019 | 2018 | 2019 | 2018 | |||||
Discount rate | 3.39% | 4.30% | 3.40% | 4.30% | ||||
Rate of compensation increase | 4.00% | 3.40% | N/A | N/A | ||||
Assumed medical cost trend rate (Pre 65) | N/A | N/A | 6.00% | 6.25% | ||||
Ultimate trend rate (Pre 65) | N/A | N/A | 5.00% | 5.00% | ||||
Year ultimate trend rate is reached (Pre 65) | N/A | N/A | 2028 | 2024 | ||||
Assumed medical cost trend rate (Post 65) | N/A | N/A | 6.04% | 6.12% | ||||
Ultimate trend rate (Post 65) | N/A | N/A | 5.00% | 5.00% | ||||
Year ultimate trend rate is reached (Post 65) | N/A | N/A | 2028 | 2028 | ||||
The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:
Pension Benefits | ||||||
2019 | 2018 | 2017 | ||||
Discount rate | 4.30% | 3.65% | 4.12% | |||
Expected return on plan assets | 7.00% | 7.00% | 7.00% | |||
Rate of compensation increase | 3.40% | 3.40% | 3.20% | |||
2019 Form 10-K | 79 | Wisconsin Electric Power Company |
OPEB Benefits | ||||||
2019 | 2018 | 2017 | ||||
Discount rate | 4.30% | 3.65% | 4.10% | |||
Expected return on plan assets | 7.25% | 7.25% | 7.25% | |||
Assumed medical cost trend rate (Pre 65) | 6.25% | 6.50% | 7.00% | |||
Ultimate trend rate (Pre 65) | 5.00% | 5.00% | 5.00% | |||
Year ultimate trend rate is reached (Pre 65) | 2024 | 2024 | 2021 | |||
Assumed medical cost trend rate (Post 65) | 6.12% | 6.18% | 7.00% | |||
Ultimate trend rate (Post 65) | 5.00% | 5.00% | 5.00% | |||
Year ultimate trend rate is reached (Post 65) | 2028 | 2028 | 2021 | |||
WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2020, the expected return on asset assumption is 6.75% for the pension plan and 7.00% for the OPEB plan.
Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2019, a one-percentage-point change in assumed health care cost trend rates would have had the following effects:
(in millions) | 1% Increase | 1% Decrease | ||||||
Effect on total of service and interest cost components of net periodic postretirement health care benefit cost | $ | 1.7 | $ | (1.4 | ) | |||
Effect on the health care component of the accumulated postretirement benefit obligation | 14.4 | (12.0 | ) | |||||
Plan Assets
Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.
The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.
Our pension trust target asset allocation is 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The two OPEB trusts' target asset allocations are 50% equity investments and 50% fixed income investments, and 70% equity investments and 30% fixed income investments, respectively. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.
Pension and OPEB plan investments are recorded at fair value. See Note 1(n), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.
