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WEP 2018-12-31
Content
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Note 1(N), Derivative Instruments, and Note 1(O), Guarantees, for Information Concerning Potential Market Risks To Which We Are Exposed.
Item 8. Financial Statements and Supplementary Data
Note 1-Summary of Significant Accounting Policies
Note 2-Dispositions
Note 3-Related Parties
Note 4-Operating Revenues
Note 5-Regulatory Assets and Liabilities
Note 6-Property, Plant, and Equipment
Note 7-Asset Retirement Obligations
Note 8-Common Equity
Note 9-Preferred Stock
Note 10-Short-Term Debt and Lines of Credit
Note 11-Long-Term Debt and Capital Lease Obligations
Note 12-Income Taxes
Note 13-Fair Value Measurements
Note 14-Derivative Instruments
Note 15-Employee Benefits
Note 16-Investment in American Transmission Company
Note 17-Segment Information
Note 18-Variable Interest Entities
Note 19-Commitments and Contingencies
Note 20-Supplemental Cash Flow Information
Note 21-Regulatory Environment
Note 22-Other Income, Net
Note 23-Quarterly Financial Information (Unaudited)
Note 24-New Accounting Pronouncements
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance of The Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Exhibits
EX-10.1
a2018we10kexhibit101.htm
EX-10.2
a2018we10kexhibit102.htm
EX-10.3
a2018we10kexhibit103.htm
EX-10.4
a2018we10kexhibit104.htm
EX-10.5
a2018we10kexhibit105.htm
EX-10.6
a2018we10kexhibit106.htm
EX-23.1
a2018we10kexhibit231.htm
EX-31.1
a2018we10kexhibit311.htm
EX-31.2
a2018we10kexhibit312.htm
EX-32.1
a2018we10kexhibit321.htm
EX-32.2
a2018we10kexhibit322.htm
Wisconsin Electric Power Earnings 2018-12-31
WEP 10K Annual Report
Balance Sheet
Income Statement
Cash Flow
10-K 1 a2018we10k.htm WISCONSIN ELECTRIC 2018 FORM10-K Document
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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 [X]
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 [X]
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically 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 [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ]
Accelerated filer [ ]
Non-accelerated filer [X]
Smaller reporting company [ ]
Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [X]
As of June 30, 2018 (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, 2019
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 25, 2019, are incorporated by reference into Part III hereof.
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 ability to obtain and retain customers, including wholesale customers, due to increased competition in our electric and natural gas markets from retail choice and alternative electric suppliers, and continued industry consolidation;
•
The timely completion of capital projects within budgets, as well as the recovery of the related costs through rates;
•
The impact of federal, state, and local legislative and/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 that affect our ability to use production tax credits and investment tax credits;
•
The remaining uncertainty surrounding the Tax Legislation enacted in December 2017, including implementing regulations and IRS interpretations, the amount to be returned to our ratepayers, and its impact, if any, on our credit ratings;
•
Federal and state legislative and regulatory changes relating to the environment, including climate change and other environmental regulations impacting generation facilities and renewable energy standards, the enforcement of these laws and regulations, changes in the interpretation of regulations or permit conditions by regulatory agencies, and the recovery of associated remediation and compliance costs;
•
Factors affecting the implementation of WEC Energy Group's generation reshaping plan, including related regulatory decisions, the cost of materials, supplies, and labor, and the feasibility of competing projects;
•
Increased pressure on us by investors and other stakeholder groups to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases;
•
The risks associated with changing commodity prices, particularly natural gas and electricity, and the availability of sources of fossil fuel, natural gas, purchased power, materials needed to operate environmental controls at our electric generating facilities,
or water supply due to high demand, shortages, transportation problems, nonperformance by electric energy or natural gas suppliers under existing power purchase or natural gas supply contracts, or other developments;
•
Changes in credit ratings, interest rates, and our ability to access the capital markets, caused by volatility in the global credit markets, our capitalization structure, and market perceptions of the utility industry or us;
•
Costs and effects of litigation, administrative proceedings, investigations, settlements, claims, and inquiries;
•
The risk of financial loss, including increases in bad debt expense, associated with the inability of our customers, counterparties, and affiliates to meet their obligations;
•
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets and fuel suppliers and transporters;
•
The direct or indirect effect on our business resulting from terrorist 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 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 or businesses, which cannot be assured to be completed timely or within budgets;
•
The timing and outcome of any audits, disputes, and other proceedings related to taxes;
•
The ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act, while both integrating and continuing to consolidate WEC Energy Group's enterprise systems with those of its other utilities;
•
The effect of accounting pronouncements issued periodically by standard-setting bodies; and
•
Other considerations disclosed elsewhere herein and in other reports we file with the SEC or in other publicly disseminated written documents.
We expressly disclaim any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
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 the Consolidated Financial Statements included in this Annual Report on Form 10-K. See Note 2, Dispositions, 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 and served customers in the Upper Peninsula of Michigan through December 31, 2016. Effective January 1, 2017, we transferred our electric customers (other than Tilden, which is discussed in more detail below) and distribution assets located in the Upper Peninsula of Michigan to UMERC, a stand-alone utility owned by WEC Energy Group. See Note 21, Regulatory Environment, for more information on UMERC.
We conduct our business primarily through our utility reportable segment. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information.