2019 Form 10-K | 80 | Wisconsin Electric Power Company |
The following tables summarize the fair values of our investments by asset class:
December 31, 2019 | ||||||||||||||||||||||||||||||||
Pension Plan Assets | OPEB Assets | |||||||||||||||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||
Asset Class | ||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
Unites States equity | $ | 103.3 | $ | — | $ | — | $ | 103.3 | $ | 27.9 | $ | — | $ | — | $ | 27.9 | ||||||||||||||||
International equity | 98.4 | — | — | 98.4 | 28.5 | — | — | 28.5 | ||||||||||||||||||||||||
Fixed income securities: * | ||||||||||||||||||||||||||||||||
United States bonds | 49.1 | 438.9 | — | 488.0 | 23.1 | 52.6 | — | 75.7 | ||||||||||||||||||||||||
International bonds | 27.7 | 29.2 | — | 56.9 | 5.8 | 2.9 | — | 8.7 | ||||||||||||||||||||||||
$ | 278.5 | $ | 468.1 | $ | — | $ | 746.6 | $ | 85.3 | $ | 55.5 | $ | — | $ | 140.8 | |||||||||||||||||
Investments measured at net asset value | $ | 348.0 | $ | 87.7 | ||||||||||||||||||||||||||||
Total | $ | 278.5 | $ | 468.1 | $ | — | $ | 1,094.6 | $ | 85.3 | $ | 55.5 | $ | — | $ | 228.5 | ||||||||||||||||
* | This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. |
December 31, 2018 | ||||||||||||||||||||||||||||||||
Pension Plan Assets | OPEB Assets | |||||||||||||||||||||||||||||||
(in millions) | Level 1 | Level 2 | Level 3 | Total | Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||
Asset Class | ||||||||||||||||||||||||||||||||
Equity securities: | ||||||||||||||||||||||||||||||||
United States equity | $ | 89.0 | $ | — | $ | — | $ | 89.0 | $ | 24.6 | $ | — | $ | — | $ | 24.6 | ||||||||||||||||
International equity | 85.8 | — | — | 85.8 | 24.0 | — | — | 24.0 | ||||||||||||||||||||||||
Fixed income securities: * | ||||||||||||||||||||||||||||||||
United States bonds | 66.2 | 436.5 | — | 502.7 | 24.0 | 48.2 | — | 72.2 | ||||||||||||||||||||||||
International bonds | 8.3 | 31.4 | — | 39.7 | 1.6 | 3.0 | — | 4.6 | ||||||||||||||||||||||||
$ | 249.3 | $ | 467.9 | $ | — | $ | 717.2 | $ | 74.2 | $ | 51.2 | $ | — | $ | 125.4 | |||||||||||||||||
Investments measured at net asset value | $ | 302.6 | $ | 76.1 | ||||||||||||||||||||||||||||
Total | $ | 249.3 | $ | 467.9 | $ | — | $ | 1,019.8 | $ | 74.2 | $ | 51.2 | $ | — | $ | 201.5 | ||||||||||||||||
* | This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. |
The following table sets forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy:
Private Equity and Real Estate | ||||||||
(in millions) | Pension | OPEB | ||||||
Beginning balance at January 1, 2018 | $ | 55.3 | $ | 3.8 | ||||
Realized and unrealized gains | 4.1 | 0.8 | ||||||
Purchases | 9.8 | 0.7 | ||||||
Liquidations | (1.2 | ) | (0.1 | ) | ||||
Transfers out of level 3 | (68.0 | ) | (5.2 | ) | ||||
Ending balance at December 31, 2018 | $ | — | $ | — | ||||
Cash Flows
We expect to contribute $3.7 million to the pension plans and $0.1 million to the OPEB plans in 2020, dependent upon various factors affecting us, including our liquidity position and the effects of the Tax Legislation.
2019 Form 10-K | 81 | Wisconsin Electric Power Company |
The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years:
(in millions) | Pension Benefits | OPEB Benefits | ||||||
2020 | $ | 90.6 | $ | 11.4 | ||||
2021 | 88.2 | 11.4 | ||||||
2022 | 83.7 | 11.6 | ||||||
2023 | 82.6 | 11.8 | ||||||
2024 | 80.2 | 11.7 | ||||||
2025-2029 | 350.1 | 58.3 | ||||||
Savings Plans
WEC Energy Group sponsors 401(k) savings plans that allow substantially all of our full-time employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, which amounts are contributed to an employee's savings plan account. Total costs incurred under all of these plans was $11.9 million in both 2019 and 2018, and $11.7 million in 2017.
NOTE 17—SEGMENT INFORMATION
We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2019, we reported two 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. In addition, our steam operations produce, distribute, and sell steam to customers in metropolitan Milwaukee. Prior to April 1, 2019, we also provided electric service to Tilden, who owns an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 as UMERC's new natural gas-fired generation in the Upper Peninsula of Michigan is now operational. |
• | Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in southeastern, east central, and northern Wisconsin. |
No significant items were reported in the other segment during the years ended December 31, 2019 and 2018. Prior to October 2018, our other segment included Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved.
All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2019, 2018, and 2017.