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 and periodic filings with the SEC are available, free of charge, on WEC Energy Group's website, www.wecenergygroup.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. You may also obtain materials we filed with or furnished to the SEC on their website at www.sec.gov.
B. UTILITY SEGMENT
ELECTRIC UTILITY OPERATIONS
We are the largest electric utility in the state of Wisconsin. We generate and distribute electric energy to customers located in southeastern Wisconsin (including the metropolitan Milwaukee area), east central Wisconsin, and northern Wisconsin, and serve an iron ore mine customer, Tilden, in the Upper Peninsula of Michigan.
Through December 31, 2016, we served other electric customers in the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred our electric customers (other than Tilden) and electric distribution assets located in the Upper Peninsula of Michigan to UMERC, a stand-alone utility owned by WEC Energy Group. See Note 3, Related Parties, and Note 21, Regulatory Environment, for more information. UMERC currently meets its market obligations through power purchase agreements with us and WPS. UMERC will begin to generate electricity when its new generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur during the second quarter of 2019.
The following table shows electric utility operating revenues, including steam operations. For information about our operating revenues disaggregated by customer class for the year ended December 31, 2018, see Note 4, Operating Revenues. For more information about our significant accounting policies related to the recognition of revenues, see Note 1(d), Operating Revenues.
Year Ended December 31
(in millions)
2017
2016
Operating revenues
Residential
$
1,178.4
$
1,243.3
Small commercial and industrial
1,015.9
1,046.1
Large commercial and industrial
657.3
699.3
Other
21.2
21.0
Total retail revenues
2,872.8
3,009.7
Wholesale
118.8
88.7
Resale
238.0
224.4
Steam
23.3
27.2
Other operating revenues *
83.3
90.6
Total operating revenues
$
3,336.2
$
3,440.6
*
Includes SSR revenues, rent income, and ancillary revenues, partially offset by revenues from Tilden that are being deferred until a future rate proceeding. For more information, see the discussion below under the heading "Large Electric Retail Customers."
Electric Sales
Our electric energy deliveries included supply and distribution sales to retail and wholesale customers. In 2018, retail electric revenues accounted for 90.7% of total electric operating revenues, while wholesale and resale electric revenues accounted for 8.2% 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. Although we no longer provide electric service in certain territories in the state of Michigan, we continue, on an interim basis, to provide service to the Tilden mine located in the Upper Peninsula of Michigan. See the discussion below under the heading "Large Electric Retail Customers."
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. For more information, see D. Regulation.
Steam Sales
We have a steam utility that generates, distributes, and sells steam supplied by 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. In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. See Note 2, Dispositions, for more information.
Electric Sales Forecast
Our service territory experienced growth in weather-normalized retail electric sales in 2018 due to customer growth. We currently forecast retail electric sales volumes, excluding the Tilden iron ore mine located in the Upper Peninsula of Michigan, 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. The Tilden mine will no longer be a retail customer of ours once UMERC's new generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur in the second quarter of 2019. At that time, Tilden will become a retail customer of UMERC.
We provide electric utility service to a diversified base of customers in industries such as governmental, municipalities, cooperatives, and marketers, metals and other manufacturing, food products, health services, mining, education, and paper.
In February 2015, Tilden, along with another affiliated iron ore mine located in the Upper Peninsula of Michigan, returned as customers after choosing an alternative electric supplier in September 2013. We entered into a contract with each of the mines to provide full requirements electric service through December 31, 2019. Since 2015, we have been deferring, and expect to continue to defer, the revenues less costs of sales from the mine sales and will apply these amounts for the benefit of Wisconsin retail electric customers in a future rate proceeding, as ordered by the PSCW.
In 2016, one of the iron ore mines closed, and the related contract for full requirements electric service was terminated. In August 2016, WEC Energy Group entered into a new agreement with Tilden under which it will purchase electric power from UMERC for 20 years for the remaining mine, contingent upon UMERC's construction of natural gas-fired generation in the Upper Peninsula of Michigan. Tilden will continue to receive full requirements electric service from us under the existing contract until UMERC's generation solution in the Upper Peninsula of Michigan begins commercial operation, which is expected to occur during the second quarter of 2019. See Note 3, Related Parties, and Note 21, Regulatory Environment, for more information.
Wholesale Customers
We provide wholesale electric service to various customers, including electric cooperatives, municipal joint action agencies, other investor-owned utilities, municipal utilities, and energy marketers. Wholesale sales accounted for 5.2%, 4.6%, and 3.2% of total electric energy sales volumes during 2018, 2017, and 2016, respectively. Wholesale revenues accounted for 3.4%, 3.6%, and 2.6% of total electric operating revenues during 2018, 2017, and 2016, respectively.
Resale
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. Resale sales accounted for 15.3%, 23.5%, and 23.0% of total electric energy sales volumes during 2018, 2017, and 2016, respectively. Resale revenues accounted for 4.8%, 7.1%, and 6.5% of total electric operating revenues during 2018, 2017, and 2016, respectively. Retail fuel costs are reduced by the amount that revenue exceeds the costs of sales derived from these opportunity sales.
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 maintain a stable, reliable, and affordable supply of electricity. Through our participation in the MISO Energy Markets, we supply 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 capacity into the MISO Energy Markets when it is economical, which reduces net fuel costs by offsetting costs of purchased power.