2019 (in millions) | Utility | Other | Wisconsin Electric Power Company Consolidated | |||||||||
External revenues | $ | 3,496.7 | $ | — | $ | 3,496.7 | ||||||
Other operation and maintenance | 1,053.1 | — | 1,053.1 | |||||||||
Depreciation and amortization | 384.4 | — | 384.4 | |||||||||
Operating income | 760.2 | — | 760.2 | |||||||||
Interest expense | 477.4 | — | 477.4 | |||||||||
Capital expenditures | 590.6 | — | 590.6 | |||||||||
Total assets | 13,360.8 | — | 13,360.8 | |||||||||
2019 Form 10-K | 82 | Wisconsin Electric Power Company |
2018 (in millions) | Utility | Other | Wisconsin Electric Power Company Consolidated | |||||||||
External revenues | $ | 3,625.0 | $ | — | $ | 3,625.0 | ||||||
Other operation and maintenance | 1,502.4 | — | 1,502.4 | |||||||||
Depreciation and amortization | 348.1 | — | 348.1 | |||||||||
Operating income | 402.5 | — | 402.5 | |||||||||
Interest expense | 120.1 | — | 120.1 | |||||||||
Capital expenditures | 603.2 | — | 603.2 | |||||||||
Total assets | 13,538.3 | — | 13,538.3 | |||||||||
2017 (in millions) | Utility | Other | Wisconsin Electric Power Company Consolidated | |||||||||
External revenues | $ | 3,711.7 | $ | — | $ | 3,711.7 | ||||||
Other operation and maintenance | 1,352.0 | — | 1,352.0 | |||||||||
Depreciation and amortization | 331.6 | — | 331.6 | |||||||||
Operating income | 632.1 | — | 632.1 | |||||||||
Interest expense | 117.0 | 0.3 | 117.3 | |||||||||
Capital expenditures | 596.1 | — | 596.1 | |||||||||
Total assets | 13,121.6 | — | 13,121.6 | |||||||||
NOTE 18—VARIABLE INTEREST ENTITIES
The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.
We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.
Power Purchase Agreement
We have a 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 finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately two years. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the power purchase agreement.
We have $22.4 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.
NOTE 19—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.
2019 Form 10-K | 83 | Wisconsin Electric Power Company |
The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2019.
Payments Due By Period | ||||||||||||||||||||||||||||||
(in millions) | Date Contracts Extend Through | Total Amounts Committed | 2020 | 2021 | 2022 | 2023 | 2024 | Later Years | ||||||||||||||||||||||
Electric utility: | ||||||||||||||||||||||||||||||
Nuclear | 2033 | $ | 8,319.0 | $ | 475.1 | $ | 501.1 | $ | 531.2 | $ | 563.0 | $ | 596.8 | $ | 5,651.8 | |||||||||||||||
Coal supply and transportation | 2023 | 735.9 | 223.7 | 196.9 | 169.6 | 145.7 | — | — | ||||||||||||||||||||||
Purchased power | 2043 | 78.9 | 19.4 | 12.3 | 10.4 | 7.6 | 3.6 | 25.6 | ||||||||||||||||||||||
Natural gas utility supply and transportation | 2048 | 494.0 | 64.1 | 56.5 | 39.8 | 25.8 | 17.5 | 290.3 | ||||||||||||||||||||||
Total | $ | 9,627.8 | $ | 782.3 | $ | 766.8 | $ | 751.0 | $ | 742.1 | $ | 617.9 | $ | 5,967.7 | ||||||||||||||||
Environmental Matters
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:
• | the development of additional sources of renewable electric energy supply; |
• | the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems; |
• | the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules; |
• | the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects; |
• | the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation; |
• | the beneficial use of ash and other products from coal-fired and biomass generating units; and |
• | the remediation of former manufactured gas plant sites. |
Air Quality
National Ambient Air Quality Standards
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. The EPA issued final nonattainment area designations in April 2018. The following counties within our service territories were designated as partial nonattainment: Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, and Sheboygan shorelines. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. Petitioners in that case have argued that additional portions of Milwaukee, Waukesha, Ozaukee, and Washington Counties (among others) should be designated as nonattainment for ozone. In November 2019, the D.C. Circuit Court of Appeals heard oral arguments for that case. A decision is expected in spring 2020, and we expect that any subsequent EPA re-designation, if necessary, would take place in mid-2021. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply. The State of Wisconsin is currently working with stakeholders, including us, in developing regulations for inclusion in the state implementation plan required by the rule.
Mercury and Air Toxics Standards
In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the MATS rule as well as the CAA required RTR. The EPA was required by the United States Supreme Court to review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from
2019 Form 10-K | 84 | Wisconsin Electric Power Company |
power plants under Section 112 of the CAA. As a result, under the proposed rule, the emission standards and other requirements of the MATS rule first enacted in 2012 would remain in place. The EPA is not proposing to remove coal- and oil-fired power plants from the list of sources that are regulated under Section 112. The EPA also proposes that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the proposed rule to have a material impact on our financial condition or operations.
Climate Change
The ACE rule became effective in September 2019. This rule provides existing coal-fired generating units with standards for achieving GHG emission reductions. The rule was finalized in conjunction with two other separate and distinct rulemakings, (1) the repeal of the Clean Power Plan, and (2) revised implementing regulations for ACE, ongoing emissions guidelines, and all future emission guidelines for existing sources issued under CAA section 111(d). Every state's plan to implement ACE is required to focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. The rule is being litigated in challenges brought in the D.C. Circuit Court of Appeals by 22 states (including Wisconsin), local governments, and certain nongovernmental organizations. This litigation is proceeding, but has not yet been scheduled for oral argument. The WDNR is working with state utilities and has begun the process of developing the implementation plan with respect to the ACE rule.
In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. The EPA determined that the BSER for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage.
In April 2019, WEC Energy Group issued a climate report, which analyzes its GHG reduction goals with respect to international efforts to limit future global temperature increases to less than two degrees Celsius. WEC Energy Group will evaluate potential GHG reduction pathways as climate change policies and relevant technologies evolve over time.
WEC Energy Group continues to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute toward long-term GHG emissions reductions. WEC Energy Group's current plan, which includes us, is to work with its industry peers, environmental groups, public policy makers, and customers, with goals of reducing CO2 emissions. In 2019, WEC Energy Group met and exceeded its 2030 goal of reducing CO2 emissions by 40% below 2005 levels, and is re-evaluating its longer-term CO2 reduction goals. As a result of WEC Energy Group's generation reshaping plan, we retired approximately 1,500 MW of coal generation since the beginning of 2018, including the 2018 retirement of the Pleasant Prairie power plant as well as the March 2019 retirement of the PIPP. See Note 6, Property, Plant, and Equipment, for more information. WEC Energy Group also has a goal to decrease the rate of methane emissions from the natural gas distribution lines in its network by 30% per mile by the year 2030 from a 2011 baseline. WEC Energy Group was over half way toward meeting that goal at the end of 2019.
We are required to report our CO2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. Based upon our analysis of the data, we reported CO2 equivalent emissions of 16.2 million metric tonnes and 20.0 million metric tonnes to the EPA for 2019 and 2018, respectively. The level of CO2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.
We are also required to report CO2 equivalent emissions related to the natural gas that our natural gas operations distribute and sell. Based upon our analysis of the data, we reported CO2 equivalent emissions of 4.2 million metric tonnes and 4.1 million metric tonnes to the EPA for 2019 and 2018, respectively.
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 that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the BTA for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.
We have received BTA determinations for OC 5 through OC 8 and VAPP. Although we currently believe that existing technology at the PWGS satisfies the BTA requirements, final determinations will not be made until the discharge permit is renewed for this facility,
2019 Form 10-K | 85 | Wisconsin Electric Power Company |
which is expected to be in 2021. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new BTA requirements for this facility.
As a result of past capital investments completed to address Section 316(b) compliance, 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.
Steam Electric Effluent Limitation Guidelines
The EPA's final 2015 ELG rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect us relate to discharge limits for BATW and wet FGD wastewater. As a result of past capital investments, we believe our fleet is well positioned to meet the existing ELG regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be modifications to the BATW systems at OC 7 and OC 8. Also, one wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS. Based on preliminary engineering, we estimate that compliance with the current rule will require $50 million in capital costs.