Our rated capacity by fuel type as of December 31, including the units we lease from We Power, is shown below. For more information on our electric generation facilities, see Item 2. Properties.
Rated Capacity in MW (1)
2018
2017
2016
Coal
2,489
3,599
3,582
Natural gas:
Combined cycle
1,232
1,182
1,140
Steam turbine (2)
269
240
240
Natural gas/oil peaking units (3)
989
982
962
Renewables (4)
145
191
190
Total rated capacity
5,124
6,194
6,114
(1)
Rated capacity 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. We are a summer peaking electric utility, and amounts are primarily based on expected capacity ratings for the following summer. The values were established by tests and may change slightly from year to year.
(2)
The natural gas steam turbine represents the rated capacity associated with VAPP.
(3)
Certain dual-fueled facilities generally burn oil only if natural gas is not available due to constraints on the natural gas pipeline and/or at the local natural gas distribution company that delivers natural gas to the plants.
(4)
Includes hydroelectric, biomass, and wind generation.
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 2019:
Estimate
Actual
2019
2018
2017
2016
Company-owned or leased generation units:
Coal *
36.7
%
45.5
%
50.8
%
49.9
%
Natural gas:
Combined cycle
22.2
%
17.7
%
14.7
%
15.9
%
Steam turbine
1.1
%
0.8
%
1.1
%
1.2
%
Natural gas/oil peaking units
0.3
%
0.8
%
0.5
%
0.7
%
Renewables
4.0
%
3.7
%
3.8
%
3.5
%
Total company-owned or leased generation units
64.3
%
68.5
%
70.9
%
71.2
%
Power purchase contracts:
Nuclear
27.8
%
27.1
%
25.2
%
24.6
%
Natural gas
4.4
%
2.3
%
1.8
%
2.4
%
Renewables
1.9
%
1.3
%
1.8
%
1.8
%
Total power purchase contracts
34.1
%
30.7
%
28.8
%
28.8
%
Purchased power from MISO
1.6
%
0.8
%
0.3
%
—
%
Total purchased power
35.7
%
31.5
%
29.1
%
28.8
%
Total electric utility supply
100.0
%
100.0
%
100.0
%
100.0
%
*
Although the generation of PIPP has been included as a source of our electric energy supply for the three years ended December 31, we have only included this generation facility as a source of our estimated 2019 electric energy supply through its expected retirement date on or before May 31, 2019. See Note 6, Property, Plant, and Equipment, for more information.
Reshaping our Generation Fleet
The following discussion summarizes information about our generation facilities, including the planned reshaping of our 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 with a goal of reducing CO2 emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively.
As of December 31, 2018, our coal-fired generation, including the ERGS units we lease from We Power, consists of three operating plants with a rated capacity of 2,489 MW. For more information about our operating plants, see Item 2. Properties.
We plan to retire approximately 1,500 MW of coal-fired generation by 2020, as a result of WEC Energy Group's generation reshaping plan. As part of this effort during 2018, we retired the Pleasant Prairie power plant, which accounted for approximately 1,190 MW of coal-fired generation. We are required to retire PIPP by May 31, 2019. For more information about the retirement of these plants, see Note 6, Property, Plant, and Equipment.
Natural Gas-Fired Generation
Our natural gas-fired generation, including the PWGS units we lease from We Power, consists of four operating plants, including peaking units, with a rated capacity of 2,300 MW as of December 31, 2018. For more information about our operating plants, see Item 2. Properties.
Oil-Fired Generation
Our oil-fired generation had a rated capacity of 190 MW as of December 31, 2018. We also have natural gas-fired peaking units with a rated capacity of 799 MW, which have the ability to burn oil if natural gas is not available due to delivery constraints. For more information about our operating plants, see Item 2. Properties.
Renewable Generation
We meet a portion of our electric generation supply with various renewable energy resources. This helps us maintain compliance with renewable energy legislation in Wisconsin and Michigan. 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. For more information about our renewable generation, see Item 2. Properties.
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 renewables to our portfolio and will allow commercial and industrial customers to site solar arrays on their property.
Hydroelectric
Our hydroelectric generating system consists of 13 operating plants with a total installed capacity of 91 MW and a rated capacity of 53 MW as of December 31, 2018. All of our hydroelectric facilities follow FERC guidelines and/or regulations.
Wind
We have four wind sites, consisting of 200 turbines, with an installed capacity of 339 MW and a rated capacity of 46 MW as of December 31, 2018.
Biomass
We have a biomass-fueled power plant at a Rothschild, Wisconsin paper mill site. Wood waste and wood shavings are used to produce a rated capacity of approximately 46 MW of 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 discussed above, 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, the MPSC, 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 Wisconsin 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.
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 17.1% installed capacity reserve margin requirement for the planning year from June 1, 2018, through May 31, 2019, and a 16.8% installed capacity reserve margin requirement for the planning year from June 1, 2019, through May 31, 2020. MISO's short-term reserve margin requirements experience year-to-year fluctuations, primarily due to changes in the average forced outage rate of generation within the MISO footprint.
Michigan legislation requires all electric providers to demonstrate to the MPSC that they have enough resources to serve the anticipated needs of their customers for a minimum of four consecutive planning years beginning in the upcoming planning year June 1, 2019, through May 31, 2020. The MPSC has established future planning reserve margin requirements based on the same study conducted by MISO that determines the short-term reserve margin requirements.