The ELG requirements for BATW and wet FGD systems are currently being re-evaluated by the EPA. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW and wet FGD wastewater requirements while it reconsiders the ELG rule. The Postponement Rule left unchanged the latest ELG rule compliance date of December 31, 2023. In November 2019, the EPA Administrator signed the proposed ELG Reconsideration Rule to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. The EPA also proposed a provision that exempts facility owners from the new BATW and wet FGD requirements if a generating unit is retired by December 31, 2028. We expect the rule to be finalized in late 2020. In the meantime, we are currently evaluating what impact, if any, the proposed rule would have on our estimated compliance cost.
Land Quality
Manufactured Gas Plant Remediation
We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.
The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.
We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31:
(in millions) | 2019 | 2018 | ||||||
Regulatory assets | $ | 22.1 | $ | 24.2 | ||||
Reserves for future environmental remediation * | 12.1 | 13.2 | ||||||
* | Recorded within other long-term liabilities on our balance sheets. |
Renewables, Efficiency, and Conservation
Wisconsin Legislation
In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. We have achieved our required renewable energy percentage of 8.27% and met our compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolio and acquire cost-effective renewables as needed to meet our requirements on an ongoing
2019 Form 10-K | 86 | Wisconsin Electric Power Company |
basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual retail operating revenues.
Enforcement and Litigation Matters
We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.
NOTE 20—SUPPLEMENTAL CASH FLOW INFORMATION
(in millions) | 2019 | 2018 | 2017 | |||||||||
Cash paid for interest, net of amount capitalized (1) | $ | 475.2 | $ | 115.0 | $ | 115.1 | ||||||
Cash paid for income taxes, net | 45.8 | 17.7 | 71.7 | |||||||||
Significant non-cash investing and financing transactions: | ||||||||||||
Accounts payable related to construction costs | 36.1 | 14.0 | 13.2 | |||||||||
Transfer of investment in ATC to another subsidiary of WEC Energy Group (2) (3) | — | — | 415.4 | |||||||||
Transfer of net assets to UMERC (2) | — | — | 61.1 | |||||||||
Equity settlement of a short-term note receivable between Bostco and our parent company | — | — | 4.8 | |||||||||
(1) | On January 1, 2019, we adopted ASU 2016-02, Leases (Topic 842). This ASU required us to prospectively change the classification of our finance lease payments on the income statement. As a result, during 2019, we classified the interest component of our finance lease payments as cash paid for interest since it was included in interest expense on the income statement. However, prior to our adoption of Topic 842, the interest component was not considered cash paid for interest since it was not included in interest expense on the income statement. See Note 12, Leases, for more information on Topic 842 and our finance leases. |
(2) | See Note 3, Related Parties, for more information on these transactions. |
(3) | The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. |
NOTE 21—REGULATORY ENVIRONMENT
Tax Cuts and Jobs Act of 2017
Due to the Tax Legislation, we deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,102 million that resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018.
In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order required our electric utility operations to use 80% of the current 2018 and 2019 tax benefits to reduce our transmission regulatory asset. The remaining 20% was to be returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of the current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting was used to reduce our transmission regulatory asset for our electric utility operations and was deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes was addressed in our rate order issued by the PSCW in December 2019. See the 2020 and 2021 Rates discussion below for more information.
We previously served one retail electric customer in Michigan, and we reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addressed all base rate impacts of the Tax Legislation, which were returned to the customer through bill credits.
2019 Form 10-K | 87 | Wisconsin Electric Power Company |
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 entered into with certain intervenors to resolve several outstanding issues in our rate case. On December 19, 2019, the PSCW issued a 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. 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 impact. The rate order reflects the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized evenly over two years, which results in approximately $65 million of tax benefits being amortized in each of 2020 and 2021. The unprotected deferred tax benefits related to the unrecovered balances of our recently retired plants and our SSR regulatory asset are being 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 will seek a financing order from the PSCW 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 fees. The securitization will reduce the carrying costs for the $100 million, benefiting customers.
We will continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under the new earnings sharing mechanism, if we earn above our authorized ROE: (i) we retain 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and (iii) 100.0% of any remaining excess earnings is refunded to customers. In addition, the rate order also requires us to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for our electric market-based rate programs for large industrial customers through 2021.
2018 and 2019 Rates
During April 2017, we, along with WPS and WG, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which froze base rates through 2019 for our electric, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remained at 10.2%, and our capital cost structure remained unchanged through 2019.
In addition to freezing base rates, the settlement agreement extended and expanded the electric real-time market pricing program options for large commercial and industrial customers and mitigated the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We were flowing through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While we would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offset the negative income statement impact of holding the regulatory assets level, resulting in no change to net income.
2019 Form 10-K | 88 | Wisconsin Electric Power Company |
Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earned above our authorized ROE, 50% of the first 50 basis points of additional utility earnings were required to be refunded to customers. All utility earnings above the first 50 basis points were also required to be refunded to customers.
Liquefied Natural Gas Facility
On November 1, 2019, we filed an application with the PSCW requesting approval to construct a LNG facility. If approved, the facility would provide us with approximately one billion cubic feet of natural gas supply to meet anticipated peak demand without requiring the construction of additional interstate pipeline capacity. This 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. Commercial operation of the LNG facility is targeted for the end of 2023.
Solar Generation Project
On August 1, 2019, we, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, we will own 100 MW of the output of this project. Our share of the cost of this project is estimated to be $130 million. At its meeting on February 20, 2020, the PSCW approved the acquisition of this project. The approval is still subject to our receipt and review of a final written order from the PSCW. Commercial operation of Badger Hollow II is targeted for the end of 2021.
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 provide a portion of the current storage needs for our natural gas utility operations. As a result of this agreement, we, along with WPS and WG, 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 agreement and interstate natural gas transportation contracts related to the storage facilities. We, along with WPS and WG, 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 entered into the long-term service agreement for the natural gas storage, which was then approved by the PSCW in November 2017. See Note 3, Related Parties, for more information.
NOTE 22—OTHER INCOME, NET
Total other income, net was as follows for the years ended December 31:
(in millions) | 2019 | 2018 | 2017 | |||||||||
AFUDC – Equity | $ | 3.7 | $ | 3.9 | $ | 3.1 | ||||||
Non-service credit (cost) components of net periodic benefit costs | 9.2 | 5.7 | (6.5 | ) | ||||||||
Interest income | 2.2 | 2.2 | 2.3 | |||||||||
Other, net | 7.6 | 8.4 | 14.3 | |||||||||
Other income, net | $ | 22.7 | $ | 20.2 | $ | 13.2 | ||||||
2019 Form 10-K | 89 | Wisconsin Electric Power Company |
NOTE 23—QUARTERLY FINANCIAL INFORMATION (Unaudited)
(in millions) | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Total | |||||||||||||||
2019 | ||||||||||||||||||||
Operating revenues | $ | 960.8 | $ | 791.7 | $ | 884.1 | $ | 860.1 | $ | 3,496.7 | ||||||||||
Operating income | 222.9 | 182.6 | 201.1 | 153.6 | 760.2 | |||||||||||||||
Net income attributed to common shareholder | 114.7 | 84.9 | 100.6 | 61.9 | 362.1 | |||||||||||||||
2018 | ||||||||||||||||||||
Operating revenues | $ | 941.5 | $ | 856.2 | $ | 924.0 | $ | 903.3 | $ | 3,625.0 | ||||||||||
Operating income | 136.4 | 104.5 | 107.8 | 53.8 | 402.5 | |||||||||||||||
Net income attributed to common shareholder | 105.8 | 92.8 | 103.2 | 56.5 | 358.3 | |||||||||||||||
NOTE 24—NEW ACCOUNTING PRONOUNCEMENTS
Financial Instruments Credit Losses
Effective January 1, 2020, we adopted FASB ASU 2016-13, "Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments," using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations.
Because our exposure to credit losses for many of our customers is mitigated by regulatory mechanisms we have in place, the noncash cumulative effect adjustment we recorded to retained earnings on January 1, 2020, as a result of our adoption of this standard, was not significant. The most significant impact of implementing this ASU will be in the form of additional disclosures that will be required in our quarterly report on Form 10-Q for the quarter ended March 31, 2020. These disclosures are intended to provide information that will help users of our financial statements analyze our exposure to credit risk and understand how we estimate our allowance for credit losses.
Cloud Computing
In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements.
Disclosure Requirements for Defined Benefit Plans
In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and other postretirement benefit plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. The guidance will be effective for annual reporting periods ending after December 15, 2020, with early adoption permitted. We are currently evaluating the effects of this pronouncement on the notes to our financial statements.
2019 Form 10-K | 90 | Wisconsin Electric Power Company |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. 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.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2019.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by our independent registered public accounting firm pursuant to rules of the SEC that permit us to provide only management's report in this annual report.
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 fourth quarter of 2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
2019 Form 10-K | 91 | Wisconsin Electric Power Company |
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE OF THE REGISTRANT
The information under "Election of Directors," "Corporate Governance – Frequently Asked Questions, and "Committees of the WEC Energy Group Board of Directors" in our Definitive Information Statement on Schedule 14C to be filed with the SEC for our Annual Meeting of Shareholders to be held April 30, 2020 (the "2020 Annual Meeting Information Statement") is incorporated herein by reference. Also see "Executive Officers of the Registrant" in Part I of this report.
WEC Energy Group has adopted a written code of ethics, referred to as its Code of Business Conduct. We are a subsidiary of WEC Energy Group, and as such, all of our directors, executive officers, and employees, including our principal executive officer, principal financial officer and principal accounting officer, have a responsibility to comply with WEC Energy Group's Code of Business Conduct. WEC Energy Group has posted its Code of Business Conduct in the "Governance" section on its website, www.wecenergygroup.com. WEC Energy Group has not provided any waiver to the Code for any director, executive officer, or other employee. Any amendments to, or waivers for directors and executive officers from, the Code of Business Conduct will be disclosed on WEC Energy Group's website or in a current report on Form 8-K.
ITEM 11. EXECUTIVE COMPENSATION
The information under "Compensation Discussion and Analysis," "Executive Compensation," "Director Compensation," "Committees of the WEC Energy Group Board of Directors," "Pay Ratio Disclosure," "Risk Analysis of Compensation Policies and Practices," and "Certain Relationships and Related Transactions" in the 2020 Annual Meeting Information Statement is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
All of our Common Stock is owned by our parent company, WEC Energy Group, 231 West Michigan Street, P.O. Box 1331, Milwaukee, Wisconsin 53201. Our directors and director nominees, who are all executive officers of WE, as well as our other executive officers, do not own any of our voting securities. The information concerning their beneficial ownership in WEC Energy Group common stock set forth under "Stock Ownership of Directors, Nominees and Executive Officers" in the 2020 Annual Meeting Information Statement is incorporated herein by reference.
We do not have any equity compensation plans under which our equity securities may be issued. Our directors, officers and certain employees participate in the compensation plans of WEC Energy Group.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information under "Corporate Governance – Frequently Asked Questions" and "Certain Relationships and Related Transactions" in the 2020 Annual Meeting Information Statement is incorporated herein by reference. A full description of the guidelines the WEC Energy Group Board uses to determine director independence is located in Appendix A of WEC Energy Group's Corporate Governance Guidelines, which can be found on its website, www.wecenergygroup.com.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information regarding the fees paid to, and services performed by, our independent auditors and the pre-approval policy of our audit and oversight committee under "Independent Auditors' Fees and Services" in the 2020 Annual Meeting Information Statement is incorporated herein by reference.
2019 Form 10-K | 92 | Wisconsin Electric Power Company |
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
1. | Financial Statements and Report of Independent Registered Public Accounting Firm Included in Part II of This Report | ||
Description | Page in 10-K | ||
2. | Financial Statement Schedules Included in Part IV of This Report | ||
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto. | |||
3. | Exhibits and Exhibit Index | ||
The following exhibits are filed or furnished with or incorporated by reference in the report with respect to Wisconsin Electric Power Company (File No. 001-01245). An asterisk (*) indicates that the exhibit has previously been filed with the SEC and is incorporated herein by reference. Each management contract and compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 15(b) of Form 10-K is identified below by two asterisks (**) following the description of the exhibit. | |||
Number | Exhibit | ||||
3 | Articles of Incorporation and By-laws | ||||
4 | Instruments defining the rights of security holders, including indentures | ||||
Indentures and Securities Resolutions: | |||||
2019 Form 10-K | 93 | Wisconsin Electric Power Company |
Number | Exhibit | ||||
Certain agreements and instruments with respect to unregistered long-term debt not exceeding 10 percent of the total assets of the Registrant and its subsidiary on a consolidated basis have been omitted as permitted by related instructions. The Registrant agrees pursuant to Item 601(b)(4) of Regulation S-K to furnish to the Securities and Exchange Commission, upon request, a copy of all such agreements and instruments. | |||||
10 | Material Contracts | ||||
2019 Form 10-K | 94 | Wisconsin Electric Power Company |
Number | Exhibit | ||||
2019 Form 10-K | 95 | Wisconsin Electric Power Company |
Number | Exhibit | ||||
23 | Consents of experts and counsel | ||||
31 | Rule 13a-14(a)/15d-14(a) Certifications | ||||
32 | Section 1350 Certifications | ||||
101 | Interactive Data File | ||||
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 | ||||
101.SCH | Inline XBRL Taxonomy Extension Schema | ||||
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase | ||||
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase | ||||
101.LAB | Inline XBRL Taxonomy Extension Label Linkbase | ||||
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase | ||||
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | ||||
ITEM 16. FORM 10-K SUMMARY
None.
2019 Form 10-K | 96 | Wisconsin Electric Power Company |
SCHEDULE II
WISCONSIN ELECTRIC POWER COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Allowance for Doubtful Accounts (in millions) | Balance at Beginning of Period | Transfer of Net Assets to UMERC (1) | Expense (2) | Deferral | Net Write-offs (3) | Balance at End of Period | ||||||||||||||||||
December 31, 2019 | $ | 40.9 | $ | — | $ | 32.7 | $ | (12.6 | ) | $ | (22.9 | ) | $ | 38.1 | ||||||||||
December 31, 2018 | 39.5 | — | 32.3 | (9.1 | ) | (21.8 | ) | 40.9 | ||||||||||||||||
December 31, 2017 | 40.9 | (0.3 | ) | 31.2 | (6.4 | ) | (25.9 | ) | 39.5 | |||||||||||||||
(1) | See Note 3, Related Parties, for more information. |
(2) | Net of recoveries. |
(3) | Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
2019 Form 10-K | 97 | Wisconsin Electric Power Company |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
WISCONSIN ELECTRIC POWER COMPANY | ||
By | /s/ J. KEVIN FLETCHER | |
Date: | February 27, 2020 | J. Kevin Fletcher |
Chairman of the Board and Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ J. KEVIN FLETCHER | February 27, 2020 | |
J. Kevin Fletcher, Chairman of the Board and Chief Executive | ||
Officer and Director -- Principal Executive Officer | ||
/s/ SCOTT J. LAUBER | February 27, 2020 | |
Scott J. Lauber, Executive Vice President and Chief Financial | ||
Officer and Director -- Principal Financial Officer | ||
/s/ WILLIAM J. GUC | February 27, 2020 | |
William J. Guc, Vice President, Controller, and Assistant | ||
Corporate Secretary -- Principal Accounting Officer | ||
/s/ MARGARET C. KELSEY | February 27, 2020 | |
Margaret C. Kelsey, Director | ||
/s/ GALE E. KLAPPA | February 27, 2020 | |
Gale E. Klappa, Director | ||
/s/ TOM METCALFE | February 27, 2020 | |
Tom Metcalfe, Director | ||
2019 Form 10-K | 98 | Wisconsin Electric Power Company |