In both of our Wisconsin and Michigan jurisdictions, we had 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 in both jurisdictions. However, extremely hot weather, unexpected equipment failure, or unavailability across the 15-state MISO footprint could require us to call upon load management procedures. Load management procedures allow for the reduction of energy use through agreements with customers to directly shut off their equipment or through interruptible service, where customers agree to reduce their load in the case of an emergency interruption.
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. Prudently incurred fuel and purchased power costs are recovered dollar-for-dollar from our Michigan retail electric customer. For more information about the fuel rules, see D. Regulation.
Our average fuel and purchased power costs per MWh by fuel type were as follows for the years ended December 31:
2018
2017
2016
Coal
$
22.39
$
22.26
$
22.68
Natural gas combined cycle
22.05
22.85
19.13
Natural gas/oil peaking units
63.29
60.44
46.99
Biomass
97.33
118.76
103.24
Purchased power
45.66
45.50
43.51
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. To moderate the volatility, we were given PSCW approval for a hedging program, which allows us to hedge up to 75% of our potential risks related to rail transportation fuel surcharge exposure. However, due to decreased volatility over the last few years, we suspended the fuel surcharge hedging program in 2017.
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 a PSCW-approved program that allows us to hedge up to 75% of our estimated natural gas use for electric generation in order to help manage our natural gas price risk.
Our hedging programs are generally implemented on a 36-month forward-looking basis. The results of these programs are reflected in the average costs of natural gas and purchased power.
Coal Supply
We diversify the coal supply for our electric generating facilities by purchasing coal from several mines in Wyoming, as well as from various other states. For 2019, approximately 89% of our total projected coal requirements of 6.4 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 two years are as follows. We have not entered into any coal contracts for years after 2020.
(in thousands)
Annual Tonnage
2019
5,733
2020
1,925
Coal Deliveries
All of our 2019 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, Pennsylvania, and Montana. The coal is transported by train to our rail-served electric-generating facilities and to dock storage in Superior, Wisconsin, until needed by our lake vessel-served facility, PIPP. See Note 6, Property, Plant, and Equipment, for more information about the planned retirement of PIPP. Additional small volume agreements may also be used to supplement the normal coal supply for our facilities.
Midcontinent Independent System Operator Costs
In connection with its status as a FERC approved RTO, MISO developed and operates the MISO Energy Markets, which include its bid-based energy and ancillary services markets. We are a participant in the MISO Energy Markets. For more information on MISO, see D. Regulation.
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 2019 through 2021 and 1,033 MW per year for 2022 and 2023, 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. Due to the actual and planned retirement of generation resources, we have entered into purchase agreements to procure additional planning capacity in order to maintain our compliance with planning reserve requirements as established by the PSCW, MPSC, and MISO.
Other Matters
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 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.
We face competition from various entities and other forms of energy sources available to customers, including self-generation by large industrial 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 territories, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Factors Affecting Results, Liquidity, and Capital Resources – Competitive Markets.
Environmental Matters
For information regarding environmental matters, especially as they relate to coal-fired generating facilities, see Note 19, Commitments and Contingencies.
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 also transport customer-owned natural gas. 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 a diversified base of industrial customers who are largely within our electric service territory. Major industries served include governmental, food and kindred products, education, real estate, and metal manufacturing. 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. For information about our operating revenues disaggregated by customer class for the year ended December 31, 2018, see Note 4, Operating Revenues. For more information about our significant accounting policies related to the recognition of revenues, see Note 1(d), Operating Revenues.
Year Ended December 31
(in millions)
2017
2016
Operating revenues
Residential
$
249.0
$
238.6
Commercial and industrial
114.3
105.0
Total retail revenues
363.3
343.6
Transport
13.7
13.6
Other operating revenues *
(1.5
)
(5.0
)
Total operating revenues
$
375.5
$
352.2
*
Includes amounts refunded to customers for purchased gas adjustment costs.
Natural Gas Sales Forecast
Our service territory experienced growth in weather-normalized natural gas deliveries (excluding natural gas deliveries for electric generation) in 2018 due to customer growth. We currently forecast retail natural gas delivery volumes to grow at a rate between 0.5% and 1.0% over the next five years, assuming normal weather.
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 and Storage Capacity
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.
Pipeline and storage capacity 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 liquefied natural gas and propane facilities located within our distribution system. These facilities are typically utilized during extreme demand conditions to ensure reliable supply to our customers.
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 2018 through 2019 heating season. Our peak daily send-out during 2018 was 6.8 million therms on January 1, 2018.
Natural Gas Supply
We have contracts for firm supplies with terms of 3–5 months 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.
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.
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. Commercial and industrial customers have the opportunity to choose a natural gas supplier other than us. We offer both natural gas transportation service and interruptible natural gas sales to enable customers to better manage their energy costs. Transportation customers purchase natural gas directly from third-party natural gas suppliers and use our distribution systems to transport the natural gas to their facilities. We earn a distribution charge for transporting the natural gas for these customers. 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. Customers continue to switch between firm system supply, interruptible system supply, and transportation service each year as the economics and service options change.
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, Dispositions, for more information.
Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information.
D. REGULATION
In addition to the specific regulations noted below, we are also subject to regulations, where applicable, of the EPA, the WDNR, the MDEQ, the Michigan Department of Natural Resources, and the United States Army Corps of Engineers.
Our rates were regulated by the various commissions shown in the table below during 2018. 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
*
Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of Tilden. See Note 3, Related Parties, and Note 21, Regulatory Environment, for more information.
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 Michigan retail electric customer and 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 2018 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, and will continue to be subject to it through 2019. 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/
MPSC
http://www.michigan.gov/mpsc/
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:
2018
2017
2016
(in millions)
Amount
Percent
Amount
Percent
Amount
Percent
Electric
Wisconsin
$
2,876.8
89.4
%
$
2,901.2
87.0
%
$
2,973.3
86.4
%
Michigan *
83.8
2.6
%
78.2
2.3
%
154.2
4.5
%
FERC – Wholesale *
258.2
8.0
%
356.8
10.7
%
313.1
9.1
%
Total
3,218.8
100.0
%
3,336.2
100.0
%
3,440.6
100.0
%
Natural Gas – Wisconsin
406.2
100.0
%
375.5
100.0
%
352.2
100.0
%
Total utility operating revenues
$
3,625.0
$
3,711.7
$
3,792.8
*
Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of Tilden. UMERC currently purchases 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, and Note 21, Regulatory Environment, 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, 2018, through May 31, 2019. The resulting ARR valuation 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, 2018, through May 31, 2019 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 and Public Acts 295 and 342 in Michigan, which contain 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 Code of Federal Regulations (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.
Our operations are subject to extensive environmental regulation by state and federal environmental agencies governing air and water quality, hazardous and solid waste management, environmental 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 of GHG emissions, coal combustion products, air emissions, or wastewater discharges, could significantly increase these environmental compliance costs.
Anticipated expenditures for environmental compliance and 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 matters related to manufactured gas plant sites and air and water quality, see Note 19, Commitments and Contingencies.
F. EMPLOYEES
As of December 31, 2018, we had 2,739 employees.
As of December 31, 2018, 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
1,611
August 15, 2020
Local 420 of International Union of Operating Engineers
360
September 30, 2021
Local 2006 Unit 1 of United Steel Workers of America
114
October 31, 2021
Local 510 of International Brotherhood of Electrical Workers
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, MPSC, 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 and the ability to recover the related costs, and continuing to recover the return on the carrying 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 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), 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.
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 Mercury and Air Toxics Standards rule, the CPP, 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. The EPA and the United States Army Corps of Engineers (Army Corps) have also adopted a final rule that would expand traditional federal jurisdiction over navigable waters and related wetlands for permitting and other regulatory matters. However, this rule has been stayed, and the EPA and the Army Corps have proposed revisions to it. 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 actions taken by the sitting President and Federal Executive Branch since taking office in January 2017, as well as its announced future plans and other factors, 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, certain of our coal-fired electric generating facilities have become uneconomical to maintain and operate, which has resulted in some of these units being retired or converted to an alternative type of fuel. For example, as part of our goal to retire approximately 1,500 MW of coal-fired generation by 2020, we retired the Pleasant Prairie power plant during 2018 and are required to retire PIPP by May 31, 2019. 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 by 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 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 increased generally throughout the United States. In particular, personal injury, property damage, and other claims for damages alleged to have been caused by environmental impacts and alleged exposure to hazardous materials have become more frequent. 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. In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the CPP, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of certain litigation in the D.C. Circuit Court of Appeals challenging the rule and, to the extent that further appellate review is sought, at the Supreme Court.
In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, be held in abeyance, which remains the case. In August 2018, the EPA issued a proposed replacement rule for the CPP, the ACE rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. In December 2018, the EPA proposed to revise the regulations related to new, modified, and reconstructed 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 CPP, the proposed ACE rule, and federal 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 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. In December 2016, Michigan enacted Act 342, which retains the 10% renewable energy portfolio requirement through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. 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, 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 efforts by investors and other stakeholders to increase pressure on us and others to take more aggressive action to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius. 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 results 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 rate or policies are changed with future federal or state legislation, we may be required to take material charges against earnings. For example, the United States federal income tax legislation enacted in December 2017 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 interpretations and implementing regulations by the Treasury Department and the IRS, as well as state income tax authorities, and the Tax Legislation could be subject to potential amendments and technical corrections, any of which could lessen or increase certain adverse impacts of the Tax Legislation. In addition, the regulatory treatment of the impacts of the Tax Legislation will be subject to the discretion of the FERC and state public utility commissions. State
and local taxing authorities continue to evaluate the impact of federal income tax reform, 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 state public utility commissions 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.
In addition, the FERC and state public utility commissions continue to engage with us to determine how certain tax savings will be returned to ratepayers. In December 2017, we deferred the estimated tax benefits for return to ratepayers through bill credits or reductions in regulatory assets. We have received written orders from the MPSC and the PSCW addressing the refunding of certain of these tax benefits to ratepayers in Michigan and Wisconsin, respectively. Despite receiving these written orders, the amount of tax benefits we must return to ratepayers could change if state commissions take additional action. Furthermore, if the amounts our regulators order us to return to ratepayers exceeds the actual amount of tax savings realized, or our regulators require the tax savings to be applied in a manner other than we had expected, it could have a material adverse effect on our financial condition, results of operations, and cash flow.
While our analysis and interpretation of the Tax Legislation is ongoing, based on our current evaluation, 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 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.
Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material effect on our results of operations.
We are subject to reporting, disclosure control, and other obligations under Section 404 of the Sarbanes-Oxley Act (SOX). SOX contains provisions requiring our management to report on the effectiveness of our internal control over financial reporting. We have undertaken, or will undertake, a variety of initiatives to integrate, standardize, centralize, and streamline our operations with technology, including, but not limited to, an enterprise resource planning system and a customer information and billing system. 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:
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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 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.
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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.
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Our customers' continued focus on energy conservation and ability to meet their own energy needs. 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 and Michigan, 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 invest 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; 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.
To the extent that delays occur, costs become unrecoverable, tax credits are lost, 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.
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.
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, 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 an enterprise resource planning system, 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.
Transporting and distributing natural gas 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.
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.
Failure of our counterparties to meet their obligations, including obligations under power purchase, natural gas supply, and transportation agreements, could have an adverse impact on our results of operations.
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 customer default under these agreements could have a negative impact on our results of operations and cash flows.
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:
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A rating downgrade;
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An economic downturn or uncertainty;
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Prevailing market conditions and rules;
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Concerns over foreign economic conditions;
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Changes in tax policy;
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Changes in investment criteria of institutional investors;
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War or the threat of war; and
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The overall health and view of the utility and financial institution industries.
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 our 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:
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Increase borrowing costs under our existing credit facility;
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Require the payment of higher interest rates in future financings and possibly reduce the pool of creditors;
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Decrease funding sources by limiting our access to the commercial paper market;
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Limit the availability of adequate credit support for our operations; and
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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 Michigan retail electric customer and 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:
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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;
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Higher rates charged to our customers, which could impact our competitive position;
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Reduced demand for energy, which could impact revenues and operating expenses; and
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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.
The 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. Increased competition in the retail and wholesale markets, which may result from restructuring efforts, 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.
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.
We own our principal properties outright, except that the major portion of our electric utility distribution lines, steam utility distribution mains and natural gas utility distribution mains and services are located, for the most part, on or under streets and highways and 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
As of December 31, 2018, we owned, or leased from We Power, the following generating assets:
Name
Location
Fuel
Number of Generating Units
Rated Capacity In MW (1)
Coal-fired plants
ERGS
Oak Creek, WI
Coal
2
1,057
(2)
PIPP
Marquette, MI
Coal
5
353
(3)
OCPP
Oak Creek, WI
Coal
4
1,079
Total coal-fired plants
11
2,489
Natural gas-fired plants
Concord Combustion Turbines
Watertown, WI
Natural Gas/Oil
4
359
Germantown Combustion Turbines
Germantown, WI
Natural Gas/Oil
5
270
Paris Combustion Turbines
Union Grove, WI
Natural Gas/Oil
4
360
PWGS
Port Washington, WI
Natural Gas
2
1,232
VAPP
Milwaukee, WI
Natural Gas
2
269
Total natural gas-fired plants
17
2,490
Renewables
Hydro Plants (13 in number)
WI and MI
Hydro
30
53
Rothschild Biomass Plant
Rothschild, WI
Biomass
1
46
Blue Sky Green Field
Fond du Lac, WI
Wind
88
17
Byron Wind Turbines
Fond du Lac, WI
Wind
2
—
Glacier Hills
Cambria, WI
Wind
90
26
Montfort Wind Energy Center
Montfort, WI
Wind
20
3
Total renewables
231
145
Total system
259
5,124
(1)
Values are primarily based on the net dependable capacity ratings for summer 2019 using historical generation. 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. The capacity indicated for the facility is equal to We Power's portion of total plant capacity based on its 83.34% ownership.
(3)
We are required to retire the PIPP units during the second quarter of 2019. See Note 6, Property, Plant, and Equipment, for more information on the plant retirement.
As of December 31, 2018, we operated approximately 19,800 miles of overhead distribution lines and 25,000 miles of underground distribution cable, as well as 312 electric distribution substations and approximately 290,300 line transformers.
Natural Gas Facilities
As of December 31, 2018, our natural gas distribution system included approximately 11,400 miles of distribution mains connected at 25 gate stations 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 Pipeline Company and approximately 414,000 natural gas lateral services. We have a liquefied natural gas storage plant that converts and stores, in liquefied form, natural gas received during periods of low consumption. The liquefied natural gas storage plant has a send-out capability of 70,000 Dth per day. Our natural gas distribution system consists almost entirely of plastic and coated steel pipe.
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, 2018, 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
The following should be read in conjunction with Note 19, Commitments and Contingencies, and Note 21, Regulatory Environment, in this report for additional information on material legal proceedings and matters related to us.
In addition to those legal proceedings discussed in Note 19, Commitments and Contingencies, Note 21, Regulatory Environment, and below, we are currently, and from time to time, subject to claims and suits arising in the ordinary course of business. Although the results of these 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.
Presque Isle Power Plant Matter
In March 2018, the EPA issued a Finding of Violation to us regarding alleged violations of mercury emission limits for PIPP Units 5, 6, 8, and 9, as well as failure to conduct mercury tests on our low-emitting electric generating units once every 12 months. We are cooperating with the EPA, and we do not expect this matter to have a material impact on our financial statements.
The names, ages, and positions of our executive officers at December 31, 2018 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.
Gale E. Klappa.(1) Age 68.
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WEC Energy Group — Chairman of the Board and Chief Executive Officer since October 2017, and from May 2004 to May 2016. Non-Executive Chairman of the Board from May 2016 to October 2017. Director since December 2003. President from April 2003 to August 2013.
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WE — Chairman of the Board since January 2018, and from May 2004 to May 2016. Chief Executive Officer since January 2018, and from August 2003 to May 2016. Director since January 2018, and from December 2003 to May 2016. President from August 2003 to June 2015.
J. Kevin Fletcher.(2) Age 60.
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WEC Energy Group — President since October 2018.
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WE — President from May 2016 to November 2018. Director since June 2015. 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 52.
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WEC Energy Group — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.
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WE — Executive Vice President - External Affairs since June 2015. Senior Vice President - External Affairs from April 2011 to June 2015.
William J. Guc. Age 49.
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WEC Energy Group — Controller since October 2015. Vice President since June 2015.
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WE — Vice President and Controller since October 2015.
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Integrys Energy Group — Vice President and Treasurer from December 2010 to June 2015.
Margaret C. Kelsey. Age 54.
•
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.(3) Age 53.
•
WEC Energy Group — Executive Vice President, Chief Financial Officer and Treasurer since October 2018. 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, Chief Financial Officer and Treasurer since October 2018. Director since April 2016. Executive Vice President and Chief Financial Officer from April 2016 to October 2018. Vice President and Treasurer from February 2013 to March 2016.
Tom Metcalfe. Age 51.
•
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.
Certain executive officers also hold officer and/or director positions at our other significant subsidiaries.
(1)
Effective February 1, 2019, Mr. Klappa was appointed Executive Chairman of WEC Energy Group. Also, effective February 1, 2019, Mr. Fletcher succeeded Mr. Klappa as Chairman and Chief Executive Officer of WE. Mr Klappa remains a Director of WE.
(2)
Effective February 1, 2019, Mr. Fletcher was appointed President and Chief Executive Officer and a Director of WEC Energy Group. Also effective February 1, 2019, Mr. Fletcher was appointed Chairman and Chief Executive Officer of WE.
(3)
Effective February 1, 2019, Mr. Lauber was named Senior Executive Vice President, Chief Financial Officer and Treasurer of WEC Energy Group.
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)
2018
2017 *
2016
2015
2014
Operating revenues
$
3,625.0
$
3,711.7
$
3,792.8
$
3,854.1
$
4,059.4
Net income attributed to common shareholder
358.3
335.6
364.3
375.7
376.7
Total assets
13,538.3
13,121.6
13,371.5
13,139.6
12,597.2
Long-term debt and capital lease obligations (excluding current portion)
5,266.8
5,236.1
5,417.6
5,351.3
4,875.2
*
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 and Note 16, Investment in American Transmission Company, for more information on these transactions.
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 have combined common functions with WG and operate under the trade name of "We Energies." We conduct our business primarily through our utility reportable segment. See Note 17, Segment Information, for more information on our reportable business segments.
Effective January 1, 2017, our customers (other than Tilden) and electric distribution assets located in the Upper Peninsula of Michigan were transferred to UMERC, a new stand-alone utility owned by WEC Energy Group. See Note 3, Related Parties, and Note 21, Regulatory Environment, for more information.
Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information. In March 2017, we sold the remaining real estate holdings of Bostco, and, in October 2018, Bostco was dissolved. See Note 2, Dispositions, for more information.
Corporate Strategy
Our goal is to continue to build and sustain long-term value for 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 will balance reliability and customer cost with environmental stewardship. Taken as a whole, this plan should reduce costs to customers, preserve fuel diversity, and lower carbon emissions. Generation reshaping includes retiring older fossil fuel generation units, building state-of-the-art natural gas generation, and investing in cost-effective zero-carbon generation with a goal of reducing CO2 emissions by approximately 40% below 2005 levels by 2030. In addition, WEC Energy Group set a new long-term goal of reducing CO2 emissions by approximately 80% below 2005 levels by 2050. WEC Energy Group expects to retire a total of approximately 1,800 MW of coal-fired generation by 2020 across its electric utilities, and add additional natural gas-fired generating units and renewable generation, including utility-scale solar projects. As part of this effort, we retired our 1,190 MW Pleasant Prairie power plant in April 2018. The physical dismantlement of the Pleasant Prairie power plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 6, Property, Plant, and Equipment, for information related to the Pleasant Prairie power plant retirement and the planned retirement of the 350 MW Presque Isle power plant as part of WEC Energy Group's plan.
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 to our portfolio, allowing commercial and industrial customers to site solar arrays on their property. 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 installations continues to decline, these pilots have become cost effective opportunities for us and our customers to participate in renewable energy.
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 operating efficiency and customer care, resulted in We Energies being recognized by PA Consulting Group, an independent consulting firm, as the most reliable utility in the Midwest for the eighth year in a row.
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 and improving business processes and consolidating its IT infrastructure across all of its companies. We expect these efforts to continue to drive operational efficiency and to put us in position to effectively support plans for future growth.
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 3, Related Parties, for information on WEC Energy Group's acquisition of Bluewater. See Note 2, Dispositions, for information on the sale of the MCPP steam generation and distribution assets and 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.
One example of how we obtain feedback from our customers is through our "We Care" calls, where our employees contact customers after a completed service call. Customer satisfaction is a priority, and making "We Care" calls is one of the main methods we use to gauge our performance to improve customer satisfaction.
Safety
We have a long-standing commitment to both workplace and public safety, and under our "Target Zero" mission, we have an ultimate goal of zero incidents, accidents, and injuries. We also set goals around injury-prevention activities that raise awareness and facilitate conversations about employee safety. 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.
The following table compares our consolidated results:
Year Ended December 31
(in millions)
2018
2017
2016
Operating revenues
$
3,625.0
$
3,711.7
$
3,792.8
Cost of sales
1,262.1
1,286.4
1,292.1
Other operation and maintenance
1,502.4
1,352.0
1,425.5
Depreciation and amortization
348.1
331.6
325.4
Property and revenue taxes
109.9
109.6
115.6
Operating income
402.5
632.1
634.2
Equity in earnings of transmission affiliate
—
—
55.5
Other income, net
20.2
13.2
4.4
Interest expense
120.1
117.3
117.6
Income before income taxes
302.6
528.0
576.5
Income tax (benefit) expense
(56.9
)
191.2
211.0
Preferred stock dividend requirements
1.2
1.2
1.2
Net income attributed to common shareholder
$
358.3
$
335.6
$
364.3
The table below shows the year-over-year income statement impacts associated with the flow through of tax repairs beginning January 1, 2018 and the Tax Legislation signed into law in December 2017. As shown in the table below, the changes related to these items had no impact on net income attributed to common shareholder. See Note 12, Income Taxes, and Note 21, Regulatory Environment, for more information.
(in millions)
2018 Compared with 2017
B (W)
Change Related to Flow Through of Tax Repairs
Change Related to Tax Legislation
Remaining Change B (W)
Operating revenues
$
(86.7
)
$
(88.1
)
$
(25.6
)
$
27.0
Cost of sales
24.3
—
—
24.3
Other operation and maintenance
(150.4
)
(77.8
)
(67.7
)
(4.9
)
Depreciation and amortization
(16.5
)
—
—
(16.5
)
Property and revenue taxes
(0.3
)
—
—
(0.3
)
Operating income
(229.6
)
(165.9
)
(93.3
)
29.6
Other income, net
7.0
—
—
7.0
Interest expense
(2.8
)
—
—
(2.8
)
Income before income taxes
(225.4
)
(165.9
)
(93.3
)
33.8
Income tax (benefit) expense
248.1
165.9
93.3
(11.1
)
Preferred stock dividend requirements
—
—
—
—
Net income attributed to common shareholder
$
22.7
$
—
$
—
$
22.7
See below for additional information on the year-over year changes in our 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, 2018, 2017, and 2016 was $402.5 million, $632.1 million, and $634.2 million, respectively. The operating income discussion below includes a table that provides the calculation of electric margins and natural gas margins, along with a reconciliation to utility segment operating income.
Utility Segment Contribution to Operating Income
Effective January 1, 2017, we transferred our electric customers (other than Tilden) located in the Upper Peninsula of Michigan to UMERC. See Note 3, Related Parties, for more information.
Year Ended December 31
(in millions)
2018
2017
2016
Electric revenues
$
3,218.8
$
3,336.2
$
3,440.6
Fuel and purchased power
1,010.1
1,064.3
1,091.8
Total electric margins
2,208.7
2,271.9
2,348.8
Natural gas revenues
406.2
375.5
352.2
Cost of natural gas sold
252.0
222.1
200.3
Total natural gas margins
154.2
153.4
151.9
Total electric and natural gas margins
2,362.9
2,425.3
2,500.7
Other operation and maintenance
1,502.4
1,352.0
1,425.5
Depreciation and amortization
348.1
331.6
325.4
Property and revenue taxes
109.9
109.6
115.6
Operating income
$
402.5
$
632.1
$
634.2
The following table shows a breakdown of other operation and maintenance:
Year Ended December 31
(in millions)
2018
2017
2016
Operation and maintenance not included in line items below
$
442.7
$
481.8
$
495.5
We Power (1)
506.9
513.0
513.2
Transmission (2)
265.1
251.9
273.8
Transmission expense related to the flow through of tax repairs (3)
77.8
—
—
Transmission expense related to Tax Legislation (4)
67.7
—
—
Regulatory amortizations and other pass through expenses (5)
98.1
96.7
96.6
Earnings sharing mechanism (6)
37.2
0.1
21.1
Other
6.9
8.5
25.3
Total other operation and maintenance
$
1,502.4
$
1,352.0
$
1,425.5
(1)
Represents costs associated with the We Power generation units, including operating and maintenance costs, as well as the lease payments that are billed from We Power to us and then recovered in our rates. During 2018, 2017, and 2016, $485.3 million, $535.1 million, and $528.4 million, respectively, of both lease and operating and maintenance costs were billed to us, with the difference in costs billed or incurred and expenses recognized, either deferred or deducted from the regulatory asset.
(2)
The PSCW has approved escrow accounting for our ATC and MISO network transmission expenses. As a result, we defer as a regulatory asset or liability the differences between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding. During 2018, 2017, and 2016, $286.3 million, $303.8 million, and $335.3 million, respectively, of costs were billed to us by transmission providers.
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.
(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.
(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 informationabout our earnings sharing mechanism.
The following tables provide information on delivered volumes by customer class and weather statistics: