G. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Nature of Operations—WEC Energy Group serves approximately 1.6 million electric customers and 3.0 million natural gas customers, and owns approximately 60% of ATC.
As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. On our financial statements, we consolidate our majority-owned subsidiaries and reflect noncontrolling interests for the portion of entities that we do not own as a component of consolidated equity separate from the equity attributable to our shareholders. The noncontrolling interests that we reported as equity on our balance sheet as of December 31, 2020 related to the minority interests at Bishop Hill III, Coyote Ridge, Upstream, Blooming Grove, and Tatanka Ridge held by third parties.
Our financial statements include the accounts of WEC Energy Group, a diversified energy holding company, and the accounts of our subsidiaries in the following reportable segments:
•Wisconsin segment – Consists of WE, WPS, and WG, which are engaged primarily in the generation of electricity and the distribution of electricity and natural gas in Wisconsin; and UMERC, which generates electricity and distributes electricity and natural gas to customers located in the Upper Peninsula of Michigan.
•Illinois segment – Consists of PGL and NSG, which are engaged primarily in the distribution of natural gas in Illinois.
•Other states segment – Consists of MERC and MGU, which are engaged primarily in the distribution of natural gas in Minnesota and Michigan, respectively.
•Electric transmission segment – Consists of our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions, and our approximate 75% ownership interest in ATC Holdco, which invests in transmission-related projects outside of ATC's traditional footprint.
•Non-utility energy infrastructure segment – Consists of We Power, which is principally engaged in the ownership of electric power generating facilities for long-term lease to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. WECI, which holds our ownership interests in several wind generating facilities, is also included in this segment. See Note 2, Acquisitions, for more information on the WECI wind generating facilities.
•Corporate and other segment – Consists of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and PDL. See Note 3, Dispositions, for more information on the sale of our remaining PDL solar facilities.
Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. We use the cumulative earnings approach for classifying distributions received in the statements of cash flows. Under the cumulative earnings approach, we compare the distributions received to cumulative equity method earnings since inception. Any distributions received up to the amount of cumulative equity earnings are considered a return on investment and classified in operating activities. Any excess distributions are considered a return of investment and classified in investing activities.
Our financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information.
(b) Basis of Presentation—We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
(c) Cash and Cash Equivalents—Cash and cash equivalents include marketable debt securities with an original maturity of three months or less.
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2020 Form 10-K
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86
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WEC Energy Group, Inc.
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(d) Operating Revenues—The following discussion includes our significant accounting policies related to operating revenues. For additional required disclosures on disaggregation of operating revenues, see Note 4, Operating Revenues.
Revenues from Contracts with Customers
Electric Utility Operating Revenues
Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our Wisconsin residential and commercial and industrial customers and the majority of our Michigan residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. In our Michigan service territory, a limited number of residential and commercial and industrial customers can purchase the commodity from a third party. In this case, the delivery of the electricity represents our sole performance obligation.
The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated electric utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on the quantity of electricity delivered each month. Our retail electric rates in Wisconsin include base amounts for fuel and purchased power costs, which also impact our revenues. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs beyond a 2% price variance from the costs included in the rates charged to customers. Our electric utilities monitor the deferral of under-collected costs to ensure that it does not cause them to earn a greater ROE than authorized by the PSCW. In contrast, the rates of our Michigan retail electric customers include recovery of fuel and purchased power costs on a one-for-one basis. In addition, the Wisconsin residential tariffs of WE and WPS include a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. See Note 26, Regulatory Environment, for more information on how COVID-19 has affected the cost recovery mechanisms for our utility companies.
Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have our utilities provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric utilities and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis.
The transaction price of the performance obligations for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility's costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services.
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2020 Form 10-K
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87
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WEC Energy Group, Inc.
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We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets.
For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.
Natural Gas Utility Operating Revenues
We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under the tariffs of our regulated utilities. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer.
The transaction price of the performance obligations for our natural gas customers is valued using the rates, charges, terms, and conditions of service included in the tariffs of our regulated utilities, which have been approved by state regulators. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month.
The tariffs of our natural gas utilities include various rate mechanisms that allow them to recover or refund changes in prudently incurred costs from rate case-approved amounts. The rates for all of our natural gas utilities include one-for-one recovery mechanisms for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. In addition, the rates of PGL and NSG, and the residential tariffs of WE, WPS, and WG, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. The rates of PGL and NSG include riders for cost recovery of both environmental cleanup costs, energy conservation and management program costs, and income tax expense changes resulting from the Tax Legislation. Finally, PGL's rates include a cost recovery mechanism for SMP costs, and similarly, MERC's rates include a rider to recover costs incurred to replace or modify natural gas facilities. See Note 26, Regulatory Environment, for more information on how COVID-19 has affected the cost recovery mechanisms for our company.
Consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days.
Other Natural Gas Operating Revenues
We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and provides service to several unaffiliated customers. All amounts associated with services provided to affiliates have been eliminated at the consolidated level.
Other Non-Utility Operating Revenues
Wind generation revenues from WECI's ownership interests in wind generation facilities continued to grow with new acquisitions in 2020. See Note 2, Acquisitions, for more information on Blooming Grove and Tatanka Ridge, as well as the acquisition of other wind parks. Most of these wind generation facilities have offtake agreements with unaffiliated third parties for all of the energy to be produced by the facility, some of which are bundled with capacity and RECs. We consider bundled energy, capacity and RECs within these offtake agreements to be distinct performance obligations as each are often transacted separately in the marketplace. When
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2020 Form 10-K
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88
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WEC Energy Group, Inc.
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recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Revenue from the sale of this renewable energy is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of the renewable generation facility and conveys the ability to call on the wind facility to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The performance obligation for RECs is recognized at a point-in-time; however, the timing of revenue recognition is the same, as the generation of renewable energy and sale of RECs occur concurrently.
As part of the construction of the We Power electric generating units, we capitalized interest during construction, which is included in property, plant, and equipment. As allowed by the PSCW, we collected these carrying costs from WE's utility customers during construction. The equity portion of these carrying costs was recorded as a contract liability, and we continually amortize the deferred carrying costs to revenues over the related lease term that We Power has with WE. During 2020, 2019, and 2018 we recorded $22.9 million, $25.4 million, and $25.3 million, respectively, of revenues related to these deferred carrying costs. These contract liabilities are presented as deferred revenue, net on our balance sheets.
Non-utility operating revenues are also derived from servicing appliances for customers at MERC. These contracts customarily have a duration of one year or less and consist of a single performance obligation satisfied over time. We use a time-based output method to recognize revenues monthly for the service fee.
Revenues from distributed renewable solar projects consist primarily of sales of renewable energy and solar RECs generated by PDL. The sale of solar RECs is a distinct performance obligation as they are often sold separately from the renewable energy generated. Although the performance obligation for the sale of renewable energy is recognized over time and the performance obligation for solar RECs is recognized at a point-in-time, the timing of revenue recognition is the same, as the generation of renewable energy and sales of solar RECs occur concurrently. See Note 3, Dispositions, for more information on the sale of our remaining PDL solar facilities.
Other Operating Revenues
Alternative Revenues
Alternative revenues are created from programs authorized by regulators that allow our utilities to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. Alternative revenue programs allow compensation for the effects of weather abnormalities, other external factors, or demand side management initiatives. Alternative revenue programs can also provide incentive awards if the utility achieves certain objectives and in other limited circumstances. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers.
Below is a summary of the alternative revenue programs at our utilities:
•The rates of PGL, NSG, and MERC include decoupling mechanisms. These mechanisms differ by state and allow the utilities to recover or refund the differences between actual and authorized margins for certain customer classes. See Note 26, Regulatory Environment, for more information.
•PGL and NSG were authorized to implement a SPC rider for the recovery of incremental direct costs resulting from the COVID-19 pandemic, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs. See Note 26, Regulatory Environment, for more information.
•MERC’s rates include a conservation improvement program rider, which includes a financial incentive for meeting energy savings goals.
•WE and WPS provide wholesale electric service to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues.
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2020 Form 10-K
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89
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WEC Energy Group, Inc.
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(e) Credit Losses—The following discussion includes our significant accounting policies related to credit losses. For additional required disclosures on credit losses, see Note 5, Credit Losses.
Effective January 1, 2020, we adopted FASB ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, using the modified retrospective transition method. This ASU amends the impairment model to utilize an expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The amendment requires entities to consider a broader range of information to estimate expected credit losses, which may result in earlier recognition of loss. The cumulative effect of adopting this standard was not significant to our financial statements.
Our exposure to credit losses is related to our accounts receivable and unbilled revenue balances, which are primarily generated from the sale of electricity and natural gas by our regulated utility operations. Credit losses associated with our utility operations are analyzed at the reportable segment level as we believe contract terms, political and economic risks, and the regulatory environment are similar at this level as our reportable segments are generally based on the geographic location of the underlying utility operations.
We have an accounts receivable and unbilled revenue balance associated with our non-utility energy infrastructure segment, related to the sale of electricity from our majority-owned wind generating facilities through agreements with several large high credit quality counterparties. At the corporate and other segment, we had an accounts receivable and unbilled revenue balance at the beginning of 2020 related to the PDL residential solar facilities, which were sold in November 2020. See Note 3, Dispositions, for more information.
We evaluate the collectability of our accounts receivable and unbilled revenue balances considering a combination of factors. For some of our larger customers and also in circumstances where we become aware of a specific customer's inability to meet its financial obligations to us, we record a specific allowance for credit losses against amounts due in order to reduce the net recognized receivable to the amount we reasonably believe will be collected. For all other customers, we use the accounts receivable aging method to calculate an allowance for credit losses. Using this method, we classify accounts receivable into different aging buckets and calculate a reserve percentage for each aging bucket based upon historical loss rates. The calculated reserve percentages are updated on at least an annual basis, in order to ensure recent macroeconomic, political, and regulatory trends are captured in the calculation, to the extent possible. Risks identified that we do not believe are reflected in the calculated reserve percentages, are assessed on a quarterly basis to determine whether further adjustments are required.
We monitor our ongoing credit exposure through active review of counterparty accounts receivable balances against contract terms and due dates. Our activities include timely account reconciliation, dispute resolution and payment confirmation. To the extent possible, we work with customers with past due balances to negotiate payment plans, but will disconnect customers for non-payment as allowed by our regulators if necessary, and employ collection agencies and legal counsel to pursue recovery of defaulted receivables. For our larger customers, detailed credit review procedures may be performed in advance of any sales being made. We sometimes require letters of credit, parental guarantees, prepayments or other forms of credit assurance from our larger customers to mitigate credit risk. See Note 26, Regulatory Environment, for information on certain regulatory actions that were and/or are being taken for the purpose of ensuring that essential utility services are available to our customers during the COVID-19 pandemic.
(f) Materials, Supplies, and Inventories—Our inventory as of December 31 consisted of:
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(in millions)
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2020
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2019
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Natural gas in storage
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$
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224.9
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$
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227.7
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Materials and supplies
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218.1
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234.2
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Fossil fuel
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85.6
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87.9
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Total
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$
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528.6
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$
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549.8
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PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the LIFO cost method. Inventories stated on a LIFO basis represented approximately 22% and 19% of total inventories at December 31, 2020 and 2019, respectively. The estimated replacement cost of natural gas in inventory at December 31, 2020 and 2019, exceeded the LIFO cost by $31.5 million and $9.8 million, respectively. In calculating these replacement amounts, PGL and NSG used a Chicago city-gate natural gas price per Dth of $2.31 at December 31, 2020, and $1.95 at December 31, 2019.
Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.
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2020 Form 10-K
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90
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WEC Energy Group, Inc.
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(g) Regulatory Assets and Liabilities—The economic effects of regulation can result in regulated companies recording costs and revenues that are allowed in the rate-making process in a period different from the period they would have been recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent deferred costs probable of recovery from customers that would have otherwise been charged to expense. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or future costs already collected from customers in rates.
The recovery or refund of regulatory assets and liabilities is based on specific periods determined by our regulators or occurs over the normal operating period of the related assets and liabilities. If a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery, and the reduction is charged to expense in the current period. See Note 6, Regulatory Assets and Liabilities, for more information.
(h) Property, Plant, and Equipment—We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired.
We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Annual utility composite depreciation rates are shown below:
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Annual Utility Composite Depreciation Rates
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2020
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2019
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2018
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WE
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3.19%
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3.11%
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3.18%
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WPS
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2.63%
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2.44%
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2.50%
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WG
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2.33%
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2.29%
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2.30%
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PGL
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3.16%
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3.20%
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3.25%
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NSG
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2.48%
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2.48%
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2.45%
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MERC (1)
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2.47%
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2.33%
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1.95%
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MGU
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2.67%
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2.54%
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2.61%
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UMERC
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2.97%
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2.87%
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2.50%
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(1) The 2018 rate reflects the impact of a new depreciation study approved by the MPUC in May 2018. The rates approved were effective retroactive to January 2017. An approximate $1.4 million reduction in depreciation expense was recorded in 2018 related to this depreciation study.
We depreciate our We Power assets over the estimated useful life of the various property components. The components have useful lives of between 10 to 45 years for PWGS 1 and PWGS 2 and 10 to 55 years for ER 1 and ER 2.
We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 3 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement.
Third parties reimburse the utilities for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment.
See Note 7, Property, Plant, and Equipment, for more information.
(i) Allowance for Funds Used During Construction—AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net.
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2020 Form 10-K
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91
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WEC Energy Group, Inc.
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The majority of AFUDC is recorded at WE, WPS, WBS, WG, and UMERC. Approximately 50% of WE's, WPS's, WG's, UMERC's, and WBS's retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. The AFUDC calculation for WBS uses the WPS AFUDC retail rate, while our utilities' AFUDC rates are determined by their respective state commissions, each with specific requirements. Based on these requirements, our utilities did not record significant AFUDC for 2020, 2019, or 2018. Average AFUDC rates are shown below:
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2020
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Average AFUDC Retail Rate
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Average AFUDC Wholesale Rate
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WE
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8.68%
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5.39%
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WPS
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7.55%
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5.59%
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WG
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8.32%
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N/A
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UMERC
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6.28%
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N/A
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WBS
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7.55%
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N/A
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Our regulated utilities and WBS recorded the following AFUDC for the years ended December 31:
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(in millions)
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2020
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2019
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2018
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AFUDC – Debt
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WE
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$
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2.6
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|
|
$
|
1.5
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$
|
1.5
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WPS
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4.6
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|
|
2.4
|
|
|
1.9
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WG
|
|
0.6
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|
|
0.5
|
|
|
0.2
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UMERC
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—
|
|
|
1.3
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|
2.4
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WBS
|
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0.1
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|
0.1
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0.2
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Other
|
|
0.1
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|
|
0.1
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|
|
0.7
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Total AFUDC – Debt
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$
|
8.0
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|
|
$
|
5.9
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|
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$
|
6.9
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AFUDC – Equity
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WE
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$
|
7.0
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|
|
$
|
3.7
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|
|
$
|
3.9
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WPS
|
|
11.8
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|
|
5.7
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|
|
4.6
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|
WG
|
|
1.6
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|
|
1.3
|
|
|
0.6
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|
UMERC
|
|
0.1
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|
|
3.3
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|
|
5.4
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WBS
|
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0.2
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|
|
0.2
|
|
|
0.6
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Other
|
|
0.2
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|
|
0.2
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|
|
0.1
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Total AFUDC – Equity
|
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$
|
20.9
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$
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14.4
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$
|
15.2
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(j) Cloud Computing Hosting Arrangements that are Service Contracts—We have entered into several cloud computing arrangements that are hosted service contracts as part of projects related to the continuous transformation of technology. These projects include, among other things, developing a centralized repository for data to improve analytics and reporting, targeted ERP systems, a project management tool, and a power generation employee scheduling system. We present prepaid hosting fees that are service contracts in either prepayments or other long-term assets on our balance sheets and amortize them as the hosting services are received. Amortization expense, as well as the fees associated with the hosting arrangements, is recorded in other operation and maintenance expense on our income statements.
At December 31, 2020, we had $1.8 million of capitalized implementation costs related to cloud computing arrangements that are hosted service contracts. We amortize the implementation costs on a straight-line basis over the cloud computing service arrangement term once the component of the hosted service is ready for its intended use. Amortization for the year ended December 31, 2020 was not significant. The presentation of the implementation costs, along with the related amortization, follows the prepaid hosting fees.
(k) Asset Impairment—Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are performed when impairment indicators are present. During the third quarter of each year, we perform an annual impairment test at all of our reporting units that carry a goodwill balance. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit's net assets exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. See Note 10, Goodwill and Intangibles, for more information.
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2020 Form 10-K
|
92
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WEC Energy Group, Inc.
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We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. Long-lived assets that would be subject to an impairment assessment generally include any assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future, as well as assets within nonregulated operations that are proposed to be sold or are currently generating operating losses. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset.
When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining net book value of that generating unit at the end of each reporting period. If it becomes probable that regulators will disallow full recovery as well as a return on the remaining net book value of a generating unit that is either abandoned or probable of being abandoned, an impairment loss may be required. An impairment loss would be recorded if the remaining net book value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers, using an incremental borrowing rate. See Note 6, Regulatory Assets and Liabilities, for more information.
We periodically assess the recoverability of equity method investments when factors indicate the carrying amount of such assets may be impaired. Equity method investments are assessed for impairment by comparing the fair values of these investments to their carrying amounts if a fair value assessment was completed or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, an impairment loss is recognized equal to the amount by which the carrying amount exceeds the investment's fair value.
(l) Asset Retirement Obligations—We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. For our regulated entities, we recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 9, Asset Retirement Obligations, for more information.
(m) Intangible Liabilities—Our finite-lived intangible liabilities include revenue contracts, consisting of PPAs and a proxy revenue swap, in addition to interconnection agreements, which were all obtained through the acquisitions of wind generation facilities by WECI in our non-utility energy infrastructure segment. Intangible liabilities are amortized on a straight-line basis over their estimated useful life. Amortization of revenue contracts is recorded within operating revenues in the income statements. Amortization related to the interconnection agreements is recorded within other operation and maintenance in the income statements. The straight-line method of amortization is used because it best reflects the pattern in which the economic benefits of the intangibles are consumed or otherwise used. The amounts and useful lives assigned to intangible liabilities assumed impact the amount and timing of future amortization.
(n) Stock-Based Compensation—In accordance with the shareholder approved Omnibus Stock Incentive Plan, we provide long-term incentives through our equity interests to our non-employee directors, officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in common stock, cash, or a combination thereof. The number of shares of common stock authorized for issuance under the plan was 34.3 million.
We recognize stock-based compensation expense on a straight-line basis over the requisite service period. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period.
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2020 Form 10-K
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93
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WEC Energy Group, Inc.
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Stock Options
We grant non-qualified stock options that generally vest on a cliff-basis after three years. The exercise price of a stock option under the plan cannot be less than 100% of our common stock's fair market value on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of our common stock on the date of the grant. Options vest immediately upon retirement, death, or disability; however, they may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of the grant.
Our stock options are classified as equity awards. The fair value of our stock options was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted along with the weighted-average assumptions used in the valuation models:
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2020
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2019
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2018
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Stock options granted
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554,594
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476,418
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710,710
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Estimated weighted-average fair value per stock option
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$
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10.94
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$
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8.60
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$
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7.71
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Assumptions used to value the options:
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Risk-free interest rate
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0.2% – 1.9%
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2.5% – 2.7%
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1.6% – 2.8%
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Dividend yield
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3.0
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%
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3.6
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%
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3.5
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%
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Expected volatility
|
|
16.3
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%
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17.0
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%
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18.0
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%
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Expected life (years)
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|
8.6
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8.5
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|
5.9
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The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on our dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on our historical experience.
Restricted Shares
Restricted shares granted to employees generally have a vesting period of three years with one-third of the award vesting on each anniversary of the grant date. Restricted shares granted to certain officers and all non-employee directors fully vest after one year.
Our restricted shares are classified as equity awards.
Performance Units
Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on our total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over three years, as well as other performance metrics as may be determined by the Compensation Committee. Under the terms of the award, participants may earn between 0% and 175% of the performance unit award based on our total shareholder return. Pursuant to the terms of the plan, these percentages can be adjusted upwards or downwards based on our performance against additional performance measures, if any, adopted by the Compensation Committee. Performance units also accrue forfeitable dividend equivalents in the form of additional performance units.
All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on our stock price and performance achievement under the terms of the award. Stock-based compensation costs are generally recorded over the performance period, which is three years.
See Note 11, Common Equity, for more information on our stock-based compensation plans.
(o) Earnings Per Share—We compute basic earnings per share by dividing our net income attributed to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted earnings per share is computed in a similar manner, but includes the exercise and/or conversion of all potentially dilutive securities. Such dilutive securities include in-the-
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2020 Form 10-K
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94
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WEC Energy Group, Inc.
|
money stock options. The calculation of diluted earnings per share for the year ended December 31, 2020 excluded 207,445 stock options that had an anti-dilutive effect. There were no securities that had an anti-dilutive effect for the years ended December 31, 2019 and 2018.
(p) Leases—In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded.
As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance.
•We did not reassess whether any expired or existing contracts were leases or contained leases.
•We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases).
•We did not reassess the accounting for initial direct costs for any existing leases.
We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with ASC 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract.
We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842.
In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842.
In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply this guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842.
Right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $49.0 million and $48.8 million, respectively. Regarding our PPA that meets the criteria of a finance lease, while the adoption of Topic 842 changed the classification of expense related to this lease on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the lease asset and related liability amounts recorded on our balance sheets.
Significant Judgments and Other Information
We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind generating facilities. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets.
As of February 25, 2021, we have not entered into any material leases that have not yet commenced.
See Note 15, Leases, for more information.
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2020 Form 10-K
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95
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WEC Energy Group, Inc.
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(q) Income Taxes—We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense.
ITCs associated with regulated operations are deferred and amortized over the life of the assets. PTCs are recognized in the period in which such credits are generated. The amount of the credit is based upon power production from our qualifying generation facilities. We file a consolidated federal income tax return. Accordingly, we allocate federal current tax expense, benefits, and credits to our subsidiaries based on their separate tax computations and our ability to monetize all credits on our consolidated federal return. See Note 16, Income Taxes, for more information.
We recognize interest and penalties accrued, related to unrecognized tax benefits, in income tax expense in our income statements.
In February 2018, the FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income. The amendments in this update allowed entities to reclassify the income tax effects that are stranded in accumulated other comprehensive income as a result of the Tax Legislation to retained earnings. These amendments were effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We early adopted the amendments in the fourth quarter of 2018 and reclassified the stranded tax effects associated with the Tax Legislation from accumulated other comprehensive income to retained earnings. As of December 31, 2018, our accumulated other comprehensive income decreased $0.6 million as a result of adopting ASU 2018-02. The adoption of this guidance had no impact on our results of operations or cash flows.
(r) Fair Value Measurements—Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).
Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.
See Note 17, Fair Value Measurements, for more information.
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2020 Form 10-K
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96
|
WEC Energy Group, Inc.
|
(s) Derivative Instruments—We use derivatives as part of our risk management program to manage the risks associated with the price volatility of interest rates, purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.
We record derivative instruments on our balance sheets as assets or liabilities measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.
We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows.
Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 18, Derivative Instruments, for more information.
(t) Guarantees—We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. See Note 19, Guarantees, for more information.
(u) Employee Benefits—The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are distributed among our subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the utilities' net periodic benefit cost calculated under GAAP. See Note 20, Employee Benefits, for more information.
(v) Customer Deposits and Credit Balances—When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets.
Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets.
(w) Environmental Remediation Costs—We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion residual landfills and manufactured gas plant sites. See Note 9, Asset Retirement Obligations, for more information regarding coal combustion residual landfills and Note 24, Commitments and Contingencies, for more information regarding manufactured gas plant sites.
We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation.
Our utilities have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the applicable state regulatory commission's approval.
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2020 Form 10-K
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97
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WEC Energy Group, Inc.
|
We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion residual landfills. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year.
(x) Customer Concentrations of Credit Risk—The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Credit risk exposure at WE, WPS, WG, PGL, and NSG is mitigated by their recovery mechanisms for uncollectible expense discussed in Note 1(d), Operating Revenues. As a result, we did not have any significant concentrations of credit risk at December 31, 2020. In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2020.
NOTE 2—ACQUISITIONS
On January 1, 2018, we adopted ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU 2017-01). The amendments in this update clarify the definition of a business and provide guidance on evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 also clarifies that transaction costs are capitalized in an asset acquisition but expensed in a business combination.
The purchase price of certain acquisitions below includes intangibles recorded as long-term liabilities related to PPAs and interconnection agreements. See Note 10, Goodwill and Intangibles, for more information.
Acquisition of Wind Generation Facilities in South Dakota
In December 2020, WECI completed the acquisition of an 85% ownership interest in Tatanka Ridge, a 155 MW wind generating facility in Deuel County, South Dakota, that became commercially operational in January 2021. WECI's total investment was $239.9 million, which included transaction costs. Tatanka Ridge has offtake agreements for all the energy produced with an affiliate of an investment grade multinational company for 12 years and a well-established electric cooperative that serves utilities in multiple states for 10 years. Under the Tax Legislation, WECI's investment in Tatanka Ridge qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Tatanka Ridge is included in the non-utility energy infrastructure segment.
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.
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(in millions)
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Current assets
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$
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37.3
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Net property, plant, and equipment
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301.2
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Current liabilities
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(37.3)
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Long-term liabilities
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(19.3)
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Noncontrolling interest
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(42.0)
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Total purchase price
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$
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239.9
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In December 2018, WECI acquired an 80% ownership interest in Coyote Ridge, a 96.7 MW wind generating facility located in Brookings County, South Dakota, for $61.4 million, which included transaction costs. In December 2019, Coyote Ridge achieved commercial operation and WECI made an additional investment of $84.0 million related to capital expenditures for the project for a total investment of $145.4 million. The project has an offtake agreement with an unaffiliated third party for all of the energy produced for 12 years. Under the Tax Legislation, WECI's investment in Coyote Ridge qualifies for PTCs. WECI is entitled to 99% of the tax benefits related to this facility for the first 11 years of commercial operation, after which we will be entitled to tax benefits equal to our ownership interest. Coyote Ridge is included in the non-utility energy infrastructure segment.
The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition.
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(in millions)
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Net property, plant, and equipment
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$
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66.4
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Noncontrolling interest
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|
(5.0)
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Total purchase price
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|
$
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61.4
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2020 Form 10-K
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98
|
WEC Energy Group, Inc.
|
Acquisition of Wind Generation Facilities in Nebraska
In August 2019, WECI signed an agreement to acquire an 80% ownership interest in Thunderhead, a 300 MW wind generating facility under construction in Antelope and Wheeler counties in Nebraska, for a total investment of approximately $338 million. In February 2020, WECI agreed to acquire an additional 10% ownership interest in Thunderhead for $43 million. The project has an offtake agreement with an unaffiliated third party for all of the energy to be produced by the facility for 12 years. Under the Tax Legislation, WECI's investment in Thunderhead is expected to qualify for PTCs. The transaction was approved by FERC in April 2020, and commercial operation was initially expected to begin by the end of 2020. However, due to a court ruling suspending a key permit and the subsequent decision by the local utility to suspend construction of the required substation, the commercial operation of Thunderhead could be delayed until as late as the fall of 2021. The transaction is expected to close upon commercial operation. Thunderhead will be included in the non-utility energy infrastructure segment.
In January 2019, WECI completed the acquisition of an 80% ownership interest in Upstream, a commercially operational 202.5 MW wind generating facility, for $268.2 million, which included transaction costs and is net of cash and restricted cash acquired of $9.2 million. In February 2020, WECI signed an agreement to acquire an additional 10% ownership interest in Upstream for $31.0 million. Upstream is located in Antelope County, Nebraska and supplies energy to the Southwest Power Pool. Upstream's revenue will be substantially fixed over 10 years through an agreement with an unaffiliated third party. Under the Tax Legislation, WECI's investment in Upstream qualifies for PTCs. Upstream is included in the non-utility energy infrastructure segment.
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition of the initial 80% ownership interest in Upstream.
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|
|
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(in millions)
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|
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Current assets
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|
$
|
0.4
|
|
Net property, plant, and equipment
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|
341.6
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Other long-term assets
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|
14.8
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Current liabilities
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|
(4.6)
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Long-term liabilities
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|
(15.0)
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Noncontrolling interest
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|
(69.0)
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Total purchase price
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$
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268.2
|
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Acquisition of Wind Generation Facilities in Illinois
In December 2020, WECI completed the acquisition of a 90% ownership interest in Blooming Grove, a commercially operational 250 MW wind generating facility in McLean County, Illinois, for a total investment of $364.6 million, which includes transaction costs and is net of restricted cash acquired of $24.1 million. Blooming Grove has offtake agreements for all the energy produced with affiliates of two investment grade multinational companies for 12 years. Under the Tax Legislation, WECI's investment in Blooming Grove qualifies for PTCs. Blooming Grove is included in the non-utility energy infrastructure segment.
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.
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|
|
|
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(in millions)
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|
Net property, plant, and equipment
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$
|
471.6
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|
Long-term liabilities
|
|
(64.0)
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Noncontrolling interest
|
|
(43.0)
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|
Total purchase price
|
|
$
|
364.6
|
|
In August 2018, WECI completed the acquisition of an 80% ownership interest in Bishop Hill III, a commercially operational 132.1 MW wind generating facility located in Henry County, Illinois, for $144.7 million, which includes transaction costs and is net of restricted cash acquired of $4.5 million. In December 2018, WECI completed the acquisition of an additional 10% ownership interest in Bishop Hill III for $18.2 million, for a total purchase price of $162.9 million. Bishop Hill III has an offtake agreement with an unaffiliated company for the sale of all of the energy produced by the facility for 22 years. Under the Tax Legislation, WECI's investment in Bishop Hill III qualifies for PTCs. Bishop Hill III is included in the non-utility energy infrastructure segment.
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|
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|
2020 Form 10-K
|
99
|
WEC Energy Group, Inc.
|
The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition.
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
Current assets
|
|
$
|
1.4
|
|
Net property, plant, and equipment
|
|
190.2
|
|
|
|
|
Current liabilities
|
|
(1.6)
|
|
Long-term liabilities
|
|
(8.3)
|
|
Noncontrolling interest
|
|
(18.8)
|
|
Total purchase price
|
|
$
|
162.9
|
|
Acquisition of a Wind Generation Facility in Wisconsin
In April 2018, WPS, along with two unaffiliated utilities, completed the purchase of Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 138 MW. The aggregate purchase price was $172.9 million of which WPS’s proportionate share was 44.6%, or $77.1 million. In addition, WPS incurred $1.9 million of transaction costs that were recorded as a regulatory asset. Since 2008 and up until the acquisition, WPS purchased 44.6% of the facility’s energy output under a PPA. This acquisition was accounted for as an asset acquisition.
The table below shows the allocation of the purchase price to the assets acquired at the date of the acquisition, which are included in rate base.
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
Current assets
|
|
$
|
0.2
|
|
Net property, plant, and equipment
|
|
76.9
|
|
Total purchase price
|
|
$
|
77.1
|
|
Under a joint ownership agreement with the two other utilities, WPS is entitled to its share of generating capability and output of the facility equal to its ownership interest. WPS is also paying its ownership share of additional capital expenditures and operating expenses. Forward Wind Energy Center is included in the Wisconsin segment. See Note 8, Jointly Owned Utility Facilities, for more information.
NOTE 3—DISPOSITIONS
Corporate and Other Segment
Sale of Certain WPS Power Development, LLC Solar Power Generation Facilities
In November 2020, we sold a portfolio of residential solar facilities owned by PDL for $10.5 million. These solar facilities were located in California and Hawaii. During the fourth quarter of 2020, we recorded an after-tax gain on the sale of $3.0 million primarily related to the recognition of deferred ITCs, which were included as a reduction of income tax expense on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of these facilities remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
In 2019, we sold four solar power generation facilities owned by PDL for $26.3 million. These solar facilities were located in Massachusetts. In 2019, we recorded an after-tax gain on the sales of $6.5 million primarily related to the recognition of deferred ITCs, which were included as a reduction of income tax expense on our income statements. The assets included in the sales were not material and, therefore, were not presented as held for sale. The results of operations of these facilities remained in continuing operations through the sale dates as the sales did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
100
|
WEC Energy Group, Inc.
|
NOTE 4—OPERATING REVENUES
For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues.
Disaggregation of Operating Revenues
The following tables present our operating revenues disaggregated by revenue source. We do not have any revenues associated with our electric transmission segment, which includes investments accounted for using the equity method. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenues and cash flows are affected by economic factors. For our segments, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and can be impacted differently by regulatory activities within their jurisdictions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Non-Utility Energy Infrastructure
|
|
Corporate
and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
Year ended December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
4,266.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,266.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,266.1
|
|
Natural gas
|
|
1,195.6
|
|
|
1,267.9
|
|
|
361.0
|
|
|
2,824.5
|
|
|
44.4
|
|
|
—
|
|
|
(42.0)
|
|
|
2,826.9
|
|
Total regulated revenues
|
|
5,461.7
|
|
|
1,267.9
|
|
|
361.0
|
|
|
7,090.6
|
|
|
44.4
|
|
|
—
|
|
|
(42.0)
|
|
|
7,093.0
|
|
Other non-utility revenues
|
|
—
|
|
|
—
|
|
|
17.1
|
|
|
17.1
|
|
|
66.6
|
|
|
1.7
|
|
|
(9.1)
|
|
|
76.3
|
|
Total revenues from contracts with customers
|
|
5,461.7
|
|
|
1,267.9
|
|
|
378.1
|
|
|
7,107.7
|
|
|
111.0
|
|
|
1.7
|
|
|
(51.1)
|
|
|
7,169.3
|
|
Other operating revenues
|
|
11.8
|
|
|
54.0
|
|
|
6.0
|
|
|
71.8
|
|
|
397.5
|
|
|
0.5
|
|
|
(397.4)
|
|
|
72.4
|
|
Total operating revenues
|
|
$
|
5,473.5
|
|
|
$
|
1,321.9
|
|
|
$
|
384.1
|
|
|
$
|
7,179.5
|
|
|
$
|
508.5
|
|
|
$
|
2.2
|
|
|
$
|
(448.5)
|
|
|
$
|
7,241.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Non-Utility Energy Infrastructure
|
|
Corporate
and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
Year ended December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
4,307.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,307.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,307.7
|
|
Natural gas
|
|
1,324.1
|
|
|
1,332.4
|
|
|
411.6
|
|
|
3,068.1
|
|
|
47.4
|
|
|
—
|
|
|
(44.1)
|
|
|
3,071.4
|
|
Total regulated revenues
|
|
5,631.8
|
|
|
1,332.4
|
|
|
411.6
|
|
|
7,375.8
|
|
|
47.4
|
|
|
—
|
|
|
(44.1)
|
|
|
7,379.1
|
|
Other non-utility revenues
|
|
—
|
|
|
0.1
|
|
|
16.6
|
|
|
16.7
|
|
|
55.2
|
|
|
4.0
|
|
|
(5.7)
|
|
|
70.2
|
|
Total revenues from contracts with customers
|
|
5,631.8
|
|
|
1,332.5
|
|
|
428.2
|
|
|
7,392.5
|
|
|
102.6
|
|
|
4.0
|
|
|
(49.8)
|
|
|
7,449.3
|
|
Other operating revenues
|
|
15.3
|
|
|
24.6
|
|
|
(2.2)
|
|
|
37.7
|
|
|
393.3
|
|
|
0.4
|
|
|
(357.6)
|
|
|
73.8
|
|
Total operating revenues
|
|
$
|
5,647.1
|
|
|
$
|
1,357.1
|
|
|
$
|
426.0
|
|
|
$
|
7,430.2
|
|
|
$
|
495.9
|
|
|
$
|
4.4
|
|
|
$
|
(407.4)
|
|
|
$
|
7,523.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Non-Utility Energy Infrastructure
|
|
Corporate
and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
Year ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
4,432.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,432.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,432.4
|
|
Natural gas
|
|
1,350.6
|
|
|
1,406.9
|
|
|
428.4
|
|
|
3,185.9
|
|
|
45.4
|
|
|
—
|
|
|
(36.4)
|
|
|
3,194.9
|
|
Total regulated revenues
|
|
5,783.0
|
|
|
1,406.9
|
|
|
428.4
|
|
|
7,618.3
|
|
|
45.4
|
|
|
—
|
|
|
(36.4)
|
|
|
7,627.3
|
|
Other non-utility revenues
|
|
—
|
|
|
0.2
|
|
|
16.1
|
|
|
16.3
|
|
|
34.6
|
|
|
7.9
|
|
|
(5.8)
|
|
|
53.0
|
|
Total revenues from contracts with customers
|
|
5,783.0
|
|
|
1,407.1
|
|
|
444.5
|
|
|
7,634.6
|
|
|
80.0
|
|
|
7.9
|
|
|
(42.2)
|
|
|
7,680.3
|
|
Other operating revenues
|
|
11.7
|
|
|
(7.1)
|
|
|
(6.3)
|
|
|
(1.7)
|
|
|
388.4
|
|
|
0.8
|
|
|
(388.3)
|
|
|
(0.8)
|
|
Total operating revenues
|
|
$
|
5,794.7
|
|
|
$
|
1,400.0
|
|
|
$
|
438.2
|
|
|
$
|
7,632.9
|
|
|
$
|
468.4
|
|
|
$
|
8.7
|
|
|
$
|
(430.5)
|
|
|
$
|
7,679.5
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
101
|
WEC Energy Group, Inc.
|
Revenues from Contracts with Customers
Electric Utility Operating Revenues
The following table disaggregates electric utility operating revenues into customer class:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Utility Operating Revenues
|
|
|
Year Ended December 31
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Residential
|
|
$
|
1,743.9
|
|
|
$
|
1,608.6
|
|
|
$
|
1,636.3
|
|
Small commercial and industrial
|
|
1,325.9
|
|
|
1,384.6
|
|
|
1,408.6
|
|
Large commercial and industrial
|
|
821.5
|
|
|
871.9
|
|
|
912.2
|
|
Other
|
|
29.0
|
|
|
29.6
|
|
|
29.9
|
|
Total retail revenues
|
|
3,920.3
|
|
|
3,894.7
|
|
|
3,987.0
|
|
Wholesale
|
|
174.0
|
|
|
189.5
|
|
|
210.1
|
|
Resale
|
|
130.4
|
|
|
163.1
|
|
|
192.2
|
|
Steam
|
|
21.3
|
|
|
23.3
|
|
|
24.1
|
|
Other utility revenues
|
|
20.1
|
|
|
37.1
|
|
|
19.0
|
|
Total electric utility operating revenues
|
|
$
|
4,266.1
|
|
|
$
|
4,307.7
|
|
|
$
|
4,432.4
|
|
Natural Gas Utility Operating Revenues
The following tables disaggregate natural gas utility operating revenues into customer class:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Natural Gas Utility Operating Revenues
|
Year ended December 31, 2020
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
752.6
|
|
|
$
|
802.2
|
|
|
$
|
220.8
|
|
|
$
|
1,775.6
|
|
Commercial and industrial
|
|
338.1
|
|
|
221.0
|
|
|
115.8
|
|
|
674.9
|
|
Total retail revenues
|
|
1,090.7
|
|
|
1,023.2
|
|
|
336.6
|
|
|
2,450.5
|
|
Transport
|
|
79.1
|
|
|
215.6
|
|
|
31.5
|
|
|
326.2
|
|
Other utility revenues (1)
|
|
25.8
|
|
|
29.1
|
|
|
(7.1)
|
|
|
47.8
|
|
Total natural gas utility operating revenues
|
|
$
|
1,195.6
|
|
|
$
|
1,267.9
|
|
|
$
|
361.0
|
|
|
$
|
2,824.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Natural Gas Utility Operating Revenues
|
Year ended December 31, 2019
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
837.9
|
|
|
$
|
857.8
|
|
|
$
|
258.2
|
|
|
$
|
1,953.9
|
|
Commercial and industrial
|
|
419.9
|
|
|
261.7
|
|
|
148.7
|
|
|
830.3
|
|
Total retail revenues
|
|
1,257.8
|
|
|
1,119.5
|
|
|
406.9
|
|
|
2,784.2
|
|
Transport
|
|
72.6
|
|
|
245.3
|
|
|
31.6
|
|
|
349.5
|
|
Other utility revenues (1)
|
|
(6.3)
|
|
|
(32.4)
|
|
|
(26.9)
|
|
|
(65.6)
|
|
Total natural gas utility operating revenues
|
|
$
|
1,324.1
|
|
|
$
|
1,332.4
|
|
|
$
|
411.6
|
|
|
$
|
3,068.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Natural Gas Utility Operating Revenues
|
Year ended December 31, 2018
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
834.5
|
|
|
$
|
877.5
|
|
|
$
|
263.3
|
|
|
$
|
1,975.3
|
|
Commercial and industrial
|
|
436.7
|
|
|
266.9
|
|
|
140.0
|
|
|
843.6
|
|
Total retail revenues
|
|
1,271.2
|
|
|
1,144.4
|
|
|
403.3
|
|
|
2,818.9
|
|
Transport
|
|
70.8
|
|
|
244.1
|
|
|
31.8
|
|
|
346.7
|
|
Other utility revenues (1)
|
|
8.6
|
|
|
18.4
|
|
|
(6.7)
|
|
|
20.3
|
|
Total natural gas utility operating revenues
|
|
$
|
1,350.6
|
|
|
$
|
1,406.9
|
|
|
$
|
428.4
|
|
|
$
|
3,185.9
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
102
|
WEC Energy Group, Inc.
|
(1) Includes amounts collected from (refunded to) customers for purchased gas adjustment costs.
Other Natural Gas Operating Revenues
We have other natural gas operating revenues from Bluewater, which is in our non-utility energy infrastructure segment. Bluewater
has entered into long-term service agreements for natural gas storage services with WE, WPS, and WG, and also provides limited service to unaffiliated customers. All amounts associated with services from affiliates have been eliminated at the consolidated level.
Other Non-Utility Operating Revenues
Other non-utility operating revenues consist primarily of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Wind generation revenues
|
|
$
|
34.6
|
|
|
$
|
24.0
|
|
|
$
|
3.6
|
|
We Power revenues
|
|
22.9
|
|
|
25.4
|
|
|
25.3
|
|
Appliance service revenues
|
|
17.1
|
|
|
16.6
|
|
|
15.9
|
|
Distributed renewable solar project revenues
|
|
1.4
|
|
|
4.0
|
|
|
8.0
|
|
Other
|
|
0.3
|
|
|
0.2
|
|
|
0.2
|
|
Total other non-utility operating revenues
|
|
$
|
76.3
|
|
|
$
|
70.2
|
|
|
$
|
53.0
|
|
Other Operating Revenues
Other operating revenues consist primarily of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Alternative revenues (1)
|
|
$
|
38.8
|
|
|
$
|
(9.6)
|
|
|
$
|
(45.6)
|
|
Late payment charges (2)
|
|
29.4
|
|
|
43.7
|
|
|
40.3
|
|
Other
|
|
4.2
|
|
|
39.7
|
|
|
4.5
|
|
Total other operating revenues
|
|
$
|
72.4
|
|
|
$
|
73.8
|
|
|
$
|
(0.8)
|
|
(1) Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to decoupling mechanisms, wholesale true-ups, conservation improvement rider true-ups, and certain late payment charges, as discussed in Note 1(d), Operating Revenues.
(2) The reduction in late payment charges is a result of various regulatory orders from our utility commissions in response to the COVID-19 pandemic, which include the suspension of late payment charges during a designated time period. PGL and NSG were authorized to implement a SPC rider for the recovery of these late payment charges related to COVID-19, thereby allowing them to record these late payment charges as alternative revenues. The total amount of late payment charges recorded as alternative revenues during the year ended December 31, 2020 was $8.5 million. See Note 26, Regulatory Environment, for more information.
NOTE 5—CREDIT LOSSES
The table below shows our gross third-party receivable balances and the related allowance for credit losses at December 31, 2020, by reportable segment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Non-Utility Energy Infrastructure
|
|
Corporate
and Other
|
|
WEC Energy Group Consolidated
|
Accounts receivable and unbilled revenues
|
|
$
|
899.8
|
|
|
$
|
393.9
|
|
|
$
|
79.8
|
|
|
$
|
1,373.5
|
|
|
$
|
45.0
|
|
|
$
|
4.4
|
|
|
$
|
1,422.9
|
|
Allowance for credit losses
|
|
102.1
|
|
|
111.6
|
|
|
6.4
|
|
|
220.1
|
|
|
—
|
|
|
—
|
|
|
220.1
|
|
Accounts receivable and unbilled revenues, net (1)
|
|
$
|
797.7
|
|
|
$
|
282.3
|
|
|
$
|
73.4
|
|
|
$
|
1,153.4
|
|
|
$
|
45.0
|
|
|
$
|
4.4
|
|
|
$
|
1,202.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total accounts receivable, net – past due greater than 90 days (1)
|
|
$
|
84.8
|
|
|
$
|
34.5
|
|
|
$
|
3.5
|
|
|
$
|
122.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
122.8
|
|
Past due greater than 90 days – collection risk mitigated by regulatory mechanisms (1)
|
|
97.6
|
%
|
|
100.0
|
%
|
|
—
|
%
|
|
95.5
|
%
|
|
—
|
%
|
|
—
|
%
|
|
95.5
|
%
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
103
|
WEC Energy Group, Inc.
|
(1)Our exposure to credit losses for certain regulated utility customers is mitigated by regulatory mechanisms we have in place. Specifically, rates related to all of the customers in our Illinois segment, as well as the residential rates of WE, WPS, and WG in our Wisconsin segment, include riders or other mechanisms for cost recovery or refund of uncollectible expense based on the difference between the actual provision for credit losses and the amounts recovered in rates. As a result, at December 31, 2020, $679.4 million, or 56.5%, of our net accounts receivable and unbilled revenues balance had regulatory protections in place to mitigate the exposure to credit losses. In addition, we have received specific orders related to the deferral of certain costs (including credit losses) incurred as a result of the COVID-19 pandemic. The additional protections related to our December 31, 2020 accounts receivable and unbilled revenue balances provided by these orders are subject to prudency reviews and are still being assessed. They are not reflected in the percentages in the above table or this note. See Note 26, Regulatory Environment, for more information on these orders.
A rollforward of the allowance for credit losses by reportable segment for the year ended December 31, 2020, is included below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Corporate
and Other
|
|
WEC Energy Group Consolidated
|
Balance at December 31, 2019
|
|
$
|
59.9
|
|
|
$
|
75.9
|
|
|
$
|
4.1
|
|
|
$
|
139.9
|
|
|
$
|
0.1
|
|
|
$
|
140.0
|
|
Provision for credit losses
|
|
47.5
|
|
|
51.1
|
|
|
4.3
|
|
|
102.9
|
|
|
—
|
|
|
102.9
|
|
Provision for credit losses deferred for future recovery or refund
|
|
24.6
|
|
|
30.6
|
|
|
—
|
|
|
55.2
|
|
|
—
|
|
|
55.2
|
|
Write-offs charged against the allowance
|
|
(65.9)
|
|
|
(63.0)
|
|
|
(3.4)
|
|
|
(132.3)
|
|
|
—
|
|
|
(132.3)
|
|
Recoveries of amounts previously written off
|
|
36.0
|
|
|
17.0
|
|
|
1.4
|
|
|
54.4
|
|
|
—
|
|
|
54.4
|
|
Sale of PDL residential solar facilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.1)
|
|
|
(0.1)
|
|
Balance at December 31, 2020
|
|
$
|
102.1
|
|
|
$
|
111.6
|
|
|
$
|
6.4
|
|
|
$
|
220.1
|
|
|
$
|
—
|
|
|
$
|
220.1
|
|
The increase in the allowance for credit losses at December 31, 2020, compared to December 31, 2019, was driven by higher past due accounts receivable balances at our utility segments, primarily related to residential customers. This increase in accounts receivable balances in arrears was driven by economic disruptions caused by the COVID-19 pandemic, including higher unemployment rates. Also, as a result of the COVID-19 pandemic and related regulatory orders we have received, we were unable to disconnect any of our Wisconsin and Illinois customers during the year ended December 31, 2020. See Note 26, Regulatory Environment, for more information.
NOTE 6—REGULATORY ASSETS AND LIABILITIES
The following regulatory assets were reflected on our balance sheets as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
See Note
|
Regulatory assets (1) (2)
|
|
|
|
|
|
|
Pension and OPEB costs (3)
|
|
$
|
1,101.6
|
|
|
$
|
1,066.6
|
|
|
20
|
Plant retirements
|
|
740.8
|
|
|
756.4
|
|
|
|
Environmental remediation costs (4)
|
|
638.2
|
|
|
685.5
|
|
|
24
|
Income tax related items
|
|
454.6
|
|
|
457.8
|
|
|
16
|
AROs
|
|
181.3
|
|
|
137.5
|
|
|
9
|
SSR (5)
|
|
135.6
|
|
|
151.5
|
|
|
26
|
Securitization
|
|
105.2
|
|
|
100.0
|
|
|
26
|
Uncollectible expense
|
|
82.0
|
|
|
52.2
|
|
|
5
|
Derivatives
|
|
26.5
|
|
|
33.8
|
|
|
1(s)
|
We Power generation (6)
|
|
7.6
|
|
|
25.8
|
|
|
|
Other, net
|
|
70.7
|
|
|
60.5
|
|
|
|
Total regulatory assets
|
|
$
|
3,544.1
|
|
|
$
|
3,527.6
|
|
|
|
|
|
|
|
|
|
|
Balance sheet presentation
|
|
|
|
|
|
|
Other current assets
|
|
$
|
20.0
|
|
|
$
|
20.9
|
|
|
|
Regulatory assets
|
|
3,524.1
|
|
|
3,506.7
|
|
|
|
Total regulatory assets
|
|
$
|
3,544.1
|
|
|
$
|
3,527.6
|
|
|
|
(1) Based on prior and current rate treatment, we believe it is probable that our utilities will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $34.2 million and $24.3 million at December 31, 2020 and 2019, respectively.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
104
|
WEC Energy Group, Inc.
|
(2) As of December 31, 2020, we had $238.8 million of regulatory assets not earning a return, $9.7 million of regulatory assets earning a return based on short-term interest rates, and $135.6 million of regulatory assets earning a return based on long-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, uncollectible expense, COVID-19 deferred costs, our invested capital tax rider, unamortized loss on reacquired debt, and our electric real-time market pricing program. The other regulatory assets in the table either earn a return at the applicable utility's weighted average cost of capital or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities.
(3) Primarily represents the unrecognized future pension and OPEB costs related to our defined benefit pension and OPEB plans. We are authorized recovery of these regulatory assets over the average remaining service life of each plan.
(4) As of December 31, 2020, we had made cash expenditures of $105.3 million related to these environmental remediation costs. The remaining $532.9 million represents our estimated future cash expenditures.
(5) The rate order WE received from the PSCW in December 2019 authorized recovery of the SSR regulatory asset over a 15-year period that began on January 1, 2020.
(6) Represents amounts recoverable from customers related to WE's costs of the generating units leased from We Power, including subsequent capital additions.
The following regulatory liabilities were reflected on our balance sheets as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
See Note
|
Regulatory liabilities
|
|
|
|
|
|
|
Income tax related items
|
|
$
|
2,137.7
|
|
|
$
|
2,248.8
|
|
|
16
|
Removal costs (1)
|
|
1,221.1
|
|
|
1,181.5
|
|
|
|
Pension and OPEB benefits (2)
|
|
378.1
|
|
|
354.9
|
|
|
20
|
Electric transmission costs (3) (4)
|
|
78.5
|
|
|
42.2
|
|
|
|
Energy costs refundable through rate adjustments
|
|
59.9
|
|
|
89.8
|
|
|
1(d)
|
Earnings sharing mechanisms (3)
|
|
36.9
|
|
|
43.5
|
|
|
26
|
Uncollectible expense
|
|
25.5
|
|
|
39.1
|
|
|
5
|
Derivatives
|
|
16.4
|
|
|
6.7
|
|
|
1(s)
|
Energy efficiency programs (5)
|
|
9.9
|
|
|
30.7
|
|
|
|
Decoupling
|
|
5.2
|
|
|
36.8
|
|
|
1(d)
|
Other, net
|
|
9.9
|
|
|
6.4
|
|
|
|
Total regulatory liabilities
|
|
$
|
3,979.1
|
|
|
$
|
4,080.4
|
|
|
|
|
|
|
|
|
|
|
Balance sheet presentation
|
|
|
|
|
|
|
Other current liabilities
|
|
$
|
51.0
|
|
|
$
|
87.6
|
|
|
|
Regulatory liabilities
|
|
3,928.1
|
|
|
3,992.8
|
|
|
|
Total regulatory liabilities
|
|
$
|
3,979.1
|
|
|
$
|
4,080.4
|
|
|
|
(1) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. See Note 9, Asset Retirement Obligations, for more information on our legal obligations.
(2) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan.
(3) Based on orders received from the PSCW, WE was required to apply the refunds due to customers from its earnings sharing mechanism to its electric transmission escrow during 2019. As a result, $38.6 million of WE's earnings sharing refunds were reflected in its electric transmission regulatory liability at December 31, 2019. WE had no refunds due to customers from its earnings sharing mechanism at December 31, 2020.
(4) In accordance with the PSCW's approval of escrow accounting for ATC and MISO network transmission expenses for our Wisconsin electric utilities, WE and WPS defer as a regulatory asset or liability the difference between actual transmission costs and those included in rates until recovery or refund is authorized in a future rate proceeding.
(5) Represents amounts refundable to customers related to programs at the utilities designed to meet energy efficiency standards.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
105
|
WEC Energy Group, Inc.
|
Pleasant Prairie Power Plant
The Pleasant Prairie power plant was retired on April 10, 2018. The net book value of this plant was $602.7 million at December 31, 2020, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of this plant were $19.6 million. The net amount of $583.1 million was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $168.7 million related to the retired Pleasant Prairie power plant. Pursuant to its rate order issued by the PSCW in December 2019, WE will continue to amortize this regulatory asset on a straight-line basis through 2039, using the composite depreciation rates approved by the PSCW before this plant was retired. Amortization is included in depreciation and amortization in the income statement. WE has FERC approval to continue to collect the net book value of the Pleasant Prairie power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. Collection of the return of and on the net book value is no longer subject to refund as the FERC completed its prudency review and concluded that the retirement of this plant was prudent. WE received approval from the PSCW in December 2019 to collect a full return of the net book value of the Pleasant Prairie power plant, and a return on all but $100 million of the net book value. In accordance with its PSCW rate order received in December 2019, WE filed an application with the PSCW on July 20, 2020 requesting a financing order to securitize the remaining $100 million of the Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related fees. On November 17, 2020, the PSCW issued a written order approving this application.
Presque Isle Power Plant
Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The net book value of the PIPP was $161.0 million at December 31, 2020, representing book value less cost of removal and accumulated depreciation. In addition, previously deferred unprotected tax benefits from the Tax Legislation related to the unrecovered balance of these units were $6.0 million. The net amount of $155.0 million was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. This regulatory asset does not include certain other previously recorded deferred tax liabilities of $46.0 million related to the retired PIPP. After the retirement of the PIPP, a portion of the regulatory asset and related cost of removal reserve was transferred to UMERC for recovery from its retail customers. Effective with its rate order issued by the PSCW in December 2019, WE received approval to collect a return of and on its share of the net book value of the PIPP, and as a result, will continue to amortize the regulatory assets on a straight-line basis through 2037, using the composite depreciation rates approved by the PSCW before the units were retired. UMERC will also continue to amortize the regulatory assets on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired. Amortization is included in depreciation and amortization in the income statement. UMERC will address the accounting and regulatory treatment related to the retirement of the PIPP with the MPSC in conjunction with a future rate case. WE has FERC approval to continue to collect the net book value of the PIPP using the approved composite depreciation rates, in addition to a return on the net book value. However, this approval is subject to refund pending the outcome of settlement proceedings.
Pulliam Power Plant
In connection with a MISO ruling, WPS retired Pulliam Units 7 and 8 on October 21, 2018. The net book value of the Pulliam units was $42.6 million at December 31, 2020, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Pulliam units, and as a result, will continue to amortize this regulatory asset on a straight-line basis through 2031, using the composite depreciation rates approved by the PSCW before these generating units were retired. Amortization is included in depreciation and amortization in the income statement. WPS has FERC approval to continue to collect the net book value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining net book value. FERC has completed its prudency review of Pulliam, concluding that the retirement of this plant was prudent.
Edgewater Unit 4
The Edgewater 4 generating unit was retired on September 28, 2018. The net book value of the generating unit was $4.7 million at December 31, 2020, representing book value less cost of removal and accumulated depreciation. This amount was classified as a regulatory asset on our balance sheets as a result of the retirement of the plant. Effective with its rate order issued by the PSCW in December 2019, WPS received approval to collect a return of and on the entire net book value of the Edgewater 4 generating unit, and as a result, will continue to amortize this regulatory asset on a straight-line basis through 2026, using the composite
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
106
|
WEC Energy Group, Inc.
|
depreciation rates approved by the PSCW before this generating unit was retired. Amortization is included in depreciation and amortization in the income statement. WPS has FERC approval to continue to collect the net book value of the Edgewater 4 generating unit using the approved composite depreciation rates, in addition to a return on the remaining net book value. FERC has completed its prudency review of Edgewater 4, concluding that the retirement of this plant was prudent.
Severance Liability for Plant Retirements
In December 2017, a severance liability of $29.4 million was recorded in other current liabilities on our balance sheets related to these plant retirements. Activity related to this severance liability for the years ended December 31 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Severance liability at January 1
|
|
$
|
2.1
|
|
|
$
|
15.7
|
|
|
$
|
29.4
|
|
Severance payments
|
|
(0.1)
|
|
|
(7.2)
|
|
|
(10.7)
|
|
Other
|
|
(1.3)
|
|
|
(6.4)
|
|
|
(3.0)
|
|
Total severance liability at December 31
|
|
$
|
0.7
|
|
|
$
|
2.1
|
|
|
$
|
15.7
|
|
NOTE 7—PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
Electric – generation
|
|
$
|
7,015.3
|
|
|
$
|
6,858.8
|
|
Electric – distribution
|
|
7,455.5
|
|
|
7,018.1
|
|
Natural gas – distribution, storage, and transmission
|
|
12,730.0
|
|
|
11,602.7
|
|
|
|
|
|
|
Other
|
|
1,896.1
|
|
|
1,696.7
|
|
Less: Accumulated depreciation
|
|
8,465.0
|
|
|
8,073.7
|
|
Net
|
|
20,631.9
|
|
|
19,102.6
|
|
CWIP
|
|
683.9
|
|
|
820.4
|
|
Net utility and non-utility property, plant, and equipment
|
|
21,315.8
|
|
|
19,923.0
|
|
|
|
|
|
|
We Power generation
|
|
3,238.8
|
|
|
3,245.7
|
|
Renewable generation
|
|
1,213.3
|
|
|
716.5
|
|
Natural gas storage
|
|
250.0
|
|
|
245.9
|
|
Net non-utility energy infrastructure
|
|
4,702.1
|
|
|
4,208.1
|
|
Corporate services
|
|
212.3
|
|
|
180.4
|
|
Other
|
|
41.8
|
|
|
88.8
|
|
Less: Accumulated depreciation
|
|
899.7
|
|
|
805.0
|
|
Net
|
|
4,056.5
|
|
|
3,672.3
|
|
CWIP
|
|
335.1
|
|
|
24.8
|
|
Net other property, plant, and equipment
|
|
4,391.6
|
|
|
3,697.1
|
|
|
|
|
|
|
Total property, plant, and equipment
|
|
$
|
25,707.4
|
|
|
$
|
23,620.1
|
|
Public Service Building
During a significant rain event in May 2020, an underground steam tunnel in downtown Milwaukee flooded and steam vented into WE’s Public Service Building. The damage to the building from the flooding and steam was extensive and will require significant repairs and restorations. As of December 31, 2020, WE had incurred $35.2 million of costs related to these repairs and restorations. WE received $20.0 million of insurance proceeds to cover a portion of these costs and $2.7 million was recorded as a receivable for future insurance recoveries. The remaining $12.5 million of costs were included in other operation and maintenance expense. We anticipate that the majority of future capital expenditures required to restore the Public Service Building will either be covered by insurance or recovery will be requested from the PSCW. As such, we do not currently expect a significant impact to our future results of operations, and although we may experience differences between periods in the timing of cash flows, we also do not currently expect a significant impact to our long-term cash flows from this event.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
107
|
WEC Energy Group, Inc.
|
NOTE 8—JOINTLY OWNED UTILITY FACILITIES
We Power and WPS hold joint ownership interests in certain electric generating facilities. They are entitled to their share of generating capability and output of each facility equal to their respective ownership interest. They pay their ownership share of additional construction costs and have supplied their own financing for all jointly owned projects. We record We Power's and WPS's proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets.
We Power leases its ownership interest in ER 1 and ER 2 to WE, and WE operates these units. WE and WPS record their respective share of fuel inventory purchases and operating expenses, unless specific agreements have been executed to limit their maximum exposure to additional costs. WE's and WPS's proportionate share of direct expenses for the joint operation of these plants is recorded within operating expenses in the income statements.
Information related to jointly owned utility facilities at December 31, 2020 was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We Power
|
|
WPS
|
(in millions, except for percentages and MW)
|
|
Elm Road Generating Station Units 1 and 2
|
|
Weston Unit 4
|
|
Columbia Energy Center Units 1
and 2
|
|
Forward Wind Energy Center
|
|
Two Creeks (2)
|
Ownership
|
|
83.34
|
%
|
|
70.0
|
%
|
|
27.5
|
%
|
|
44.6
|
%
|
|
66.7
|
%
|
Share of capacity (MW) (1)
|
|
1,059.4
|
|
|
385.0
|
|
|
311.1
|
|
|
61.5
|
|
|
100.0
|
|
In-service date
|
|
2010 and 2011
|
|
2008
|
|
1975 and 1978
|
|
2008
|
|
2020
|
Property, plant, and equipment
|
|
$
|
2,436.5
|
|
|
$
|
613.5
|
|
|
$
|
422.3
|
|
|
$
|
118.9
|
|
|
$
|
136.0
|
|
Accumulated depreciation
|
|
$
|
(447.2)
|
|
|
$
|
(218.6)
|
|
|
$
|
(145.5)
|
|
|
$
|
(49.6)
|
|
|
$
|
(0.7)
|
|
CWIP
|
|
$
|
2.2
|
|
|
$
|
3.8
|
|
|
$
|
2.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1) Capacity for our jointly-owned electric generation facilities, other than Forward Wind Energy Center and Two Creeks, is based on rated capacity, which is the net power output under average operating conditions with equipment in an average state of repair as of a given month in a given year. Values are primarily based on the net dependable expected capacity ratings for summer 2021 established by tests and may change slightly from year to year. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Capacity for Forward Wind Energy Center is based on nameplate capacity, which is the amount of energy a turbine should produce at optimal wind speeds. Capacity for Two Creeks is based on nameplate capacity, which is the maximum output that a generator should produce at continuous full power.
(2) Commercial operation was achieved in November 2020 for Two Creeks.
WPS has partnered with an unaffiliated utility to construct a solar project, Badger Hollow I, that will be located in Iowa County, Wisconsin. Once constructed, WPS will own 66.7%, or 100 MW, of Badger Hollow I. Commercial operation is targeted for the second quarter of 2021. WE has partnered with an unaffiliated utility to construct a solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 66.7%, or 100 MW, of Badger Hollow II. Commercial operation is targeted for December 2022. The CWIP balances for Badger Hollow I and Badger Hollow II as of December 31, 2020 were $115.3 million and $10.8 million, respectively.
NOTE 9—ASSET RETIREMENT OBLIGATIONS
Our utilities have recorded AROs primarily for the removal of natural gas distribution mains and service pipes (including asbestos and PCBs); asbestos abatement at certain generation and substation facilities, office buildings, and service centers; the removal and dismantlement of biomass and hydro generation facilities; the dismantling of wind generation projects; the dismantling of solar generation projects; the disposal of PCB-contaminated transformers; the closure of coal combustion residual landfills at certain generation facilities; and the removal of above ground storage tanks. Regulatory assets and liabilities are established by our utilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the applicable regulators.
WECI has also recorded AROs for the dismantling of our non-utility wind generation projects.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
108
|
WEC Energy Group, Inc.
|
On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Balance as of January 1
|
|
$
|
483.5
|
|
|
$
|
461.4
|
|
|
$
|
573.7
|
|
|
Accretion
|
|
20.7
|
|
|
22.1
|
|
|
28.0
|
|
|
Additions and revisions to estimated cash flows
|
|
39.7
|
|
(1)
|
39.1
|
|
(2)
|
(104.5)
|
|
(3)
|
Liabilities settled
|
|
(30.4)
|
|
|
(39.1)
|
|
|
(35.8)
|
|
|
Balance as of December 31
|
|
$
|
513.5
|
|
|
$
|
483.5
|
|
|
$
|
461.4
|
|
|
(1) AROs increased $39.3 million in 2020, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2020, AROs increased by $8.5 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, the Two Creeks solar generation project. AROs decreased $9.2 million due to revisions made to estimated cash flows for the abatement of asbestos at WE.
(2) AROs increased $40.1 million in 2019, primarily due to new natural gas distribution lines being placed into service at PGL. Also in 2019, AROs increased $10.7 million as a result of AROs being recorded for the legal requirement to dismantle, at retirement, certain non-utility wind generation projects. AROs decreased $7.3 million due to revisions made to estimated cash flows for the abatement of asbestos at WE.
(3) AROs decreased $127.3 million in 2018 due to revisions made to estimated cash flows primarily for changes in the cost to retire natural gas distribution pipe at PGL. Also in 2018, AROs increased $10.7 million as a result of revisions made to estimated cash flows for the abatement of asbestos at WPS's Pulliam power plant, and a $10.9 million ARO was recorded for the legal requirement to dismantle, at retirement, certain wind generation projects.
NOTE 10—GOODWILL AND INTANGIBLES
Goodwill
Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The table below shows our goodwill balances by segment at December 31, 2020. We had no changes to the carrying amount of goodwill during the years ended December 31, 2020 and 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Non-Utility Energy Infrastructure
|
|
Total
|
Goodwill balance (1)
|
|
$
|
2,104.3
|
|
|
$
|
758.7
|
|
|
$
|
183.2
|
|
|
$
|
6.6
|
|
|
$
|
3,052.8
|
|
(1) We had no accumulated impairment losses related to our goodwill as of December 31, 2020.
In the third quarter of 2020, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2020. No impairments resulted from these tests.
Intangible Assets
At December 31, 2020, we had $5.7 million of indefinite-lived intangible assets primarily related to a MGU trade name obtained through an acquisition, which is included in other long-term assets on our balance sheets. We had no changes to the carrying amount of these intangible assets during the years ended December 31, 2020 and 2019.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
109
|
WEC Energy Group, Inc.
|
Intangible Liabilities
The intangible liabilities below were all obtained through acquisitions by WECI and are classified as other long-term liabilities on our balance sheets. See Note 2, Acquisitions, for more information.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
(in millions)
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
|
Gross Carrying Amount
|
|
Accumulated Amortization
|
|
Net Carrying Amount
|
PPAs (1)
|
|
$
|
76.1
|
|
|
$
|
—
|
|
|
$
|
76.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Proxy revenue swap (2)
|
|
7.2
|
|
|
(1.3)
|
|
|
5.9
|
|
|
7.2
|
|
|
(0.6)
|
|
|
6.6
|
|
Interconnection agreements (3)
|
|
5.1
|
|
|
(0.3)
|
|
|
4.8
|
|
|
3.0
|
|
|
(0.2)
|
|
|
2.8
|
|
Total intangible liabilities
|
|
$
|
88.4
|
|
|
$
|
(1.6)
|
|
|
$
|
86.8
|
|
|
$
|
10.2
|
|
|
$
|
(0.8)
|
|
|
$
|
9.4
|
|
(1) Represents PPAs related to the acquisition of Blooming Grove and Tatanka Ridge expiring between 2030 and 2032. The weighted-average remaining useful life of the PPAs is 12 years.
(2) Represents an agreement with a counterparty to swap the market revenue of Upstream's wind generation for fixed quarterly payments over 10 years, which expires in 2029. The remaining useful life of the proxy revenue swap is eight years.
(3) Represents interconnection agreements related to the acquisitions of Tatanka Ridge and Bishop Hill III, expiring in 2040 and 2041, respectively. These agreements relate to payments for connecting our facilities to the infrastructure of another utility to facilitate the movement of power onto the electric grid. The weighted-average remaining useful life of the interconnection agreements is 20 years.
Amortization related to these intangibles for the years ended December 31, 2020, 2019, and 2018 was not significant. Amortization for the next five years is estimated to be:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ending December 31
|
(in millions)
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
2025
|
Amortization to be recorded in operating revenues
|
|
$
|
7.2
|
|
|
$
|
7.2
|
|
|
$
|
7.2
|
|
|
$
|
7.2
|
|
|
$
|
7.2
|
|
Amortization to be recorded in other operation and maintenance
|
|
0.2
|
|
|
0.2
|
|
|
0.2
|
|
|
0.2
|
|
|
0.2
|
|
NOTE 11—COMMON EQUITY
Stock-Based Compensation Plans
The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Stock options
|
|
$
|
6.0
|
|
|
$
|
4.4
|
|
|
$
|
5.2
|
|
Restricted stock
|
|
7.4
|
|
|
7.1
|
|
|
10.7
|
|
Performance units
|
|
22.3
|
|
|
38.7
|
|
|
20.2
|
|
Stock-based compensation expense
|
|
$
|
35.7
|
|
|
$
|
50.2
|
|
|
$
|
36.1
|
|
Related tax benefit
|
|
$
|
9.8
|
|
|
$
|
13.8
|
|
|
$
|
9.9
|
|
Stock-based compensation costs capitalized during 2020, 2019, and 2018 were not significant.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
110
|
WEC Energy Group, Inc.
|
Stock Options
The following is a summary of our stock option activity during 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock Options
|
|
Number of Options
|
|
Weighted-Average Exercise Price
|
|
Weighted-Average Remaining Contractual Life
(in years)
|
|
Aggregate Intrinsic Value (in millions)
|
Outstanding as of January 1, 2020
|
|
3,249,918
|
|
|
$
|
54.98
|
|
|
|
|
|
Granted
|
|
554,594
|
|
|
$
|
91.51
|
|
|
|
|
|
Exercised
|
|
(910,083)
|
|
|
$
|
48.10
|
|
|
|
|
|
Forfeited
|
|
(6,969)
|
|
|
$
|
71.08
|
|
|
|
|
|
Outstanding as of December 31, 2020
|
|
2,887,460
|
|
|
$
|
64.13
|
|
|
6.4
|
|
$
|
80.6
|
|
Exercisable as of December 31, 2020
|
|
1,461,537
|
|
|
$
|
53.17
|
|
|
4.8
|
|
$
|
56.8
|
|
The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2020. This is calculated as the difference between our closing stock price on December 31, 2020, and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2020, 2019, and 2018 was $47.1 million, $62.4 million, and $32.4 million, respectively. The actual tax benefit from option exercises for the same periods was approximately $12.9 million, $17.1 million, and $8.9 million, respectively.
As of December 31, 2020, approximately $2.2 million of unrecognized compensation cost related to unvested and outstanding stock options was expected to be recognized over the next 1.8 years on a weighted-average basis.
During the first quarter of 2021, the Compensation Committee awarded 530,612 non-qualified stock options with a weighted-average exercise price of $91.06 and a weighted-average grant date fair value of $13.20 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.
Restricted Shares
The following restricted stock activity occurred during 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Shares
|
|
Number of Shares
|
|
Weighted-Average Grant Date Fair Value
|
Outstanding and unvested as of January 1, 2020
|
|
134,109
|
|
|
$
|
66.48
|
|
Granted
|
|
91,873
|
|
|
$
|
91.54
|
|
Released
|
|
(122,043)
|
|
|
$
|
71.25
|
|
Forfeited
|
|
(2,852)
|
|
|
$
|
74.31
|
|
Outstanding and unvested as of December 31, 2020
|
|
101,087
|
|
|
$
|
83.28
|
|
The intrinsic value of restricted stock released was $11.1 million, $13.4 million, and $7.9 million for the years ended December 31, 2020, 2019, and 2018, respectively. The actual tax benefit from released restricted shares for the same years was $3.1 million, $3.7 million, and $2.2 million, respectively.
As of December 31, 2020, approximately $3.1 million of unrecognized compensation cost related to unvested and outstanding restricted stock was expected to be recognized over the next 1.8 years on a weighted-average basis.
During the first quarter of 2021, the Compensation Committee awarded 69,681 restricted shares to certain of our directors, officers, and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $91.06 per share.
Performance Units
During 2020, 2019, and 2018, the Compensation Committee awarded 153,465; 148,036; and 217,560 performance units, respectively, to officers and other key employees under the WEC Energy Group Performance Unit Plan.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
111
|
WEC Energy Group, Inc.
|
Performance units with an intrinsic value of $34.5 million, $18.7 million, and $9.7 million were settled during 2020, 2019, and 2018, respectively. The actual tax benefit from the distribution of performance units for the same years was $8.4 million, $4.4 million, and $2.2 million, respectively.
At December 31, 2020, we had 483,842 performance units outstanding, including dividend equivalents. A liability of $45.9 million was recorded on our balance sheet at December 31, 2020 related to these outstanding units. As of December 31, 2020, approximately $16.7 million of unrecognized compensation cost related to unvested and outstanding performance units was expected to be recognized over the next 1.6 years on a weighted-average basis.
During the first quarter of 2021, we settled performance units with an intrinsic value of $27.4 million. The actual tax benefit from the distribution of these awards was $6.7 million. In January 2021, the Compensation Committee also awarded 152,382 performance units to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation.
Restrictions
Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries, We Power, Bluewater Gas Storage, ATC Holding, and WECI. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of UMERC and MGU, are prohibited from loaning funds to us, either directly or indirectly.
In accordance with their most recent rate orders, WE, WPS, and WG may not pay common dividends above the test year forecasted amounts reflected in their respective rate cases, if it would cause their average common equity ratio, on a financial basis, to fall below their authorized level of 52.5%. A return of capital in excess of the test year amount can be paid by each company at the end of the year provided that their respective average common equity ratios do not fall below the authorized level.
WE may not pay common dividends to us under WE's Restated Articles of Incorporation if any dividends on its outstanding preferred stock have not been paid. In addition, pursuant to the terms of WE's 3.60% Serial Preferred Stock, WE's ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if its common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20%, respectively.
NSG's long-term debt obligations contain provisions and covenants restricting the payment of cash dividends and the purchase or redemption of its capital stock.
The long-term debt obligations of UMERC, Bluewater Gas Storage, and ATC Holding contain a provision requiring them to maintain a total funded debt to capitalization ratio of 65% or less.
WECI Wind Holding I's long-term debt obligations contain various conditions that must be met prior to WECI Wind Holding I making any cash distributions. Included in these provisions is a requirement to maintain a debt service coverage ratio of 1.2 or greater for the 12-month period prior to the distribution.
WEC Energy Group and Integrys have the option to defer interest payments on their junior subordinated notes, from time to time, for one or more periods of up to 10 consecutive years per period. During any period in which they defer interest payments, they may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, their respective common stock.
See Note 13, Short-Term Debt and Lines of Credit, for discussion of certain financial covenants related to short-term debt obligations.
As of December 31, 2020, restricted net assets of our consolidated subsidiaries totaled approximately $8.6 billion. Our equity in undistributed earnings of investees accounted for by the equity method was approximately $386 million.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
112
|
WEC Energy Group, Inc.
|
Share Purchases
We have instructed our independent agents to purchase shares on the open market to fulfill obligations under various stock-based employee benefit and compensations plans and to provide shares to participants in our dividend reinvestment and stock purchase plan. As a result, no new shares of common stock were issued in 2020, 2019, or 2018.
The following is a summary of shares purchased to fulfill exercised stock options and restricted stock awards during the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Shares purchased
|
|
1.0
|
|
|
1.8
|
|
|
1.1
|
|
Cost of shares purchased
|
|
$
|
99.2
|
|
|
$
|
140.1
|
|
|
$
|
72.4
|
|
Common Stock Dividends
During the year ended December 31, 2020, our Board of Directors declared common stock dividends which are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Date Declared
|
|
Date Payable
|
|
Per Share
|
|
Period
|
January 16, 2020
|
|
March 1, 2020
|
|
$0.6325
|
|
First quarter
|
April 16, 2020
|
|
June 1, 2020
|
|
$0.6325
|
|
Second quarter
|
July 16, 2020
|
|
September 1, 2020
|
|
$0.6325
|
|
Third quarter
|
October 15, 2020
|
|
December 1, 2020
|
|
$0.6325
|
|
Fourth quarter
|
On January 21, 2021, our Board of Directors declared a quarterly cash dividend of $0.6775 per share, which equates to an annual dividend of $2.71 per share. The dividend is payable on March 1, 2021, to shareholders of record on February 14, 2021. In addition, the Board of Directors affirmed our dividend policy that continues to target a dividend payout ratio of 65-70% of earnings.
NOTE 12—PREFERRED STOCK
The following table shows preferred stock authorized and outstanding at December 31, 2020 and 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions, except share and per share amounts)
|
|
Shares Authorized
|
|
Shares Outstanding
|
|
Redemption Price Per Share
|
|
Total
|
WEC Energy Group
|
|
|
|
|
|
|
|
|
$0.01 par value Preferred Stock
|
|
15,000,000
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
WE
|
|
|
|
|
|
|
|
|
$100 par value, Six Per Cent. Preferred Stock
|
|
45,000
|
|
|
44,498
|
|
|
—
|
|
|
4.4
|
|
$100 par value, Serial Preferred Stock 3.60% Series
|
|
2,286,500
|
|
|
260,000
|
|
|
$
|
101
|
|
|
26.0
|
|
$25 par value, Serial Preferred Stock
|
|
5,000,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
WPS
|
|
|
|
|
|
|
|
|
$100 par value, Preferred Stock
|
|
1,000,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
PGL
|
|
|
|
|
|
|
|
|
$100 par value, Cumulative Preferred Stock
|
|
430,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
NSG
|
|
|
|
|
|
|
|
|
$100 par value, Cumulative Preferred Stock
|
|
160,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
|
|
|
|
|
|
$
|
30.4
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
113
|
WEC Energy Group, Inc.
|
NOTE 13—SHORT-TERM DEBT AND LINES OF CREDIT
The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions, except percentages)
|
|
2020
|
|
2019
|
Commercial paper
|
|
|
|
|
Amount outstanding at December 31
|
|
$
|
1,436.9
|
|
|
$
|
830.8
|
|
Average interest rate on amounts outstanding at December 31
|
|
0.21
|
%
|
|
2.00
|
%
|
Term loan
|
|
|
|
|
Amount outstanding at December 31
|
|
$
|
340.0
|
|
|
$
|
—
|
|
Average interest rate on amounts outstanding at December 31
|
|
0.99
|
%
|
|
—
|
%
|
Our average amount of commercial paper borrowings based on daily outstanding balances during 2020, was $788.9 million with a weighted-average interest rate during the period of 0.85%.
In order to enhance our liquidity position in response to the COVID-19 pandemic, in March 2020, WEC Energy Group entered into a $340.0 million 364-day term loan that will mature on March 29, 2021. The proceeds from this term loan were used to pay down commercial paper. The weighted-average interest rate on the term loan during the year ended December 31, 2020 was 1.38%.
WEC Energy Group, WE, WPS, WG, and PGL have entered into bank back-up credit facilities to maintain short-term credit liquidity which, among other terms, require them to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 70.0%, 65.0%, 65.0%, 65.0%, and 65.0% or less, respectively. As of December 31, 2020, all companies were in compliance with their respective ratio.
The information in the table below relates to our term loan agreement and our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these credit agreements as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Maturity
|
|
2020
|
Term loan agreement (WEC Energy Group)
|
|
March 2021
|
|
$
|
340.0
|
|
Revolving credit facility (WEC Energy Group)
|
|
October 2022
|
|
1,200.0
|
|
Revolving credit facility (WE)
|
|
October 2022
|
|
500.0
|
|
Revolving credit facility (WPS)
|
|
October 2022
|
|
400.0
|
|
Revolving credit facility (WG)
|
|
October 2022
|
|
350.0
|
|
Revolving credit facility (PGL)
|
|
October 2022
|
|
350.0
|
|
Total short-term credit capacity
|
|
|
|
$
|
3,140.0
|
|
|
|
|
|
|
Less:
|
|
|
|
|
Letters of credit issued inside credit facilities
|
|
|
|
$
|
2.3
|
|
Term loan outstanding
|
|
|
|
340.0
|
|
Commercial paper outstanding
|
|
|
|
1,436.9
|
|
Available capacity under existing agreements
|
|
|
|
$
|
1,360.8
|
|
Each of the revolving credit facilities has a renewal provision for two extensions, subject to lender approval. Each extension is for a period of one year.
The bank back-up credit facilities contain customary covenants, including certain limitations on the respective companies' ability to sell assets. The credit facilities also contain customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults, and change of control. In addition, pursuant to the terms of WEC Energy Group's credit agreement, we must ensure that certain of our subsidiaries comply with several of the covenants contained therein.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
114
|
WEC Energy Group, Inc.
|
NOTE 14—LONG-TERM DEBT
The following table is a summary of our long-term debt outstanding (excluding finance leases) as of December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
(in millions)
|
|
Maturity Date
|
|
Weighted Average Interest Rate
|
|
Balance
|
|
Weighted Average Interest Rate
|
|
Balance
|
WEC Energy Group Senior Notes (unsecured) (1)
|
|
2023-2033
|
|
2.03
|
%
|
|
$
|
2,270.0
|
|
|
3.47
|
%
|
|
$
|
2,050.0
|
|
WEC Energy Group Junior Notes (unsecured) (1) (2)
|
|
2067
|
|
3.65
|
%
|
|
500.0
|
|
|
4.50
|
%
|
|
500.0
|
|
WE Debentures (unsecured)
|
|
2021-2095
|
|
4.26
|
%
|
|
2,785.0
|
|
|
4.26
|
%
|
|
2,785.0
|
|
WPS Senior Notes (unsecured)
|
|
2021-2049
|
|
4.04
|
%
|
|
1,625.0
|
|
|
4.04
|
%
|
|
1,625.0
|
|
WG Debentures (unsecured)
|
|
2024-2046
|
|
3.65
|
%
|
|
640.0
|
|
|
3.65
|
%
|
|
640.0
|
|
Integrys Senior Notes (unsecured)
|
|
2020
|
|
N/A
|
|
—
|
|
|
4.17
|
%
|
|
250.0
|
|
Integrys Junior Notes (unsecured) (3)
|
|
2073
|
|
6.00
|
%
|
|
400.0
|
|
|
6.00
|
%
|
|
400.0
|
|
PGL First and Refunding Mortgage Bonds (secured) (4)
|
|
2024-2047
|
|
3.45
|
%
|
|
1,670.0
|
|
|
3.59
|
%
|
|
1,520.0
|
|
NSG First Mortgage Bonds (secured) (5)
|
|
2027-2043
|
|
3.81
|
%
|
|
132.0
|
|
|
3.81
|
%
|
|
132.0
|
|
MERC Senior Notes (unsecured)
|
|
2025-2047
|
|
3.27
|
%
|
|
170.0
|
|
|
3.51
|
%
|
|
120.0
|
|
MGU Senior Notes (unsecured)
|
|
2025-2047
|
|
3.18
|
%
|
|
150.0
|
|
|
3.51
|
%
|
|
90.0
|
|
UMERC Senior Notes (unsecured)
|
|
2029
|
|
3.26
|
%
|
|
160.0
|
|
|
3.26
|
%
|
|
160.0
|
|
Bluewater Gas Storage Senior Notes (unsecured) (6)
|
|
2021-2047
|
|
3.76
|
%
|
|
117.8
|
|
|
3.76
|
%
|
|
120.3
|
|
ATC Holding Senior Notes (unsecured)
|
|
2025-2030
|
|
4.05
|
%
|
|
475.0
|
|
|
4.05
|
%
|
|
475.0
|
|
We Power Subsidiaries Notes (secured, nonrecourse) (6) (7)
|
|
2021-2041
|
|
5.59
|
%
|
|
970.8
|
|
|
5.57
|
%
|
|
1,005.2
|
|
WECC Notes (unsecured)
|
|
2028
|
|
6.94
|
%
|
|
50.0
|
|
|
6.94
|
%
|
|
50.0
|
|
WECI Wind Holding I Senior Notes (secured) (6) (8)
|
|
2032
|
|
2.75
|
%
|
|
413.6
|
|
|
N/A
|
|
—
|
|
Total
|
|
|
|
|
|
12,529.2
|
|
|
|
|
11,922.5
|
|
Integrys acquisition fair value adjustment
|
|
|
|
|
|
8.4
|
|
|
|
|
14.3
|
|
Unamortized debt issuance costs
|
|
|
|
|
|
(65.2)
|
|
|
|
|
(52.9)
|
|
Unamortized discount, net and other
|
|
|
|
|
|
(21.9)
|
|
|
|
|
(25.6)
|
|
Total long-term debt, including current portion (9)
|
|
|
|
|
|
12,450.5
|
|
|
|
|
11,858.3
|
|
Current portion of long-term debt
|
|
|
|
|
|
(777.7)
|
|
|
|
|
(686.9)
|
|
Total long-term debt
|
|
|
|
|
|
$
|
11,672.8
|
|
|
|
|
$
|
11,171.4
|
|
(1) In connection with our outstanding 2007 Junior Notes, we executed an RCC, which we amended on June 29, 2015, for the benefit of persons that buy, hold, or sell a specified series of our long-term indebtedness (covered debt). Our 6.20% Senior Notes due April 1, 2033 have been designated as the covered debt under the RCC. The RCC provides that we may not redeem, defease, or purchase, and that our subsidiaries may not purchase, any 2007 Junior Notes on or before May 15, 2037, unless, subject to certain limitations described in the RCC, we have received a specified amount of proceeds from the sale of qualifying securities.
(2) Variable interest rate reset quarterly. The rates were 2.33% and 4.02% as of December 31, 2020 and 2019, respectively. On July 12, 2018, we executed two interest rate swaps that provided a fixed rate of 4.9765% on $250.0 million of the outstanding notes. The effective rates of 3.65% and 4.50% as of December 31, 2020 and 2019, respectively, were blended rates of the variable and fixed portions.
(3) Effective August 2023, Integrys's $400.0 million of 2013 6.00% Junior Subordinated Notes due 2073 will bear interest at the three-month LIBOR plus 322 basis points and will reset quarterly.
(4) PGL's First Mortgage Bonds are subject to the terms and conditions of PGL's First Mortgage Indenture dated January 2, 1926, as supplemented. Under the terms of the Indenture, substantially all property owned by PGL is pledged as collateral for these outstanding debt securities.
PGL has used certain First Mortgage Bonds to secure tax exempt interest rates. The Illinois Finance Authority has issued Tax Exempt Bonds, and the proceeds from the sale of these bonds were loaned to PGL. In return, PGL issued equal principal amounts of certain collateralized First Mortgage Bonds.
(5) NSG's First Mortgage Bonds are subject to the terms and conditions of NSG's First Mortgage Indenture dated April 1, 1955, as supplemented. Under the terms of the Indenture, substantially all property owned by NSG is pledged as collateral for these outstanding debt securities.
(6) The long-term debt of Bluewater, WECI Wind Holding I, and We Power's subsidiaries requires periodic principal payments.
(7) We Power's subsidiaries' senior notes are secured by a collateral assignment of the leases between We Power's subsidiaries and WE related to PWGS and ERGS, as applicable.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
115
|
WEC Energy Group, Inc.
|
(8) WECI Wind Holding I's Senior Notes are secured by a first priority security interest in the ownership interest of its subsidiaries as well as a pledge of equity in WECI Wind Holding I.
(9) The amount of long-term debt on our balance sheets includes finance lease obligations of $63.4 million and $45.9 million at December 31, 2020 and 2019, respectively.
We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense.
WEC Energy Group, Inc.
In May 2020, we redeemed at par all $400.0 million outstanding of our 2.45% Senior Notes due June 15, 2020.
In September 2020, we issued $700.0 million of 0.55% Senior Notes due September 15, 2023, and used the net proceeds to repay commercial paper and for working capital and other general corporate purposes.
In October 2020, we issued $500.0 million of 1.375% Senior Notes due October 15, 2027, and $450.0 million of 1.800% Senior Notes due October 15, 2030. We used the net proceeds to redeem all $600.0 million outstanding of our 3.375% Senior Notes due June 15, 2021 and all $350.0 million outstanding of our 3.10% Senior Notes due March 8, 2022, and for other general corporate purposes. As a result of redeeming our 3.375% Senior Notes and our 3.10% Senior Notes prior to their maturity dates, we recognized a $27.9 million loss on early extinguishment of debt in October 2020. The loss is comprised of the make-whole premium associated with the early redemptions and the write-off of unamortized debt discounts and debt issuance costs as of the redemption date.
In December 2020, we redeemed $80.0 million of the $500.0 million outstanding of our 3.55% Senior Notes due June 15, 2025 with the proceeds we received from issuing commercial paper. As a result of the redemption prior to maturity, we recognized a $10.5 million loss on early extinguishment of debt. The loss is comprised of the make-whole premium associated with the early redemption and the write-off of the related unamortized debt discount and debt issuance costs as of the redemption date.
Integrys Holding, Inc.
In November 2020, Integrys' $250.0 million of 4.17% Senior Notes matured, and outstanding principal was paid with proceeds received from WEC Energy Group issuing commercial paper.
The Peoples Gas Light and Coke Company
In August 2020, PGL redeemed at par all $50.0 million outstanding of its 1.875% Series WW Bonds due February 1, 2033.
In November 2020, PGL issued $200.0 million of 1.98% Series JJJ Bonds due December 1, 2030, and used the net proceeds for general corporate purposes, including capital expenditures and the refinancing of short-term debt.
Minnesota Energy Resources Corporation
In April 2020, MERC issued $50.0 million of 2.69% Senior Notes due May 1, 2025, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys, and for general corporate purposes, including capital expenditures.
Michigan Gas Utilities Corporation
In April 2020, MGU issued $60.0 million of 2.69% Senior Notes due May 1, 2025, and used the net proceeds to repay intercompany short-term debt to its parent, Integrys, and for general corporate purposes, including capital expenditures.
WEC Infrastructure Wind Holding I LLC
In December 2020, WECI Wind Holding I issued $413.6 million of 2.75% Senior Notes due December 31, 2032, and used the net proceeds to return a portion of WECI's previously invested capital in the subsidiaries of WECI Wind Holding I.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
116
|
WEC Energy Group, Inc.
|
Maturities of Long-Term Debt Outstanding
The following table shows the long-term debt securities (excluding finance leases) maturing within one year of December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Interest Rate
|
|
Maturity Date (1)
|
|
Principal Amount
|
WE Debentures (unsecured)
|
|
2.95%
|
|
September
|
|
$
|
300.0
|
|
WPS Senior Notes (unsecured)
|
|
3.35%
|
|
November
|
|
400.0
|
|
Bluewater Gas Storage Senior Notes (unsecured)
|
|
3.76%
|
|
Semi-annually
|
|
2.6
|
|
We Power Subsidiaries Notes – PWGS (secured, nonrecourse)
|
|
4.91%
|
|
Monthly
|
|
6.9
|
|
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)
|
|
5.209%
|
|
Semi-annually
|
|
13.2
|
|
We Power Subsidiaries Notes – ERGS (secured, nonrecourse)
|
|
4.673%
|
|
Semi-annually
|
|
10.2
|
|
We Power Subsidiaries Notes – PWGS (secured, nonrecourse)
|
|
6.00%
|
|
Monthly
|
|
5.9
|
|
WECI Wind Holding I Senior Notes (secured)
|
|
2.75%
|
|
Semi-annually
|
|
38.9
|
|
Total
|
|
|
|
|
|
$
|
777.7
|
|
(1) Maturity dates listed as semi-annually and monthly are associated with debt that requires periodic principal payments.
The following table shows the future maturities of our long-term debt outstanding (excluding obligations under finance leases) as of December 31, 2020:
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Payments
|
2021
|
|
$
|
777.7
|
|
2022
|
|
83.3
|
|
2023
|
|
784.9
|
|
2024
|
|
613.7
|
|
2025
|
|
1,156.7
|
|
Thereafter
|
|
9,112.9
|
|
Total
|
|
$
|
12,529.2
|
|
Certain long-term debt obligations contain financial and other covenants related to payment of principal and interest when due, maintaining certain total funded debt to capitalization ratios, and various other obligations. Failure to comply with these covenants could result in an event of default, which could result in the acceleration of outstanding debt obligations.
NOTE 15—LEASES
Obligations Under Operating Leases
We have recorded right of use assets and lease liabilities associated with the following operating leases.
•Leases of office space, primarily related to several floors we are leasing in the Aon Center office building in Chicago, Illinois, though April 2029.
•Land we are leasing related to our Rothschild biomass plant through June 2051.
•Rail cars we are leasing to transport coal to various generating facilities through February 2021.
The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement.
Obligations Under Finance Lease
Power Purchase Commitment
In 1997, we entered into a 25-year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years, purchase the generating facility at fair market value, or allow the contract to expire. At lease inception we recorded this leased facility and corresponding obligation
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
117
|
WEC Energy Group, Inc.
|
on our balance sheets at the estimated fair value of the plant's electric generating facilities. Minimum lease payments are a function of the 236 MW of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease.
Prior to our adoption of Topic 842 on January 1, 2019, we accounted for this finance lease under Topic 980-840, Regulated Operations – Leases, as follows:
•We recorded our minimum lease payments as purchased power expense in cost of sales on our income statement.
•We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets.
In conjunction with our adoption of Topic 842, while the timing of expense recognition related to this finance lease did not change, classification of the lease expense changed as follows:
•Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within cost of sales in our income statements, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases.
•In accordance with Topic 980-842, the timing of lease expense did not change for this finance lease upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, as the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842.
•We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets.
Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $12.1 million at December 31, 2020, and will decrease to zero over the remaining life of the contract.
Two Creeks Solar Park
Related to its investment in Two Creeks, WPS, along with an unaffiliated utility, entered into several land leases in Manitowoc County, Wisconsin that commenced in the third quarter of 2019. The leases with unaffiliated parties are for a total of approximately 600 acres of land. Each lease has an initial term of 30 years with two optional 10-year extensions. We expect the two optional extensions to be exercised, and, as a result, the land leases are being amortized over the 50-year extended term of the leases. The lease payments are being recovered through rates.
We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Two Creeks was $7.9 million as of December 31, 2020, and will decrease to zero over the remaining lives of the leases.
Badger Hollow Solar Park I
Related to its investment in Badger Hollow I, WPS, along with an unaffiliated utility, entered into several land leases in Iowa County, Wisconsin that commenced in the third quarter of 2019. The leases are for a total of approximately 1,400 acres of land. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. The lease payments will be recovered through rates.
We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Badger Hollow I was $20.3 million as of December 31, 2020, and will decrease to zero over the remaining lives of the leases.
Badger Hollow Solar Park II
Related to its investment in Badger Hollow II, WE, along with an unaffiliated utility, entered into several land leases in Iowa County, Wisconsin that commenced in the second quarter of 2020. The leases are for a total of approximately 1,500 acres of land. Each lease has an initial construction term that ends upon achieving commercial operation, then automatically extends for 25 years with an option for an additional 25-year extension. We expect the optional extension to be exercised, and, as a result, the land leases are being amortized over the extended term of the leases. The lease payments will be recovered through rates.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
118
|
WEC Energy Group, Inc.
|
We treat these land lease contracts as operating leases for rate-making purposes. Our total obligation under the finance leases for Badger Hollow II was $23.1 million as of December 31, 2020, and will decrease to zero over the remaining lives of the leases.
Amounts Recognized in the Financial Statements
The components of lease expense and supplemental cash flow information related to our leases for the years ended December 31 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Finance lease expense
|
|
|
|
|
|
|
Amortization of right of use assets (1)
|
|
$
|
6.3
|
|
|
$
|
4.9
|
|
|
|
Interest on lease liabilities (2)
|
|
2.5
|
|
|
3.3
|
|
|
|
Capital lease expense (3)
|
|
|
|
|
|
$
|
7.7
|
|
Operating lease expense (4)
|
|
5.4
|
|
|
5.5
|
|
|
5.6
|
|
Short-term lease expense (4)
|
|
0.3
|
|
|
0.6
|
|
|
1.5
|
|
Total lease expense
|
|
$
|
14.5
|
|
|
$
|
14.3
|
|
|
$
|
14.8
|
|
|
|
|
|
|
|
|
Other information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
|
|
|
|
Operating cash flows from finance/capital leases (5)
|
|
$
|
2.5
|
|
|
$
|
3.3
|
|
|
$
|
7.7
|
|
Operating cash flows from operating leases
|
|
$
|
6.7
|
|
|
$
|
6.0
|
|
|
$
|
6.5
|
|
Financing cash flows from finance leases (5)
|
|
$
|
6.3
|
|
|
$
|
4.9
|
|
|
|
|
|
|
|
|
|
|
Non-cash activities:
|
|
|
|
|
|
|
Right of use assets obtained in exchange for finance lease liabilities
|
|
$
|
22.8
|
|
|
$
|
27.2
|
|
|
|
Right of use assets obtained in exchange for operating lease liabilities
|
|
$
|
—
|
|
|
$
|
49.0
|
|
|
|
|
|
|
|
|
|
|
Weighted-average remaining lease term – finance leases
|
|
41.5 years
|
|
31.5 years
|
|
|
Weighted-average remaining lease term – operating leases
|
|
13.0 years
|
|
12.9 years
|
|
|
|
|
|
|
|
|
|
Weighted-average discount rate – finance lease (6)
|
|
4.9
|
%
|
|
6.7
|
%
|
|
|
Weighted average discount rate – operating leases (6)
|
|
3.4
|
%
|
|
4.4
|
%
|
|
|
(1) Amortization of right of use assets was included as a component of depreciation and amortization expense for the years ended December 31, 2020 and 2019.
(2) Interest on lease liabilities was included as a component of interest expense for the years ended December 31, 2020 and 2019.
(3) Capital lease expense related to the long-term PPA was included in cost of sales for the year ended December 31, 2018.
(4) Operating and short-term lease expense were included as a component of operation and maintenance for the years ended December 31, 2020, 2019, and 2018.
(5) Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to the finance lease were recorded as a component of operating cash flows.
(6) Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our PPA that meets the definition of a finance lease, the rate implicit in the lease was readily determinable. For our solar land leases that are finance leases, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
119
|
WEC Energy Group, Inc.
|
The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
Long-term power purchase commitment
|
|
|
|
|
|
Under finance leases
|
|
$
|
140.3
|
|
|
$
|
140.3
|
|
|
Accumulated amortization
|
|
(132.3)
|
|
|
(126.6)
|
|
|
Total long-term power purchase commitment
|
|
$
|
8.0
|
|
|
$
|
13.7
|
|
|
|
|
|
|
|
|
Two Creeks land leases
|
|
|
|
|
|
Under finance leases
|
|
$
|
7.7
|
|
|
$
|
7.7
|
|
|
Accumulated amortization
|
|
(0.2)
|
|
|
(0.1)
|
|
|
Total Two Creeks land leases
|
|
$
|
7.5
|
|
|
$
|
7.6
|
|
|
|
|
|
|
|
|
Badger Hollow I land leases
|
|
|
|
|
|
Under finance leases
|
|
$
|
19.5
|
|
|
$
|
19.5
|
|
|
Accumulated amortization
|
|
(0.6)
|
|
|
(0.2)
|
|
|
Total Badger Hollow I land leases
|
|
$
|
18.9
|
|
|
$
|
19.3
|
|
|
|
|
|
|
|
|
Badger Hollow II land leases
|
|
|
|
|
|
Under finance leases
|
|
$
|
22.8
|
|
|
$
|
—
|
|
|
Accumulated amortization
|
|
(0.2)
|
|
|
—
|
|
|
Total Badger Hollow II land leases
|
|
$
|
22.6
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Total finance lease right of use assets
|
|
$
|
57.0
|
|
|
$
|
40.6
|
|
|
Right of use assets related to operating leases were $20.7 million and $41.4 million at December 31, 2020 and 2019, and were included in other long-term assets on our balance sheets.
Future minimum lease payments under our operating leases and our finance leases, and the present value of our net minimum lease payments as of December 31, 2020, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Total Operating Leases
|
|
Power Purchase Commitment
|
|
Two Creeks
|
|
Badger Hollow I
|
|
Badger Hollow II
|
|
Total Finance Leases
|
2021
|
|
$
|
4.5
|
|
|
$
|
9.4
|
|
|
$
|
0.2
|
|
|
$
|
0.7
|
|
|
$
|
0.3
|
|
|
$
|
10.6
|
|
2022
|
|
4.4
|
|
|
4.2
|
|
|
0.2
|
|
|
0.7
|
|
|
0.3
|
|
|
5.4
|
|
2023
|
|
4.5
|
|
|
—
|
|
|
0.2
|
|
|
0.7
|
|
|
0.7
|
|
|
1.6
|
|
2024
|
|
4.3
|
|
|
—
|
|
|
0.2
|
|
|
0.7
|
|
|
0.7
|
|
|
1.6
|
|
2025
|
|
3.8
|
|
|
—
|
|
|
0.2
|
|
|
0.7
|
|
|
0.7
|
|
|
1.6
|
|
Thereafter
|
|
24.5
|
|
|
—
|
|
|
22.6
|
|
|
52.7
|
|
|
55.0
|
|
|
130.3
|
|
Total minimum lease payments
|
|
46.0
|
|
|
13.6
|
|
|
23.6
|
|
|
56.2
|
|
|
57.7
|
|
|
151.1
|
|
Less: Interest
|
|
(10.2)
|
|
|
(1.5)
|
|
|
(15.7)
|
|
|
(35.9)
|
|
|
(34.6)
|
|
|
(87.7)
|
|
Present value of minimum lease payments
|
|
35.8
|
|
|
12.1
|
|
|
7.9
|
|
|
20.3
|
|
|
23.1
|
|
|
63.4
|
|
Less: Short-term lease liabilities
|
|
(3.4)
|
|
|
(8.1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8.1)
|
|
Long-term lease liabilities
|
|
$
|
32.4
|
|
|
$
|
4.0
|
|
|
$
|
7.9
|
|
|
$
|
20.3
|
|
|
$
|
23.1
|
|
|
$
|
55.3
|
|
Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively. Short-term and long-term lease liabilities related to our finance leases were included in current portion of long-term debt and long-term debt on the balance sheets, respectively.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
120
|
WEC Energy Group, Inc.
|
NOTE 16—INCOME TAXES
Income Tax Expense
The following table is a summary of income tax expense for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Current tax expense (benefit)
|
|
$
|
49.2
|
|
|
$
|
(37.9)
|
|
|
$
|
(127.5)
|
|
Deferred income taxes, net
|
|
182.2
|
|
|
167.7
|
|
|
300.1
|
|
ITC, net
|
|
(3.5)
|
|
|
(4.8)
|
|
|
(2.8)
|
|
Total income tax expense
|
|
$
|
227.9
|
|
|
$
|
125.0
|
|
|
$
|
169.8
|
|
Statutory Rate Reconciliation
The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
Effective
|
|
|
|
Effective
|
|
|
|
Effective
|
(in millions)
|
|
Amount
|
|
Tax Rate
|
|
Amount
|
|
Tax Rate
|
|
Amount
|
|
Tax Rate
|
Statutory federal income tax
|
|
$
|
299.9
|
|
|
21.0
|
%
|
|
$
|
264.4
|
|
|
21.0
|
%
|
|
$
|
258.1
|
|
|
21.0
|
%
|
State income taxes net of federal tax benefit
|
|
90.5
|
|
|
6.3
|
%
|
|
80.4
|
|
|
6.4
|
%
|
|
71.8
|
|
|
5.8
|
%
|
Federal excess deferred tax amortization – Wisconsin unprotected (1)
|
|
(57.6)
|
|
|
(4.0)
|
%
|
|
—
|
|
|
—
|
%
|
|
—
|
|
|
—
|
%
|
Wind PTCs
|
|
(51.5)
|
|
|
(3.6)
|
%
|
|
(34.1)
|
|
|
(2.7)
|
%
|
|
(12.1)
|
|
|
(1.0)
|
%
|
Federal excess deferred tax amortization (2)
|
|
(36.7)
|
|
|
(2.6)
|
%
|
|
(34.9)
|
|
|
(2.8)
|
%
|
|
(16.8)
|
|
|
(1.4)
|
%
|
Excess tax benefits – stock options
|
|
(12.3)
|
|
|
(0.9)
|
%
|
|
(15.8)
|
|
|
(1.3)
|
%
|
|
(5.9)
|
|
|
(0.5)
|
%
|
AFUDC – Equity
|
|
(4.4)
|
|
|
(0.3)
|
%
|
|
(3.0)
|
|
|
(0.2)
|
%
|
|
(3.2)
|
|
|
(0.3)
|
%
|
ITC restored
|
|
(3.5)
|
|
|
(0.2)
|
%
|
|
(4.8)
|
|
|
(0.4)
|
%
|
|
(2.8)
|
|
|
(0.2)
|
%
|
Tax repairs (3)
|
|
3.3
|
|
|
0.2
|
%
|
|
(122.8)
|
|
|
(9.8)
|
%
|
|
(120.7)
|
|
|
(9.8)
|
%
|
Other, net
|
|
0.2
|
|
|
—
|
%
|
|
(4.4)
|
|
|
(0.3)
|
%
|
|
1.4
|
|
|
0.2
|
%
|
Total income tax expense
|
|
$
|
227.9
|
|
|
15.9
|
%
|
|
$
|
125.0
|
|
|
9.9
|
%
|
|
$
|
169.8
|
|
|
13.8
|
%
|
(1) In accordance with the rate order received from the PSCW in December 2019, our Wisconsin utilities are amortizing these unprotected deferred tax benefits over periods ranging from two years to four years, to reduce near-term rate impacts to their customers. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.
(2) The Tax Legislation required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess protected deferred income taxes beginning in 2018 in accordance with normalization requirements. The decrease in income tax expense related to the amortization of the deferred tax benefits is offset by a decrease in revenue as the benefits are returned to customers, resulting in no impact on net income.
(3) In accordance with a settlement agreement with the PSCW, WE flowed through the tax benefit of its repair related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. The flow through treatment of the repair related deferred tax liabilities offset the negative income statement impact of holding the regulatory assets level, resulting in no impact to net income. In 2020, in accordance with the settlement agreement, WE started collecting the payback of the tax repairs benefit that was flowed through to customers. Customers will pay back all of the benefits over the next fifty years.
See Note 26, Regulatory Environment, for more information about the impact of the Tax Legislation and the Wisconsin rate orders.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
121
|
WEC Energy Group, Inc.
|
Deferred Income Tax Assets and Liabilities
The components of deferred income taxes as of December 31 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
Deferred tax assets
|
|
|
|
|
Tax gross up – regulatory items
|
|
$
|
497.6
|
|
|
$
|
519.8
|
|
Deferred revenues
|
|
104.2
|
|
|
106.3
|
|
Future tax benefits
|
|
102.5
|
|
|
101.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
197.2
|
|
|
159.8
|
|
Total deferred tax assets
|
|
901.5
|
|
|
886.9
|
|
Valuation allowance
|
|
(2.3)
|
|
|
(2.3)
|
|
Net deferred tax assets
|
|
$
|
899.2
|
|
|
$
|
884.6
|
|
|
|
|
|
|
Deferred tax liabilities
|
|
|
|
|
Property-related
|
|
$
|
3,721.0
|
|
|
$
|
3,609.0
|
|
Investment in affiliates
|
|
647.2
|
|
|
531.7
|
|
Deferred costs – Plant retirements
|
|
255.4
|
|
|
232.0
|
|
Employee benefits and compensation
|
|
148.2
|
|
|
131.4
|
|
|
|
|
|
|
Other
|
|
187.2
|
|
|
149.8
|
|
Total deferred tax liabilities
|
|
4,959.0
|
|
|
4,653.9
|
|
Deferred tax liability, net
|
|
$
|
4,059.8
|
|
|
$
|
3,769.3
|
|
Consistent with rate-making treatment, deferred taxes related to our regulated utilities in the table above are offset for temporary differences that have related regulatory assets and liabilities.
The components of net deferred tax assets associated with federal and state tax benefit carryforwards as of December 31, 2020 and 2019 are summarized in the tables below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
(in millions)
|
|
Gross Value
|
|
Deferred Tax Effect
|
|
Valuation Allowance
|
|
Earliest Year of Expiration
|
Future tax benefits as of December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal tax credit
|
|
$
|
—
|
|
|
$
|
89.1
|
|
|
$
|
—
|
|
|
2040
|
State net operating loss
|
|
88.8
|
|
|
5.5
|
|
|
(2.3)
|
|
|
2030
|
Other state benefits
|
|
—
|
|
|
7.9
|
|
|
—
|
|
|
2023
|
Balance as of December 31, 2020
|
|
$
|
88.8
|
|
|
$
|
102.5
|
|
|
$
|
(2.3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
(in millions)
|
|
Gross Value
|
|
Deferred Tax Effect
|
|
Valuation Allowance
|
|
Earliest Year of Expiration
|
Future tax benefits as of December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal tax credit
|
|
$
|
—
|
|
|
$
|
75.4
|
|
|
$
|
—
|
|
|
2037
|
State net operating loss
|
|
287.1
|
|
|
17.6
|
|
|
(2.3)
|
|
|
2023
|
Other state benefits
|
|
—
|
|
|
8.0
|
|
|
—
|
|
|
2019
|
Balance as of December 31, 2019
|
|
$
|
287.1
|
|
|
$
|
101.0
|
|
|
$
|
(2.3)
|
|
|
|
Unrecognized Tax Benefits
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
Balance as of January 1
|
|
$
|
17.9
|
|
|
$
|
20.0
|
|
Additions for tax positions of prior years
|
|
1.6
|
|
|
1.9
|
|
Additions based on tax positions related to the current year
|
|
0.1
|
|
|
0.2
|
|
Reductions for tax positions of prior years
|
|
(7.7)
|
|
|
(4.2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31
|
|
$
|
11.9
|
|
|
$
|
17.9
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
122
|
WEC Energy Group, Inc.
|
The amount of unrecognized tax benefits as of both December 31, 2020 and 2019, excludes deferred tax assets related to uncertainty in income taxes of $1.9 million and $2.0 million, respectively. As of December 31, 2020 and 2019, the net amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations was $10.1 million and $15.9 million, respectively.
For the years ended December 31, 2020, 2019, and 2018, we recognized $0.3 million of interest income, $0.1 million of interest expense, and $0.5 million of interest expense, respectively, related to unrecognized tax benefits in our income statements. For the years ended December 31, 2020, 2019, and 2018, we recognized no penalties related to unrecognized tax benefits in our income statements. For the year ended December 31, 2020, we had $0.5 million of interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets. For the year ended December 31, 2019, we had $0.8 million of interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets.
Although analysis of our unrecognized tax benefits is ongoing, the potential estimated decrease in the total amounts of unrecognized tax benefits within the next 12 months is approximately $7.5 million associated with statutes of limitations on certain tax years. We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months.
We file income tax returns in the United States federal jurisdiction and state tax returns based on income in our major state operating jurisdictions of Wisconsin, Illinois, Michigan, and Minnesota. We also file tax returns in other state and local jurisdictions with varying statutes of limitations. As of December 31, 2020, with a few exceptions, we were subject to examination by federal and state or local tax authorities for the 2015 through 2020 tax years in our major operating jurisdictions as follows:
|
|
|
|
|
|
|
|
|
Jurisdiction
|
|
Years
|
Federal
|
|
2017–2020
|
Illinois
|
|
2015–2020
|
Michigan
|
|
2015–2020
|
Minnesota
|
|
2016–2020
|
Wisconsin
|
|
2016–2020
|
NOTE 17—FAIR VALUE MEASUREMENTS
The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
(in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Derivative assets
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
11.7
|
|
|
$
|
2.0
|
|
|
$
|
—
|
|
|
$
|
13.7
|
|
FTRs
|
|
—
|
|
|
—
|
|
|
2.4
|
|
|
2.4
|
|
Coal contracts
|
|
—
|
|
|
1.8
|
|
|
—
|
|
|
1.8
|
|
Total derivative assets
|
|
$
|
11.7
|
|
|
$
|
3.8
|
|
|
$
|
2.4
|
|
|
$
|
17.9
|
|
|
|
|
|
|
|
|
|
|
Investments held in rabbi trust
|
|
$
|
79.6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
79.6
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
7.7
|
|
|
$
|
6.4
|
|
|
$
|
—
|
|
|
$
|
14.1
|
|
Coal contracts
|
|
—
|
|
|
1.2
|
|
|
—
|
|
|
1.2
|
|
Interest rate swaps
|
|
—
|
|
|
6.8
|
|
|
—
|
|
|
6.8
|
|
Total derivative liabilities
|
|
$
|
7.7
|
|
|
$
|
14.4
|
|
|
$
|
—
|
|
|
$
|
22.1
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
123
|
WEC Energy Group, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
(in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Derivative assets
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
1.4
|
|
|
$
|
2.0
|
|
|
$
|
—
|
|
|
$
|
3.4
|
|
FTRs
|
|
—
|
|
|
—
|
|
|
3.1
|
|
|
3.1
|
|
Coal contracts
|
|
—
|
|
|
0.4
|
|
|
—
|
|
|
0.4
|
|
Total derivative assets
|
|
$
|
1.4
|
|
|
$
|
2.4
|
|
|
$
|
3.1
|
|
|
$
|
6.9
|
|
|
|
|
|
|
|
|
|
|
Investments held in rabbi trust
|
|
$
|
85.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
85.3
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
21.4
|
|
|
$
|
1.3
|
|
|
$
|
—
|
|
|
$
|
22.7
|
|
Coal contracts
|
|
—
|
|
|
0.2
|
|
|
—
|
|
|
0.2
|
|
Interest rate swaps
|
|
—
|
|
|
6.0
|
|
|
—
|
|
|
6.0
|
|
Total derivative liabilities
|
|
$
|
21.4
|
|
|
$
|
7.5
|
|
|
$
|
—
|
|
|
$
|
28.9
|
|
The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices and interest rates. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.
We hold investments in the Integrys rabbi trust. These investments are restricted as they can only be withdrawn from the trust to fund participants' benefits under the Integrys deferred compensation plan and certain Integrys non-qualified pension plans. These investments are included in other long-term assets on our balance sheets. For the years ended December 31, 2020 and 2019, the net unrealized gains included in earnings related to the investments held at the end of the period were $6.3 million and $18.7 million, respectively. The net unrealized gains included in earnings for the year ended December 31, 2018 were not significant.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Balance at the beginning of the period
|
|
$
|
3.1
|
|
|
$
|
7.4
|
|
|
$
|
4.4
|
|
Purchases
|
|
7.6
|
|
|
12.8
|
|
|
18.4
|
|
Settlements
|
|
(8.3)
|
|
|
(17.1)
|
|
|
(15.4)
|
|
Balance at the end of the period
|
|
$
|
2.4
|
|
|
$
|
3.1
|
|
|
$
|
7.4
|
|
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
(in millions)
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
Preferred stock of subsidiary
|
|
$
|
30.4
|
|
|
$
|
32.3
|
|
|
$
|
30.4
|
|
|
$
|
29.5
|
|
Long-term debt, including current portion (1)
|
|
12,450.5
|
|
|
14,343.2
|
|
|
11,858.3
|
|
|
13,035.9
|
|
(1) The carrying amount of long-term debt excludes finance lease obligations of $63.4 million and $45.9 million at December 31, 2020 and 2019, respectively.
The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
124
|
WEC Energy Group, Inc.
|
NOTE 18—DERIVATIVE INSTRUMENTS
The following table shows our derivative assets and derivative liabilities, along with their classification on our balance sheets. None of our derivatives are designated as hedging instruments, with the exception of our interest rate swaps, which have been designated as cash flow hedges.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
(in millions)
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
Derivative Assets
|
|
Derivative Liabilities
|
Other current
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
13.0
|
|
|
$
|
12.9
|
|
|
$
|
3.4
|
|
|
$
|
21.8
|
|
FTRs
|
|
2.4
|
|
|
—
|
|
|
3.1
|
|
|
—
|
|
Coal contracts
|
|
1.6
|
|
|
0.8
|
|
|
0.2
|
|
|
0.2
|
|
Interest rate swaps
|
|
—
|
|
|
6.8
|
|
|
—
|
|
|
2.8
|
|
Total other current
|
|
17.0
|
|
|
20.5
|
|
|
6.7
|
|
|
24.8
|
|
|
|
|
|
|
|
|
|
|
Other long-term
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
0.7
|
|
|
1.2
|
|
|
—
|
|
|
0.9
|
|
Coal contracts
|
|
0.2
|
|
|
0.4
|
|
|
0.2
|
|
|
—
|
|
Interest rate swaps
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.2
|
|
Total other long-term
|
|
0.9
|
|
|
1.6
|
|
|
0.2
|
|
|
4.1
|
|
Total
|
|
$
|
17.9
|
|
|
$
|
22.1
|
|
|
$
|
6.9
|
|
|
$
|
28.9
|
|
Realized gains (losses) on derivatives not designated as hedging instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows for the years ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
December 31, 2018
|
(in millions)
|
|
Volumes
|
|
Gains (Losses)
|
|
Volumes
|
|
Gains (Losses)
|
|
Volumes
|
|
Gains
|
Natural gas contracts
|
|
188.6 Dth
|
|
$
|
(54.1)
|
|
|
183.9 Dth
|
|
$
|
(27.1)
|
|
|
173.2 Dth
|
|
$
|
24.6
|
|
Petroleum products contracts
|
|
— gallons
|
|
—
|
|
|
— gallons
|
|
—
|
|
|
6.0 gallons
|
|
1.6
|
|
FTRs
|
|
29.8 MWh
|
|
4.1
|
|
|
31.2 MWh
|
|
16.3
|
|
|
30.5 MWh
|
|
15.9
|
|
Total
|
|
|
|
$
|
(50.0)
|
|
|
|
|
$
|
(10.8)
|
|
|
|
|
$
|
42.1
|
|
At December 31, 2020 and 2019, we had posted cash collateral of $18.9 million and $34.4 million, respectively, in our margin accounts.
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
(in millions)
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
Gross amount recognized on the balance sheet
|
|
$
|
17.9
|
|
|
$
|
22.1
|
|
|
$
|
6.9
|
|
|
$
|
28.9
|
|
|
Gross amount not offset on the balance sheet
|
|
(6.9)
|
|
|
(7.7)
|
|
(1)
|
(1.4)
|
|
|
(21.4)
|
|
(2)
|
Net amount
|
|
$
|
11.0
|
|
|
$
|
14.4
|
|
|
$
|
5.5
|
|
|
$
|
7.5
|
|
|
(1) Includes cash collateral posted of $0.8 million.
(2) Includes cash collateral posted of $20.0 million.
Cash Flow Hedges
As of December 31, 2020, we had two interest rate swaps with a combined notional value of $250.0 million to hedge the variable interest rate risk associated with our 2007 Junior Notes. The swaps provide a fixed interest rate of 4.9765% on $250.0 million of the $500.0 million of outstanding 2007 Junior Notes through November 15, 2021. As these swaps qualify for cash flow hedge accounting treatment, the related gains and losses are being deferred in accumulated other comprehensive loss and are being amortized to interest expense as interest is accrued on the 2007 Junior Notes.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
125
|
WEC Energy Group, Inc.
|
We previously entered into forward interest rate swap agreements to mitigate the interest rate exposure associated with the issuance of long-term debt related to the acquisition of Integrys. These swap agreements were settled in 2015, and we continue to amortize amounts out of accumulated other comprehensive loss into interest expense over the periods in which the interest costs are recognized in earnings.
The table below shows the amounts related to these cash flow hedges recorded in other comprehensive loss and in earnings, along with our total interest expense on the income statements, for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Derivative loss recognized in other comprehensive loss
|
|
$
|
(5.9)
|
|
|
$
|
(4.8)
|
|
|
$
|
(2.9)
|
|
Net derivative gain (loss) reclassified from accumulated other comprehensive loss to interest expense
|
|
(2.1)
|
|
|
1.1
|
|
|
1.6
|
|
Total interest expense line item on the income statements
|
|
493.7
|
|
|
501.5
|
|
|
445.1
|
|
We estimate that during the next twelve months $5.5 million will be reclassified from accumulated other comprehensive loss as an increase to interest expense.
NOTE 19—GUARANTEES
The following table shows our outstanding guarantees:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expiration
|
(in millions)
|
|
Total Amounts Committed at December 31, 2020
|
|
Less Than 1 Year
|
|
1 to 3 Years
|
|
Over 3 Years
|
Guarantees supporting transactions of subsidiaries (1)
|
|
$
|
71.2
|
|
|
$
|
11.7
|
|
|
$
|
1.2
|
|
|
$
|
58.3
|
|
Standby letters of credit (2)
|
|
69.2
|
|
|
0.1
|
|
|
—
|
|
|
69.1
|
|
Surety bonds (3)
|
|
12.1
|
|
|
12.0
|
|
|
0.1
|
|
|
—
|
|
Other guarantees (4)
|
|
10.5
|
|
|
—
|
|
|
—
|
|
|
10.5
|
|
Total guarantees
|
|
$
|
163.0
|
|
|
$
|
23.8
|
|
|
$
|
1.3
|
|
|
$
|
137.9
|
|
(1) Consists of $4.2 million, $8.2 million, and $58.8 million to support the business operations of UMERC, Bluewater, and WECI, respectively.
(2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.
(3) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.
(4) Consists of $10.5 million related to workers compensation coverage for which a liability was recorded on our balance sheets.
NOTE 20—EMPLOYEE BENEFITS
Pension and Other Postretirement Employee Benefits
We and our subsidiaries have defined benefit pension plans that cover substantially all of our employees, as well as several unfunded non-qualified retirement plans. In addition, we and our subsidiaries offer multiple OPEB plans to employees. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred.
Generally, former Wisconsin Energy Corporation employees who started with the company after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. Wisconsin Energy Corporation management employees hired after December 31, 2014, and certain new represented employees hired after May 1, 2017, receive an annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans.
For former Integrys employees, the defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual
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2020 Form 10-K
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126
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WEC Energy Group, Inc.
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company contribution to their 401(k) savings plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year.
We use a year-end measurement date to measure the funded status of all of our pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of our pension and OPEB plans qualify as a regulatory asset.
The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
OPEB Benefits
|
(in millions)
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Change in benefit obligation
|
|
|
|
|
|
|
|
|
Obligation at January 1
|
|
$
|
3,123.7
|
|
|
$
|
2,927.2
|
|
|
$
|
558.6
|
|
|
$
|
608.2
|
|
Service cost
|
|
50.1
|
|
|
47.0
|
|
|
15.2
|
|
|
16.3
|
|
Interest cost
|
|
102.8
|
|
|
120.4
|
|
|
18.6
|
|
|
25.7
|
|
Participant contributions
|
|
—
|
|
|
—
|
|
|
13.3
|
|
|
12.3
|
|
Plan amendments
|
|
—
|
|
|
—
|
|
|
(5.0)
|
|
|
(4.0)
|
|
Actuarial loss (gain)
|
|
311.6
|
|
|
269.3
|
|
|
(1.4)
|
|
|
(60.7)
|
|
Benefit payments
|
|
(241.8)
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|
|
(240.2)
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|
|
(46.1)
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|
|
(42.3)
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|
Federal subsidy on benefits paid
|
|
N/A
|
|
N/A
|
|
1.3
|
|
|
1.3
|
|
Transfer
|
|
—
|
|
|
—
|
|
|
1.6
|
|
|
1.8
|
|
Obligation at December 31
|
|
$
|
3,346.4
|
|
|
$
|
3,123.7
|
|
|
$
|
556.1
|
|
|
$
|
558.6
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of plan assets
|
|
|
|
|
|
|
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|
Fair value at January 1
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|
$
|
3,007.0
|
|
|
$
|
2,690.8
|
|
|
$
|
879.6
|
|
|
$
|
771.7
|
|
Actual return on plan assets
|
|
348.1
|
|
|
494.1
|
|
|
103.1
|
|
|
134.3
|
|
Employer contributions
|
|
111.7
|
|
|
62.3
|
|
|
1.5
|
|
|
3.6
|
|
Participant contributions
|
|
—
|
|
|
—
|
|
|
13.3
|
|
|
12.3
|
|
Benefit payments
|
|
(241.8)
|
|
|
(240.2)
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|
|
(46.1)
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|
|
(42.3)
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Fair value at December 31
|
|
$
|
3,225.0
|
|
|
$
|
3,007.0
|
|
|
$
|
951.4
|
|
|
$
|
879.6
|
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Funded status at December 31
|
|
$
|
(121.4)
|
|
|
$
|
(116.7)
|
|
|
$
|
395.3
|
|
|
$
|
321.0
|
|
In 2020 and 2019, we had actuarial losses related to our pension benefit obligations of $311.6 million and $269.3 million, respectively, which was primarily due to decreases in our discount rates. The discount rate for our pension benefits was 2.67%, 3.41%, and 4.30%, in 2020, 2019, and 2018, respectively.
The 2020 actuarial gain related to our OPEB benefit obligation was not significant. In 2019, we had an actuarial gain related to our OPEB benefit obligation of $60.7 million, which was primarily due to better than expected claims and premiums experience, the use of new mortality tables, and the repeal of certain health insurance related taxes. These gains were partially offset by a decrease in our discount rate. The discount rate for our OPEB benefits was 3.39% and 4.27%, in 2019 and 2018, respectively.
The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows:
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|
|
|
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|
|
|
|
|
|
|
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Pension Benefits
|
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OPEB Benefits
|
(in millions)
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2020
|
|
2019
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2020
|
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2019
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Other long-term assets
|
|
$
|
182.9
|
|
|
$
|
188.8
|
|
|
$
|
418.0
|
|
|
$
|
341.7
|
|
Pension and OPEB obligations
|
|
304.3
|
|
|
305.5
|
|
|
22.7
|
|
|
20.7
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Total net (liabilities) assets
|
|
$
|
(121.4)
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|
$
|
(116.7)
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|
|
$
|
395.3
|
|
|
$
|
321.0
|
|
The accumulated benefit obligation for all defined benefit pension plans was $3,194.3 million and $2,992.9 million as of December 31, 2020 and 2019, respectively.
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2020 Form 10-K
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127
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WEC Energy Group, Inc.
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The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:
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|
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|
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(in millions)
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|
2020
|
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2019
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Accumulated benefit obligation
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$
|
1,555.5
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|
$
|
1,754.2
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Fair value of plan assets
|
|
1,298.3
|
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|
1,504.6
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The following table shows information for pension plans with a projected benefit obligation in excess of plan assets. Amounts presented are as of December 31:
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|
|
|
|
|
|
|
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|
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(in millions)
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|
2020
|
|
2019
|
Projected benefit obligation
|
|
$
|
2,034.1
|
|
|
$
|
1,810.1
|
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Fair value of plan assets
|
|
1,729.8
|
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|
1,504.6
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The following table shows information for OPEB plans with an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31:
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|
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|
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|
(in millions)
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|
2020
|
|
2019
|
Accumulated benefit obligation
|
|
$
|
25.7
|
|
|
$
|
31.1
|
|
Fair value of plan assets
|
|
3.0
|
|
|
10.4
|
|
The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
OPEB Benefits
|
(in millions)
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Pre-tax accumulated other comprehensive loss (1)
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
|
$
|
10.4
|
|
|
$
|
10.6
|
|
|
$
|
(1.4)
|
|
|
$
|
(1.6)
|
|
Prior service credits
|
|
—
|
|
|
—
|
|
|
(0.1)
|
|
|
(0.1)
|
|
Total
|
|
$
|
10.4
|
|
|
$
|
10.6
|
|
|
$
|
(1.5)
|
|
|
$
|
(1.7)
|
|
|
|
|
|
|
|
|
|
|
Net regulatory assets (liabilities) (2)
|
|
|
|
|
|
|
|
|
Net actuarial loss (gain)
|
|
$
|
1,101.2
|
|
|
$
|
1,067.7
|
|
|
$
|
(288.7)
|
|
|
$
|
(266.6)
|
|
Prior service costs (credits)
|
|
1.1
|
|
|
2.7
|
|
|
(78.6)
|
|
|
(88.6)
|
|
Total
|
|
$
|
1,102.3
|
|
|
$
|
1,070.4
|
|
|
$
|
(367.3)
|
|
|
$
|
(355.2)
|
|
(1) Amounts related to the nonregulated entities are included in accumulated other comprehensive loss.
(2) Amounts related to the utilities and WBS are recorded as net regulatory assets or liabilities.
The components of net periodic benefit cost (credit) (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
OPEB Benefits
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Service cost
|
|
$
|
50.1
|
|
|
$
|
47.0
|
|
|
$
|
47.1
|
|
|
$
|
15.2
|
|
|
$
|
16.3
|
|
|
$
|
23.7
|
|
Interest cost
|
|
102.8
|
|
|
120.4
|
|
|
114.3
|
|
|
18.6
|
|
|
25.7
|
|
|
29.9
|
|
Expected return on plan assets
|
|
(190.3)
|
|
|
(193.3)
|
|
|
(196.5)
|
|
|
(60.3)
|
|
|
(54.7)
|
|
|
(59.5)
|
|
Plan settlement
|
|
17.9
|
|
|
11.5
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service cost (credit)
|
|
1.6
|
|
|
2.2
|
|
|
2.7
|
|
|
(15.0)
|
|
|
(15.4)
|
|
|
(15.4)
|
|
Amortization of net actuarial loss (gain)
|
|
102.6
|
|
|
77.3
|
|
|
94.0
|
|
|
(22.4)
|
|
|
(6.6)
|
|
|
1.0
|
|
Net periodic benefit cost (credit)
|
|
$
|
84.7
|
|
|
$
|
65.1
|
|
|
$
|
62.6
|
|
|
$
|
(63.9)
|
|
|
$
|
(34.7)
|
|
|
$
|
(20.3)
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
128
|
WEC Energy Group, Inc.
|
The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
OPEB Benefits
|
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Discount rate
|
|
2.67%
|
|
3.41%
|
|
2.60%
|
|
3.39%
|
Rate of compensation increase
|
|
4.00%
|
|
4.00%
|
|
N/A
|
|
N/A
|
Interest credit rate
|
|
3.69%
|
|
3.70%
|
|
N/A
|
|
N/A
|
Assumed medical cost trend rate (Pre 65)
|
|
N/A
|
|
N/A
|
|
5.85%
|
|
6.00%
|
Ultimate trend rate (Pre 65)
|
|
N/A
|
|
N/A
|
|
5.00%
|
|
5.00%
|
Year ultimate trend rate is reached (Pre 65)
|
|
N/A
|
|
N/A
|
|
2028
|
|
2028
|
Assumed medical cost trend rate (Post 65)
|
|
N/A
|
|
N/A
|
|
5.80%
|
|
5.91%
|
Ultimate trend rate (Post 65)
|
|
N/A
|
|
N/A
|
|
5.00%
|
|
5.00%
|
Year ultimate trend rate is reached (Post 65)
|
|
N/A
|
|
N/A
|
|
2028
|
|
2028
|
The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
2020
|
|
2019
|
|
2018
|
Discount rate
|
|
3.34%
|
|
4.21%
|
|
3.71%
|
Expected return on plan assets
|
|
6.87%
|
|
7.12%
|
|
7.12%
|
Rate of compensation increase
|
|
4.00%
|
|
3.66%
|
|
3.66%
|
Interest credit rate
|
|
3.70%
|
|
3.72%
|
|
3.71%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPEB Benefits
|
|
|
2020
|
|
2019
|
|
2018
|
Discount rate
|
|
3.39%
|
|
4.27%
|
|
3.63%
|
Expected return on plan assets
|
|
7.00%
|
|
7.25%
|
|
7.25%
|
Assumed medical cost trend rate (Pre 65)
|
|
6.00%
|
|
6.25%
|
|
6.50%
|
Ultimate trend rate (Pre 65)
|
|
5.00%
|
|
5.00%
|
|
5.00%
|
Year ultimate trend rate is reached (Pre 65)
|
|
2028
|
|
2024
|
|
2024
|
Assumed medical cost trend rate (Post 65)
|
|
5.91%
|
|
6.01%
|
|
6.09%
|
Ultimate trend rate (Post 65)
|
|
5.00%
|
|
5.00%
|
|
5.00%
|
Year ultimate trend rate is reached (Post 65)
|
|
2028
|
|
2028
|
|
2028
|
We consult with our investment advisors on an annual basis to help us forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2021, the expected return on assets assumption is 6.87% for the pension plans and 7.00% for the OPEB plans.
Plan Assets
Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees.
The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments.
The legacy Wisconsin Energy Corporation pension trust target asset allocations are 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The legacy Integrys pension trust target asset allocations are 45% equity investments, 45% fixed income investments, and 10% private equity and real estate investments. The two legacy Wisconsin
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
129
|
WEC Energy Group, Inc.
|
Energy Corporation OPEB trusts' target asset allocations are 50% equity investments and 50% fixed income investments, and 70% equity investments and 30% fixed income investments, respectively. The two largest legacy OPEB trusts for Integrys have the same target asset allocations of 45% equity investments and 55% fixed income investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries.
Pension and OPEB plan investments are recorded at fair value. See Note 1(r), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used.
The following tables provide the fair values of our investments by asset class:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
|
Pension Plan Assets
|
|
OPEB Assets
|
(in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Asset Class
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States equity
|
|
$
|
439.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
439.2
|
|
|
$
|
141.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
141.4
|
|
International equity
|
|
345.1
|
|
|
—
|
|
|
—
|
|
|
345.1
|
|
|
120.9
|
|
|
—
|
|
|
—
|
|
|
120.9
|
|
Fixed income securities: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States bonds
|
|
—
|
|
|
1,056.4
|
|
|
—
|
|
|
1,056.4
|
|
|
143.0
|
|
|
179.9
|
|
|
—
|
|
|
322.9
|
|
International bonds
|
|
—
|
|
|
114.3
|
|
|
—
|
|
|
114.3
|
|
|
—
|
|
|
12.0
|
|
|
—
|
|
|
12.0
|
|
|
|
$
|
784.3
|
|
|
$
|
1,170.7
|
|
|
$
|
—
|
|
|
$
|
1,955.0
|
|
|
$
|
405.3
|
|
|
$
|
191.9
|
|
|
$
|
—
|
|
|
$
|
597.2
|
|
Investments measured at net asset value
|
|
|
|
|
|
|
|
$
|
1,270.0
|
|
|
|
|
|
|
|
|
$
|
354.2
|
|
Total
|
|
$
|
784.3
|
|
|
$
|
1,170.7
|
|
|
$
|
—
|
|
|
$
|
3,225.0
|
|
|
$
|
405.3
|
|
|
$
|
191.9
|
|
|
$
|
—
|
|
|
$
|
951.4
|
|
(1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
Pension Plan Assets
|
|
OPEB Assets
|
(in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
Asset Class
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States equity
|
|
$
|
335.6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
335.6
|
|
|
$
|
103.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
103.0
|
|
International equity
|
|
321.6
|
|
|
0.7
|
|
|
—
|
|
|
322.3
|
|
|
107.3
|
|
|
0.2
|
|
|
—
|
|
|
107.5
|
|
Fixed income securities: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States bonds
|
|
94.3
|
|
|
887.4
|
|
|
—
|
|
|
981.7
|
|
|
119.1
|
|
|
165.9
|
|
|
—
|
|
|
285.0
|
|
International bonds
|
|
51.5
|
|
|
87.0
|
|
|
—
|
|
|
138.5
|
|
|
24.6
|
|
|
8.5
|
|
|
—
|
|
|
33.1
|
|
|
|
$
|
803.0
|
|
|
$
|
975.1
|
|
|
$
|
—
|
|
|
$
|
1,778.1
|
|
|
$
|
354.0
|
|
|
$
|
174.6
|
|
|
$
|
—
|
|
|
$
|
528.6
|
|
Investments measured at net asset value
|
|
|
|
|
|
|
|
$
|
1,228.9
|
|
|
|
|
|
|
|
|
$
|
351.0
|
|
Total
|
|
$
|
803.0
|
|
|
$
|
975.1
|
|
|
$
|
—
|
|
|
$
|
3,007.0
|
|
|
$
|
354.0
|
|
|
$
|
174.6
|
|
|
$
|
—
|
|
|
$
|
879.6
|
|
(1) This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries.
Cash Flows
We expect to contribute $11.6 million to the pension plans and $2.1 million to the OPEB plans in 2021, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
130
|
WEC Energy Group, Inc.
|
The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB over the next 10 years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Pension Benefits
|
|
OPEB Benefits
|
|
2021
|
|
$
|
237.4
|
|
|
$
|
34.2
|
|
|
2022
|
|
231.8
|
|
|
34.4
|
|
|
2023
|
|
230.6
|
|
|
34.7
|
|
|
2024
|
|
222.2
|
|
|
34.5
|
|
|
2025
|
|
215.4
|
|
|
34.5
|
|
|
2026-2030
|
|
989.9
|
|
|
169.0
|
|
|
Savings Plans
We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, in which amounts are contributed to the employee's savings plan account based on the employee's wages, age, and years of service. Total costs incurred under all of these plans were $49.7 million, $50.9 million, and $49.3 million in 2020, 2019, and 2018, respectively.
NOTE 21—INVESTMENT IN TRANSMISSION AFFILIATES
We own approximately 60% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. ATC's corporate manager has a ten-member board of directors, and ATC Holdco's corporate manager has a four-member board of directors. We have one representative on each board. Each member of the board has only one vote. The following tables provide a reconciliation of the changes in our investments in ATC and ATC Holdco:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
(in millions)
|
|
ATC
|
|
ATC Holdco
|
|
Total
|
Balance at January 1
|
|
$
|
1,684.7
|
|
|
$
|
36.1
|
|
|
$
|
1,720.8
|
|
Add: Earnings from equity method investment
|
|
174.3
|
|
|
1.5
|
|
|
175.8
|
|
Add: Capital contributions
|
|
21.2
|
|
|
—
|
|
|
21.2
|
|
Less: Distributions
|
|
146.7
|
|
|
—
|
|
|
146.7
|
|
Less: Return of capital
|
|
—
|
|
|
6.8
|
|
|
6.8
|
|
Balance at December 31
|
|
$
|
1,733.5
|
|
|
$
|
30.8
|
|
|
$
|
1,764.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
(in millions)
|
|
ATC
|
|
ATC Holdco
|
|
Total
|
Balance at January 1
|
|
$
|
1,625.3
|
|
|
$
|
40.0
|
|
|
$
|
1,665.3
|
|
Add: Earnings (loss) from equity method investment
|
|
132.8
|
|
|
(5.2)
|
|
|
127.6
|
|
Add: Capital contributions
|
|
51.3
|
|
|
1.3
|
|
|
52.6
|
|
Less: Distributions
|
|
124.7
|
|
|
—
|
|
|
124.7
|
|
|
|
|
|
|
|
|
Balance at December 31
|
|
$
|
1,684.7
|
|
|
$
|
36.1
|
|
|
$
|
1,720.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
(in millions)
|
|
ATC
|
|
ATC Holdco
|
|
Total
|
Balance at January 1
|
|
$
|
1,515.8
|
|
(1)
|
$
|
37.6
|
|
|
$
|
1,553.4
|
|
Add: Earnings (loss) from equity method investment
|
|
139.6
|
|
|
(2.9)
|
|
|
136.7
|
|
Add: Capital contributions
|
|
48.2
|
|
|
5.3
|
|
|
53.5
|
|
Less: Distributions
|
|
78.2
|
|
|
—
|
|
|
78.2
|
|
Less: Other
|
|
0.1
|
|
|
—
|
|
|
0.1
|
|
Balance at December 31
|
|
$
|
1,625.3
|
|
|
$
|
40.0
|
|
|
$
|
1,665.3
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
131
|
WEC Energy Group, Inc.
|
(1) Distributions of $39.9 million, received in the first quarter of 2018, were approved and recorded as a receivable from ATC in other current assets at December 31, 2017.
In November 2019 and May 2020, the FERC issued orders that addressed complaints related to ATC's allowed ROE. Due to the various outstanding petitions filed related to these orders, our financials continue to include a $39.1 million liability for potential future refunds that ATC may be required to provide, reducing our equity earnings from ATC. This liability reflects a 10.52% ROE for all periods covered by the complaints.
We pay ATC for network transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. We are also required to initially fund the construction of transmission infrastructure upgrades needed for new generation projects. ATC owns these transmission assets and reimburses us for these costs when the new generation is placed in service.
The following table summarizes our significant related party transactions with ATC during the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Charges to ATC for services and construction
|
|
$
|
27.5
|
|
|
$
|
25.9
|
|
|
$
|
21.8
|
|
Charges from ATC for network transmission services
|
|
350.5
|
|
|
348.1
|
|
|
338.1
|
|
Net refund from ATC related to FERC ROE orders
|
|
10.7
|
|
|
—
|
|
|
—
|
|
Refund from ATC related to a FERC audit
|
|
—
|
|
|
—
|
|
|
22.0
|
|
As of December 31, 2020 and 2019, our balance sheets included the following receivables and payables for services provided to or received from ATC:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2020
|
|
2019
|
Accounts receivable for services provided to ATC
|
|
$
|
3.7
|
|
|
$
|
3.5
|
|
|
Accounts payable for services received from ATC
|
|
29.3
|
|
|
29.0
|
|
|
Amounts due from ATC for transmission infrastructure upgrades
|
|
4.6
|
|
(1)
|
2.8
|
|
(2)
|
(1) The transmission infrastructure upgrades were primarily related to WE's and WPS's construction of their new solar projects, Badger Hollow II and Badger Hollow I, respectively.
(2) The transmission infrastructure upgrades were related to WPS's construction of its two new solar projects, Badger Hollow I and Two Creeks. Amounts due related to Two Creeks were largely reimbursed by ATC in December 2020 as the new generation was placed in service.
Summarized financial data for ATC is included in the tables below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
(in millions)
|
|
2020
|
|
2019
|
|
2018
|
Income statement data
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
758.1
|
|
|
$
|
744.4
|
|
|
$
|
690.5
|
|
Operating expenses
|
|
372.5
|
|
|
373.5
|
|
|
358.7
|
|
Other expense, net
|
|
110.8
|
|
|
110.5
|
|
|
108.3
|
|
Net income
|
|
$
|
274.8
|
|
|
$
|
260.4
|
|
|
$
|
223.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
December 31, 2020
|
|
December 31, 2019
|
|
|
Balance sheet data
|
|
|
|
|
|
|
Current assets
|
|
$
|
92.7
|
|
|
$
|
84.7
|
|
|
|
Noncurrent assets
|
|
5,400.6
|
|
|
5,244.2
|
|
|
|
Total assets
|
|
$
|
5,493.3
|
|
|
$
|
5,328.9
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
310.8
|
|
|
$
|
502.6
|
|
|
|
Long-term debt
|
|
2,512.2
|
|
|
2,312.8
|
|
|
|
Other noncurrent liabilities
|
|
378.2
|
|
|
298.9
|
|
|
|
Members' equity
|
|
2,292.1
|
|
|
2,214.6
|
|
|
|
Total liabilities and members' equity
|
|
$
|
5,493.3
|
|
|
$
|
5,328.9
|
|
|
|
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
132
|
WEC Energy Group, Inc.
|
NOTE 22—SEGMENT INFORMATION
Effective December 31, 2020, we changed our measure of segment profitability from operating income to net income attributed to common shareholders. At December 31, 2020, we reported six segments, which are described below.
•The Wisconsin segment includes the electric and natural gas utility operations of WE, WPS, WG, and UMERC.
•The Illinois segment includes the natural gas utility operations of PGL and NSG.
•The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.
•The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects, and our approximate 75% ownership interest in ATC Holdco, which was formed to invest in transmission-related projects outside of ATC's traditional footprint.
•The non-utility energy infrastructure segment includes:
◦We Power, which owns and leases generating facilities to WE,
◦Bluewater, which owns underground natural gas storage facilities in Michigan that provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities, and
◦WECI, which holds our ownership interests in the following wind generating facilities:
▪90% ownership interest in Bishop Hill III, located in Henry County, Illinois,
▪80% ownership interest in Coyote Ridge, located in Brookings County, South Dakota,
▪90% ownership interest in Upstream, located in Antelope County, Nebraska,
▪90% ownership interest in Blooming Grove, located in McLean County, Illinois, and
▪85% ownership interest in Tatanka Ridge, located in Deuel County, South Dakota.
See Note 2, Acquisitions, for more information on Bishop Hill III, Coyote Ridge, Upstream, Blooming Grove, and Tatanka Ridge.
•The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the PELLC holding company, Wispark, Wisvest, WECC, WBS, and PDL. See Note 3, Dispositions, for more information on the sale of our remaining PDL solar facilities.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
133
|
WEC Energy Group, Inc.
|
All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2020, 2019, and 2018.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
|
|
|
|
|
|
|
|
|
2020 (in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Electric Transmission
|
|
Non-Utility Energy Infrastructure
|
|
Corporate and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
External revenues
|
|
$
|
5,473.5
|
|
|
$
|
1,321.9
|
|
|
$
|
384.1
|
|
|
$
|
7,179.5
|
|
|
$
|
—
|
|
|
$
|
60.0
|
|
|
$
|
2.2
|
|
|
$
|
—
|
|
|
$
|
7,241.7
|
|
Intersegment revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
448.5
|
|
|
—
|
|
|
(448.5)
|
|
|
—
|
|
Other operation and maintenance
|
|
1,476.7
|
|
|
435.4
|
|
|
87.0
|
|
|
1,999.1
|
|
|
—
|
|
|
24.9
|
|
|
17.4
|
|
|
(9.2)
|
|
|
2,032.2
|
|
Depreciation and amortization
|
|
674.5
|
|
|
196.7
|
|
|
33.5
|
|
|
904.7
|
|
|
—
|
|
|
98.9
|
|
|
25.1
|
|
|
(52.8)
|
|
|
975.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of transmission affiliates
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
175.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
175.8
|
|
Interest expense
|
|
561.3
|
|
|
63.5
|
|
|
10.2
|
|
|
635.0
|
|
|
19.4
|
|
|
60.8
|
|
|
124.0
|
|
|
(345.5)
|
|
|
493.7
|
|
Loss on debt extinguishment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
38.4
|
|
|
—
|
|
|
38.4
|
|
Income tax expense (benefit)
|
|
132.7
|
|
|
66.1
|
|
|
13.1
|
|
|
211.9
|
|
|
43.7
|
|
|
44.7
|
|
|
(72.4)
|
|
|
—
|
|
|
227.9
|
|
Net income (loss)
|
|
691.6
|
|
|
203.5
|
|
|
39.0
|
|
|
934.1
|
|
|
112.6
|
|
|
261.1
|
|
|
(106.4)
|
|
|
—
|
|
|
1,201.4
|
|
Net income (loss) attributed to common shareholders
|
|
690.4
|
|
|
203.5
|
|
|
39.0
|
|
|
932.9
|
|
|
112.6
|
|
|
260.8
|
|
|
(106.4)
|
|
|
—
|
|
|
1,199.9
|
|
Capital expenditures and asset acquisitions
|
|
1,382.4
|
|
|
652.7
|
|
|
144.3
|
|
|
2,179.4
|
|
|
—
|
|
|
661.8
|
|
|
33.1
|
|
|
—
|
|
|
2,874.3
|
|
Total assets (1)
|
|
24,599.2
|
|
|
7,471.8
|
|
|
1,336.2
|
|
|
33,407.2
|
|
|
1,764.7
|
|
|
4,455.2
|
|
|
762.2
|
|
|
(3,361.2)
|
|
|
37,028.1
|
|
(1) Total assets at December 31, 2020 reflect an elimination of $1,824.5 million for all lease activity between We Power and WE.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
|
|
|
|
|
|
|
|
|
2019 (in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Electric Transmission
|
|
Non-Utility Energy Infrastructure
|
|
Corporate and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
External revenues
|
|
$
|
5,647.1
|
|
|
$
|
1,357.1
|
|
|
$
|
426.0
|
|
|
$
|
7,430.2
|
|
|
$
|
—
|
|
|
$
|
88.5
|
|
|
$
|
4.4
|
|
|
$
|
—
|
|
|
$
|
7,523.1
|
|
Intersegment revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
407.4
|
|
|
—
|
|
|
(407.4)
|
|
|
—
|
|
Other operation and maintenance
|
|
1,591.3
|
|
|
461.1
|
|
|
98.5
|
|
|
2,150.9
|
|
|
—
|
|
|
19.7
|
|
|
14.0
|
|
|
0.2
|
|
|
2,184.8
|
|
Depreciation and amortization
|
|
617.0
|
|
|
181.3
|
|
|
27.5
|
|
|
825.8
|
|
|
—
|
|
|
92.0
|
|
|
24.3
|
|
|
(15.8)
|
|
|
926.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of transmission affiliates
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
127.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
127.6
|
|
Interest expense
|
|
572.0
|
|
|
59.0
|
|
|
8.5
|
|
|
639.5
|
|
|
13.1
|
|
|
62.1
|
|
|
140.9
|
|
|
(354.1)
|
|
|
501.5
|
|
Income tax expense (benefit)
|
|
35.2
|
|
|
60.2
|
|
|
13.6
|
|
|
109.0
|
|
|
27.1
|
|
|
59.9
|
|
|
(71.0)
|
|
|
—
|
|
|
125.0
|
|
Net income (loss)
|
|
651.1
|
|
|
170.3
|
|
|
43.2
|
|
|
864.6
|
|
|
87.4
|
|
|
245.5
|
|
|
(62.8)
|
|
|
—
|
|
|
1,134.7
|
|
Net income (loss) attributed to common shareholders
|
|
649.9
|
|
|
170.3
|
|
|
43.2
|
|
|
863.4
|
|
|
87.4
|
|
|
246.0
|
|
|
(62.8)
|
|
|
—
|
|
|
1,134.0
|
|
Capital expenditures and asset acquisitions
|
|
1,378.6
|
|
|
624.9
|
|
|
109.1
|
|
|
2,112.6
|
|
|
—
|
|
|
389.9
|
|
|
26.5
|
|
|
—
|
|
|
2,529.0
|
|
Total assets (1)
|
|
23,934.8
|
|
|
6,932.5
|
|
|
1,237.8
|
|
|
32,105.1
|
|
|
1,723.1
|
|
|
3,654.1
|
|
|
814.0
|
|
|
(3,344.5)
|
|
|
34,951.8
|
|
(1) Total assets at December 31, 2019 reflect an elimination of $1,896.7 million for all lease activity between We Power and WE.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
134
|
WEC Energy Group, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
|
|
|
|
|
|
|
|
|
2018 (in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Electric Transmission
|
|
Non-Utility Energy Infrastructure
|
|
Corporate and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
External revenues
|
|
$
|
5,794.7
|
|
|
$
|
1,400.0
|
|
|
$
|
438.2
|
|
|
$
|
7,632.9
|
|
|
$
|
—
|
|
|
$
|
37.9
|
|
|
$
|
8.7
|
|
|
$
|
—
|
|
|
$
|
7,679.5
|
|
Intersegment revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
430.5
|
|
|
—
|
|
|
(430.5)
|
|
|
—
|
|
Other operation and maintenance
|
|
2,076.1
|
|
|
472.3
|
|
|
101.0
|
|
|
2,649.4
|
|
|
—
|
|
|
12.6
|
|
|
1.8
|
|
|
(393.3)
|
|
|
2,270.5
|
|
Depreciation and amortization
|
|
546.6
|
|
|
170.3
|
|
|
24.1
|
|
|
741.0
|
|
|
—
|
|
|
75.7
|
|
|
29.1
|
|
|
—
|
|
|
845.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of transmission affiliates
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
136.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
136.7
|
|
Interest expense
|
|
200.7
|
|
|
51.2
|
|
|
8.7
|
|
|
260.6
|
|
|
0.3
|
|
|
63.7
|
|
|
125.8
|
|
|
(5.3)
|
|
|
445.1
|
|
Income tax expense (benefit)
|
|
46.7
|
|
|
51.8
|
|
|
15.9
|
|
|
114.4
|
|
|
53.7
|
|
|
73.9
|
|
|
(72.2)
|
|
|
—
|
|
|
169.8
|
|
Net income (loss)
|
|
618.2
|
|
|
147.1
|
|
|
44.1
|
|
|
809.4
|
|
|
82.8
|
|
|
228.4
|
|
|
(60.1)
|
|
|
—
|
|
|
1,060.5
|
|
Net income (loss) attributed to common shareholders
|
|
617.0
|
|
|
147.1
|
|
|
44.1
|
|
|
808.2
|
|
|
82.8
|
|
|
228.4
|
|
|
(60.1)
|
|
|
—
|
|
|
1,059.3
|
|
Capital expenditures and asset acquisitions
|
|
1,466.1
|
|
|
547.1
|
|
|
103.6
|
|
|
2,116.8
|
|
|
—
|
|
|
260.6
|
|
|
39.7
|
|
|
—
|
|
|
2,417.1
|
|
Total assets (1)
|
|
23,407.0
|
|
|
6,483.3
|
|
|
1,147.9
|
|
|
31,038.2
|
|
|
1,665.3
|
|
|
3,227.2
|
|
|
959.6
|
|
|
(3,414.5)
|
|
|
33,475.8
|
|
(1) Total assets at December 31, 2018 reflect an elimination of $1,968.5 million for all lease activity between We Power and WE.
NOTE 23—VARIABLE INTEREST ENTITIES
The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.
We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to PPAs, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.
Investment in Transmission Affiliates
We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. Therefore, we account for ATC as an equity method investment. At December 31, 2020 and 2019, our equity investment in ATC was $1,733.5 million and $1,684.7 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC.
We also own approximately 75% of ATC Holdco, a separate entity formed in December 2016 to invest in transmission-related projects outside of ATC's traditional footprint. We have determined that ATC Holdco is a variable interest entity but consolidation is not required since we are not ATC Holdco's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC Holdco's economic performance. Therefore, we account for ATC Holdco as an equity method investment. At December 31, 2020 and 2019, our equity investment in ATC Holdco was $30.8 million and $36.1 million, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC Holdco.
See Note 21, Investment in Transmission Affiliates, for more information, including any significant assets and liabilities related to ATC and ATC Holdco recorded on our balance sheets.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
135
|
WEC Energy Group, Inc.
|
Power Purchase Agreement
We have a PPA that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately one year. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the PPA.
We have $13.6 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments.
NOTE 24—COMMITMENTS AND CONTINGENCIES
We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.
Unconditional Purchase Obligations
Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time.
The wind generation facilities that are part of our non-utility energy infrastructure segment have obligations to distribute and sell electricity through long-term offtake agreements with their customers for all of the energy produced. These projects also enter into related easements and other agreements associated with the generating facilities.
The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2020, including those of our subsidiaries.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period
|
(in millions)
|
|
Date Contracts Extend Through
|
|
Total Amounts Committed
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
2025
|
|
Later Years
|
Electric utility:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear
|
|
2033
|
|
$
|
7,843.9
|
|
|
$
|
501.1
|
|
|
$
|
531.2
|
|
|
$
|
563.1
|
|
|
$
|
596.8
|
|
|
$
|
632.6
|
|
|
$
|
5,019.1
|
|
Coal supply and transportation
|
|
2024
|
|
600.1
|
|
|
257.8
|
|
|
190.6
|
|
|
151.0
|
|
|
0.7
|
|
|
—
|
|
|
—
|
|
Purchased power
|
|
2051
|
|
339.7
|
|
|
58.2
|
|
|
51.6
|
|
|
46.5
|
|
|
43.4
|
|
|
44.6
|
|
|
95.4
|
|
Natural gas utility:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supply and transportation
|
|
2048
|
|
1,805.8
|
|
|
337.4
|
|
|
318.1
|
|
|
236.7
|
|
|
162.5
|
|
|
96.4
|
|
|
654.7
|
|
Non-utility energy infrastructure:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased power
|
|
2061
|
|
380.1
|
|
|
18.4
|
|
|
18.2
|
|
|
18.0
|
|
|
18.1
|
|
|
18.5
|
|
|
288.9
|
|
Natural gas storage and transportation
|
|
2048
|
|
9.8
|
|
|
6.7
|
|
|
1.3
|
|
|
0.8
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
Total
|
|
|
|
$
|
10,979.4
|
|
|
$
|
1,179.6
|
|
|
$
|
1,111.0
|
|
|
$
|
1,016.1
|
|
|
$
|
821.5
|
|
|
$
|
792.1
|
|
|
$
|
6,059.1
|
|
Environmental Matters
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO2, NOx, fine particulates, mercury, and GHGs; water intake and discharges; management of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
136
|
WEC Energy Group, Inc.
|
We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including:
•the development of additional sources of renewable electric energy supply;
•the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems;
•the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules;
•the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects;
•the retirement of older coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation;
•the beneficial use of ash and other products from coal-fired and biomass generating units;
•the remediation of former manufactured gas plant sites; and
•the reduction of methane emissions across our natural gas distribution system by upgrading infrastructure.
Air Quality
National Ambient Air Quality Standards
After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, creating a more stringent standard than the 2008 NAAQS. The 2015 ozone standard lowered the 8-hour limit for ground-level ozone. In December 2020, the EPA completed its 5-year review of the ozone standard and issued a final decision to retain, without any changes, the existing 2015 standard.
The EPA issued final nonattainment area designations for the 2015 standard in April 2018. The following counties within our service territories were designated as partial nonattainment: Door, Kenosha, Sheboygan, Manitowoc, and Northern Milwaukee/Ozaukee. This re-designation was challenged in the D.C. Circuit Court of Appeals in Clean Wisconsin et al. v. U.S. Environmental Protection Agency. Petitioners in that case have argued that additional portions of Milwaukee, Waukesha, Ozaukee, and Washington Counties (among others) should be designated as nonattainment for ozone. In November 2019, the D.C. Circuit Court of Appeals heard oral arguments for that case. A decision was issued in July 2020 remanding the rule to the EPA for further evaluation. We expect that any subsequent EPA re-designation, if necessary, would take place in 2021. The State of Wisconsin submitted the "infrastructure" portion of its state implementation plan outlining how it will implement, maintain, and enforce the 2015 ozone standard. The plan is subject to EPA review and approval. Additionally, in January 2021, the WDNR issued a notice that it had prepared a draft economic impact analysis for proposed rules related to incorporating the 2015 standards into the state administrative code. We believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply with associated state or federal rules.
In addition to the 2015 ozone standard, in December 2020, the EPA completed its 5-year review of the 2012 standard for particulate matter, including fine particulate matter. The EPA determined that no revisions were necessary to the current standard. All counties within our service territories are in attainment with the 2012 standards; however, we expect that the decision to retain the 2012 standards with no changes will be challenged by certain states and non-governmental organizations.
Climate Change
The ACE rule, effective since September 2019, was vacated by the D.C. Circuit Court of Appeals in January 2021. The ACE rule replaced the CPP and provided existing coal-fired generating units with standards for achieving GHG emission reductions. It is unclear what steps the EPA will take next. The EPA could either revive an updated version of the CPP or draft a new rule to regulate GHG emissions.
In December 2018, the EPA proposed to revise the NSPS for GHG emissions from new, modified, and reconstructed fossil-fueled power plants. In the proposed rule, the EPA determined that the BSER for new, modified, and reconstructed coal units is highly efficient generation that would be equivalent to supercritical steam conditions for larger units and subcritical steam conditions for smaller units. This proposed BSER would replace the determination from the previous rule, which identified BSER as partial carbon capture and storage.
|
|
|
|
|
|
|
|
|
2020 Form 10-K
|
137
|
WEC Energy Group, Inc.
|
In January 2021, the EPA finalized the NSPS but did not address the BSER as proposed in 2018. Instead, the EPA shifted the focus to finalizing a significant contribution finding for purposes of regulating source categories for GHG emissions. While the EPA confirmed that EGUs remain a listed source category, the EPA concluded that no other source category should be listed. The EPA based its conclusion on the fact that no other source category, except for EGUs, should contribute to GHG emissions above a 3% threshold. BSER may be addressed in a future action by the EPA. If the rule is not repealed, it will become effective in March 2021. Despite this uncertainty, we continue to move forward on the ESG Progress Plan which is heavily focused on reducing GHG emissions.
The ESG Progress Plan includes the retirement of older, fossil-fueled generation, to be replaced with the construction of zero-carbon-emitting renewable generation and natural gas-fired generation. In 2019, we met and surpassed our original goal to reduce CO2 emissions by 40% below 2005 levels by 2030. In July 2020, we announced new goals to reduce CO2 emissions from our electric generation by 70% below 2005 levels by 2030 and to be net carbon neutral by 2050. We added a near-term goal in November 2020 to reduce CO2 emissions by 55% below 2005 levels by 2025. We have already retired more than 1,800 MW of coal-fired generation since the beginning of 2018. As part of the ESG Progress Plan, we expect to retire approximately 1,800 MW of additional fossil-fueled generation by 2025 and to invest in low-cost renewable energy in Wisconsin. Our plan is to replace a portion of the retired capacity by building and owning a combination of natural gas-fired generation and zero-carbon-emitting renewable generation facilities.
We also have a goal to decrease the rate of methane emissions from the natural gas distribution lines in our network by 30% per mile by the year 2030 from a 2011 baseline. We were over half way toward meeting that goal at the end of 2020.
We are required to report our CO2 equivalent emissions from the electric generating facilities we operate under the EPA Greenhouse Gases Reporting Program. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 20.1 million metric tonnes to the EPA for 2020. The level of CO2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO.
We are also required to report CO2 equivalent emissions related to the natural gas that our natural gas utilities distribute and sell. Based upon our preliminary analysis of the data, we estimate that we will report CO2 equivalent emissions of approximately 27.4 million metric tonnes to the EPA for 2020.
National Emission Standards for Hazardous Air Pollutants – Major Source Classification
In November 2020, the EPA published a final rule to eliminate the "once-in-always-in" policy regarding major and area source classifications under the National Emission Standards for Hazardous Air Pollutants. The final rule revised the definition of "major source" to allow for the reclassification as an area source when the source's potential to emit hazardous air pollutants meets certain criteria. Technical corrections to this final rule were published in December 2020. We do not expect the revisions to the major source classification will have a material impact on our financial condition or results of operations.
Cross-State Air Pollution Rule Update Rule Revision
In 2015, the EPA determined that several upwind states had failed to submit state implementation plans that addressed their "Good Neighbor" obligations (i.e., the states projected NOx emissions significantly contribute to a continuing downwind nonattainment and/or maintenance problem); therefore, by statute, the EPA was required to issue a federal implementation plan. In October 2020, the EPA proposed a CSAPR update rule revision that keeps nine of the 21 CSAPR affected states (including Wisconsin) as a Group 2 NOx ozone season trading program source and found that the prior CSAPR update is sufficient to meet its "Good Neighbor" obligations. No further NOx reductions would be needed within these nine states. We do not expect that the proposed rule, if finalized, will have a material impact on our financial condition or results of operations.
Water Quality
Clean Water Act Cooling Water Intake Structure Rule
In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act that requires the location, design, construction, and capacity of cooling water intake structures at existing power plants to reflect the BTA for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.
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2020 Form 10-K
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138
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WEC Energy Group, Inc.
|
We have received BTA determinations for OC 5 through OC 8, Weston Units 2, 3, and 4, and VAPP. Although we currently believe that existing technology at the PWGS satisfies the BTA requirements, final determinations will not be made until the discharge permit is renewed for this facility, which is expected to be in 2021. We anticipate that the permit renewal will include a final BTA determination to address all of the Section 316(b) rule requirements.
As a result of past capital investments completed to address Section 316(b) compliance at WE and WPS, we believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant additional costs to comply with this regulation.
Steam Electric Effluent Limitation Guidelines
The EPA's final 2015 ELG rule took effect in January 2016 and was modified in 2020 to revise the treatment technology requirements related to BATW and wet FGD wastewaters at existing facilities. The latest compliance date under the ELG rule is December 31, 2023. This rule created new requirements for several types of power plant wastewaters. The two new requirements that affect WE and WPS relate to discharge limits for BATW and wet FGD wastewater. As a result of past capital investments at WE and WPS, we believe our fleet is well positioned to meet the existing ELG regulations. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. There will, however, need to be modifications to the BATW systems at Weston Unit 3 and OC 7 and OC 8. Wastewater treatment system modifications will be required for wet FGD discharges and site wastewater from the OCPP and ERGS units. Based on engineering cost estimates, we expect that compliance with the ELG rule will require approximately $110 million in capital investment.
Land Quality
Manufactured Gas Plant Remediation
We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.
In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.
We have established the following regulatory assets and reserves for manufactured gas plant sites as of December 31:
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(in millions)
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2020
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2019
|
Regulatory assets
|
|
$
|
638.2
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|
$
|
685.5
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|
Reserves for future environmental remediation
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|
532.9
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589.2
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Renewables, Efficiency, and Conservation
Wisconsin Legislation
In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources annually. WE and WPS have achieved their required renewable energy percentages of 8.27% and 9.74%, respectively, by constructing various wind parks, a solar park, a biomass facility, and by also relying on renewable energy purchases. WE and WPS continue to review their renewable energy portfolios and acquire cost-effective renewables as needed to meet their
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2020 Form 10-K
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139
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WEC Energy Group, Inc.
|
requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and each utility funds the program based on 1.2% of its annual retail operating revenues.
Michigan Legislation
In December 2016, Michigan enacted Act 342, which required 12.5% of the state's electric energy to come from renewables for 2019 and 2020, and energy optimization (efficiency) targets up to 1% annually. The renewable requirement increased to 15.0% for 2021. UMERC was in compliance with its requirements under this statute as of December 31, 2020. The legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective.
Enforcement and Litigation Matters
We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material impact on our financial condition or results of operations.
Consent Decrees
Wisconsin Public Service Corporation – Weston and Pulliam Power Plants
In November 2009, the EPA issued an NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam power plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013.
With the retirement of Pulliam Units 7 and 8 in October 2018, WPS completed the mitigation projects required by the Consent Decree and received a completeness letter from the EPA in October 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. We are working with the EPA on a closeout process for the Consent Decree.
Joint Ownership Power Plants – Columbia and Edgewater
In December 2009, the EPA issued an NOV to Wisconsin Power and Light Company, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light Company, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, the Edgewater 4 generating unit was retired in September 2018. See Note 6, Regulatory Assets and Liabilities, for more information about the retirement. Wisconsin Power and Light Company has started the process to close out this Consent Decree.
NOTE 25—SUPPLEMENTAL CASH FLOW INFORMATION
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Year Ended December 31
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(in millions)
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|
2020
|
|
2019
|
|
2018
|
Cash paid for interest, net of amount capitalized
|
|
$
|
492.9
|
|
|
$
|
485.9
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|
|
$
|
441.5
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Cash paid (received) for income taxes, net
|
|
27.9
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|
|
(24.9)
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|
|
16.3
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|
Significant non-cash investing and financing transactions:
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|
|
|
|
|
|
Accounts payable related to construction costs
|
|
153.1
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|
|
159.9
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|
|
65.9
|
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Non-cash capital contributions from noncontrolling interest
|
|
—
|
|
|
21.0
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|
|
—
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|
Receivable related to corporate-owned life insurance proceeds
|
|
—
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—
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|
|
7.7
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The statements of cash flows include our activity related to cash, cash equivalents, and restricted cash. Our restricted cash primarily consists of the cash held in the Integrys rabbi trust, which is used to fund participants' benefits under the Integrys deferred
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2020 Form 10-K
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140
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WEC Energy Group, Inc.
|
compensation plan and certain Integrys non-qualified pension plans. All assets held within the rabbi trust are restricted as they can only be withdrawn from the trust to make qualifying benefit payments. Our restricted cash also includes the restricted cash we received when WECI acquired ownership interests in certain wind generation projects. This cash is restricted as it can only be used to pay for any remaining costs associated with the construction of these wind generation facilities. See Note 2, Acquisitions, for more information on the acquisitions of these wind generation projects.
The following table reconciles the cash, cash equivalents, and restricted cash amounts reported within the balance sheets at December 31 to the total of these amounts shown on the statements of cash flows:
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(in millions)
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2020
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|
2019
|
|
2018
|
Cash and cash equivalents
|
|
$
|
24.8
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|
|
$
|
37.5
|
|
|
$
|
84.5
|
|
Restricted cash included in other current assets
|
|
—
|
|
|
—
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|
|
2.5
|
|
Restricted cash included in other long term assets
|
|
47.8
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|
|
44.8
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|
|
59.1
|
|
Cash, cash equivalents, and restricted cash
|
|
$
|
72.6
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|
|
$
|
82.3
|
|
|
$
|
146.1
|
|
NOTE 26—REGULATORY ENVIRONMENT
Coronavirus Disease – 2019
The global outbreak of COVID-19 was declared a pandemic by the WHO and the CDC. COVID-19 has spread globally, including throughout the United States and, in turn, our service territories. Each of the states in which our regulated utilities operate declared a public health emergency and issued shelter-in-place orders in response to the COVID-19 pandemic. All of the shelter-in-place orders have since expired or been lifted. The PSCW, the ICC, the MPUC, and the MPSC have all issued written orders requiring certain actions to ensure that essential utility services were, and continue to be, available to customers in their respective jurisdictions. A summary of these orders is included below.
Wisconsin
On March 24, 2020, the PSCW issued two orders in response to the COVID-19 pandemic. The first order required all public utilities in the state of Wisconsin, including WE, WPS, and WG, to temporarily suspend disconnections, the assessment of late fees, and deposit requirements for all customer classes. In addition, it required utilities to reconnect customers that were previously disconnected, offer deferred payment arrangements to all customers, and streamline the application process for customers applying for utility service.
In the second order issued on March 24, 2020, the PSCW authorized Wisconsin utilities to defer expenditures and certain foregone revenues resulting from compliance with the first order, and expenditures as otherwise incurred to ensure safe, reliable, and affordable access to utility services during the declared public health emergency. The PSCW has affirmed that this authorization for deferral includes the incremental increase in uncollectible expense above what is currently being recovered in rates. As WE, WPS, and WG already have a cost recovery mechanism in place to recover uncollectible expense for residential customers, this new deferral only impacts the recovery of uncollectible expense for their commercial and industrial customers. See Note 5, Credit Losses, for information regarding changes to our allowance for credit losses related to COVID-19. As of December 31, 2020, the total amount deferred at our Wisconsin utilities related to the COVID-19 pandemic was not significant. The PSCW will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings.
On June 26, 2020, the PSCW issued a written order providing a timeline for the lifting of the temporary provisions required in the first March 24, 2020 order. Utilities were allowed to disconnect commercial and industrial customers and require deposits for new service as of July 25, 2020 and July 31, 2020, respectively. After August 15, 2020, utilities were no longer required to offer deferred payment arrangements to all customers. Additionally, utilities were authorized to reinstate late fees except for the period between the first order and this supplemental order. Our Wisconsin utilities resumed charging late payment fees in late August 2020. Late payment fees were not charged on outstanding balances that were billed between the first order and late August 2020.
The PSCW extended the moratorium on disconnections of residential customers until November 1, 2020. In accordance with Wisconsin regulations, utilities are generally not allowed to disconnect residential customers for non-payment during the winter moratorium, which began on November 1 and ends on April 15. Utilities are allowed to continue assessing late fees during the winter moratorium.
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2020 Form 10-K
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141
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WEC Energy Group, Inc.
|
Illinois
On March 18, 2020, the ICC issued an order to all Illinois utilities, including PGL and NSG, requiring, among other things, a moratorium on disconnections of utility service and a suspension of late fees and penalties during the declared public health emergency. These provisions applied to all utility customer classes. Illinois utilities were also required to temporarily enact more flexible credit and collections procedures.
On June 18, 2020, the ICC issued a written order approving a settlement agreement negotiated by Illinois utilities, ICC staff, and certain intervenors. The key terms of the settlement agreement included the following:
•The moratorium on disconnections and the suspension of late fees and penalties were extended until July 26, 2020.
•Customers disconnected after June 18, 2019 could be reconnected without being assessed a reconnection fee if reconnection was requested prior to August 25, 2020.
•Flexible deferred payment arrangements were required to be offered to residential and commercial and industrial customers for an extended period of time and with reduced down payment requirements.
•Deposit requirements were waived until August 25, 2020 for all residential customers, and were waived for an additional four months for residential customers that verbally expressed financial hardship.
•PGL and NSG were required to establish a bill payment assistance program with approximately $12.0 million and $1.2 million, respectively, available for eligible residential customers to provide relief from high arrearages.
In addition to the above, the settlement agreement authorized PGL and NSG to implement a SPC rider for the recovery of incremental direct costs resulting from COVID-19, foregone late fees and reconnection charges, and the costs associated with their bill payment assistance programs. PGL and NSG began recovering costs under the SPC rider on October 1, 2020. Amounts deferred under the SPC rider are being recovered over 36 months and will be subject to review and reconciliation by the ICC. As of December 31, 2020, PGL's and NSG's regulatory assets related to the COVID-19 pandemic were $19.4 million, collectively.
Subsequent to the approval of the settlement agreement, and at the request of the ICC, PGL and NSG agreed to extend the moratorium on disconnections for qualified low-income residential customers and residential customers expressing financial hardship through March 31, 2021. The annual winter moratorium in Illinois that generally prohibits PGL and NSG from disconnecting residential customers for non-payment began on December 1 and ends on March 31. Additionally, PGL and NSG voluntarily extended the availability of deferred payment arrangements with reduced down payment requirements to residential and commercial and industrial customers until March 31, 2021.
Minnesota
On May 22, 2020, the MPUC issued a written order authorizing Minnesota utilities, including MERC, to track and defer COVID-19 related expenses and certain foregone revenues. The MPUC will review the recoverability and examine the prudency of any deferred amounts in future rate proceedings. As of December 31, 2020, amounts deferred at MERC related to the COVID-19 pandemic were not significant.
On June 18, 2020, the MPUC verbally ordered Minnesota utilities to temporarily suspend disconnections and waive reconnection fees, service deposits, late fees, interest, and penalties for all residential customers. In addition, utilities were required to immediately reconnect residential customers that were previously disconnected. On August 13, 2020, the MPUC issued a written order affirming these temporary provisions. The order will remain in effect until 60 days after Minnesota's declared peacetime emergency expires. Currently, the peacetime order is set to expire on March 15, 2021, meaning the MPUC's order would expire on May 14, 2021. The expiration date of Minnesota's peacetime emergency, and the corresponding expiration date of the MPUC order, are subject to change. The annual winter moratorium in Minnesota that generally prohibits MERC from disconnecting residential customers for non-payment began on October 15, 2020 and does not end until April 15, 2021.
Prior to the verbal order issued by the MPUC, MERC had voluntarily taken actions to ensure its customers continued to receive utility services during the pandemic. These actions included, but were not limited to, temporarily suspending disconnections and waiving late payment fees for residential and small commercial and industrial customers that entered into payment plans.
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2020 Form 10-K
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142
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WEC Energy Group, Inc.
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Michigan
On April 15, 2020, the MPSC issued a written order requiring Michigan utilities, including MGU and UMERC, to put certain minimum protections in place during the COVID-19 pandemic. The minimum protections required by the order include the suspension of disconnections, late payment fees, deposits, and reconnection fees for certain vulnerable customers. In addition, utilities are required to extend access to and enhance the flexibility of payment plans to customers financially impacted by COVID-19. The order will remain in effect until further notice from the MPSC.
As required in the MPSC order, MGU and UMERC filed responses with the MPSC on April 20, 2020 affirming the actions they are taking to protect customers. The actions being taken by MGU and UMERC provide protections to more customers than required by the MPSC order. These actions include suspending disconnections for all residential customers, waiving deposit requirements for new service, suspending the assessment of late fees for customers that have entered into payment plans, and enhancing payment plan options for all customers.
The April 15, 2020 MPSC order also authorized all Michigan utilities to defer, for potential future recovery, uncollectible expense incurred on or after March 24, 2020 that exceeds the amounts being recovered in rates. On July 23, 2020, the MPSC issued an order denying Michigan utilities' ability to defer additional COVID-19 related expenses and certain foregone revenues. The MPSC indicated that utilities can still seek recovery of these costs and foregone revenues by filing additional information on the specifics of their request. MGU and UMERC filed comments with the MPSC on November 2, 2020 indicating that they have not experienced any material additional COVID-19 related expenses or foregone revenues, but that they will continue to monitor them and will notify the MPSC if they become material. At December 31, 2020, our Michigan utilities had not recorded any deferrals related to the COVID-19 pandemic.
Tax Cuts and Jobs Act of 2017
Due to the Tax Legislation, our regulated utilities deferred for return to ratepayers, through future refunds, bill credits, riders, or reductions in other regulatory assets, the estimated tax benefit of $2,529 million that resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018. We received written orders from the PSCW and the MPSC addressing the refunding of certain of these tax benefits to ratepayers in Wisconsin and Michigan, respectively. The ICC approved the VITA in Illinois, and the MPUC addressed the impacts to MERC in its 2018 rate order. See the Variable Income Tax Adjustment Rider discussion and the 2018 Minnesota Rate Order discussion below for more information. Summaries of the Wisconsin and Michigan orders are provided below.
Wisconsin
In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order required WE's and WPS’s electric utility operations to use 80% and 40%, respectively, of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. The remaining 20% and 60% at WE and WPS, respectively, was returned to electric customers in the form of bill credits. For our Wisconsin natural gas utility operations, the PSCW indicated that 100% of the current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting was used to reduce certain regulatory assets for our electric utilities and was deferred at our natural gas utilities. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes was addressed in the rate orders issued by the PSCW in December 2019. See the 2020 and 2021 Rates discussion below for more information.
Michigan
In February 2018, the MPSC issued an order requiring Michigan utilities to make three filings related to the Tax Legislation. The first of those filings, which was filed in March 2018, prospectively addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21%. MGU and UMERC proposed providing a volumetric bill credit, subject to reconciliation and true up. In May 2018, the MPSC issued orders approving settlements that resulted in volumetric bill credits for all of MGU's and UMERC's customers effective July 1, 2018. The bill credits will remain in effect until each company's next rate proceeding.
The second filing, which was filed in July 2018, addressed the impact on base rates for the change in tax expense resulting from the federal tax rate reduction from 35% to 21% from January 1, 2018 until July 1, 2018. MGU and UMERC proposed to return the tax
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2020 Form 10-K
|
143
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WEC Energy Group, Inc.
|
savings from these months to customers via volumetric bill credits over multiple months. The MPSC issued orders approving settlements in September 2018. In accordance with the settlement orders, the savings were returned to MGU's and UMERC's customers via volumetric bill credits that were in effect from October 1, 2018 through December 31, 2018.
The third filing was filed in October 2018 and addressed the remaining impacts of the Tax Legislation on base rates – most notably the re-measurement of deferred tax balances. MGU and UMERC proposed providing a volumetric bill credit, subject to reconciliation and true up, to return these remaining impacts of the Tax Legislation to customers. The MPSC issued orders approving settlements in May 2019. The settlement orders provide for volumetric bill credits to MGU's and UMERC's customers effective June 1, 2019. For MGU's customers and UMERC's electric customers, the bill credits will remain in effect until each company's next rate proceeding. Effective July 1, 2020, the bill credits were temporarily suspended for UMERC's natural gas customers.
WE, which served one retail electric customer in Michigan, reached a settlement with that customer. That settlement was approved by the MPSC in May 2018 and addressed all base rate impacts of the Tax Legislation, which were returned to the customer through bill credits.
Wisconsin Electric Power Company, Wisconsin Public Service Corporation, and Wisconsin Gas LLC
2020 and 2021 Rates
In March 2019, WE, WPS, and WG filed applications with the PSCW to increase their retail electric, natural gas, and steam rates, as applicable, effective January 1, 2020. In August 2019, all three utilities filed applications with the PSCW for approval of settlement agreements entered into with certain intervenors to resolve several outstanding issues in each utility's respective rate case. In December 2019, the PSCW issued written orders that approved the settlement agreements without material modification and addressed the remaining outstanding issues that were not included in the settlement agreements. The new rates became effective January 1, 2020. The final orders reflect the following:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
WE
|
|
WPS
|
|
WG
|
2020 Effective rate increase (decrease)
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric (1) (2)
|
|
$
|
15.3
|
million
|
/
|
0.5%
|
|
$
|
15.8
|
million
|
/
|
1.6%
|
|
N/A
|
Gas (3)
|
|
$
|
10.4
|
million
|
/
|
2.8%
|
|
$
|
4.3
|
million
|
/
|
1.4%
|
|
$
|
(1.5)
|
million
|
/
|
(0.2)%
|
Steam
|
|
$
|
1.9
|
million
|
/
|
8.6%
|
|
N/A
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ROE
|
|
10.0%
|
|
10.0%
|
|
10.2%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common equity component average on a financial basis
|
|
52.5%
|
|
52.5%
|
|
52.5%
|
(1) Amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The WE and WPS rate orders reflect the majority of the unprotected deferred tax benefits from the Tax Legislation being amortized over two years. For WE, approximately $65 million of tax benefits will be amortized in each of 2020 and 2021. For WPS, approximately $11 million of tax benefits were amortized in 2020 and approximately $39 million will be amortized in 2021. The unprotected deferred tax benefits related to the unrecovered balances of WE's recently retired plants and its SSR regulatory asset were used to reduce the related regulatory asset. Unprotected deferred tax benefits by their nature are eligible to be returned to customers in a manner and timeline determined to be appropriate by our regulators.
(2) The WPS rate order is net of $21 million of refunds related to its 2018 earnings sharing mechanism. These refunds are being made to customers evenly over two years, with half returned in 2020 and the remainder being returned in 2021.
(3) The WE amount includes certain deferred tax expense from the Tax Legislation, and the WPS and WG amounts are net of certain deferred tax benefits from the Tax Legislation that were utilized to reduce near-term rate impact. The rate orders for all three gas utilities reflect all of the unprotected deferred tax expense and benefits from the Tax Legislation being amortized evenly over four years. For WE, approximately $5 million of previously deferred tax expense will be amortized each year. For WPS and WG, approximately $5 million and $3 million, respectively, of previously deferred tax benefits will be amortized each year. Unprotected deferred tax expense and benefits by their nature are eligible to be recovered from or returned to customers in a manner and timeline determined to be appropriate by our regulators.
In accordance with its rate order, WE filed an application with the PSCW on July 20, 2020 requesting a financing order to securitize $100 million of Pleasant Prairie power plant's book value, plus the carrying costs accrued on the $100 million during the securitization process and related fees. On November 17, 2020, the PSCW issued a written order approving the application. The securitization is expected to reduce the carrying costs for the $100 million, benefiting customers.
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2020 Form 10-K
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144
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WEC Energy Group, Inc.
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The WPS rate order allows WPS to collect the previously deferred revenue requirement for ReACT™ costs above the authorized $275.0 million level. The total cost of the ReACT™ project was $342 million. This regulatory asset will be collected from customers over eight years.
All three Wisconsin utilities will continue having an earnings sharing mechanism through 2021. The earnings sharing mechanism was modified from its previous structure to one that is consistent with other Wisconsin investor-owned utilities. Under the new earnings sharing mechanism, if the utility earns above its authorized ROE: (i) the utility retains 100.0% of earnings for the first 25 basis points above the authorized ROE; (ii) 50.0% of the next 50 basis points is refunded to customers; and (iii) 100.0% of any remaining excess earnings is refunded to customers. In addition, the rate orders also require WE, WPS, and WG to maintain residential and small commercial electric and natural gas customer fixed charges at previously authorized rates and to maintain the status quo for WE's and WPS's electric market-based rate programs for large industrial customers through 2021.
2018 and 2019 Rates
During April 2017, WE, WPS, and WG filed an application with the PSCW for approval of a settlement agreement they made with several of their commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which froze base rates through 2019 for electric, natural gas, and steam customers of WE, WPS, and WG. Based on the PSCW order, the authorized ROE for WE, WPS, and WG remained at 10.2%, 10.0%, and 10.3%, respectively, and the capital cost structure for all of our Wisconsin utilities remained unchanged through 2019.
In addition to freezing base rates, the settlement agreement extended and expanded the electric real-time market pricing program options for large commercial and industrial customers and mitigated the continued growth of certain escrowed costs at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. WE was flowing through the tax benefit of its repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While WE would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate-making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offset the negative income statement impact of holding the regulatory assets level, resulting in no change to net income.
The agreement also allowed WPS to extend through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to WPS's electric real-time market pricing program and network transmission expenses.
Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism that had been in place for WE and WG since January 2016, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WPS, or WG earned above its authorized ROE, 50% of the first 50 basis points of additional utility earnings were required to be refunded to customers. All utility earnings above the first 50 basis points were also required to be refunded to customers.
Liquefied Natural Gas Facilities
In November 2019, WE and WG filed a joint application with the PSCW requesting approval for each company to construct its own LNG facility. If approved, each facility would provide one Bcf of natural gas supply to meet peak demand without requiring the construction of additional interstate pipeline capacity. These facilities are expected to reduce the likelihood of constraints on WE's and WG's natural gas systems during the highest demand days of winter. The total cost of both projects is estimated to be approximately $370 million, with approximately half being invested by each utility. A decision from the PSCW is expected in 2021, and commercial operation of the LNG facilities is targeted for the end of 2023.
Solar Generation Projects
In August 2019, WE, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire an ownership interest in a proposed solar project, Badger Hollow II, that will be located in Iowa County, Wisconsin. Once constructed, WE will own 100 MW of this project. WE's share of the cost of this project is estimated to be $130 million. The PSCW issued a written order approving the acquisition of this project in March 2020. Commercial operation of Badger Hollow II is targeted for December 2022.
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2020 Form 10-K
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145
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WEC Energy Group, Inc.
|
In May 2018, WPS, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire ownership interests in two solar projects in Wisconsin. Badger Hollow I is located in Iowa County, Wisconsin, and Two Creeks is located in Manitowoc County, Wisconsin. The PSCW approved the acquisition of these two projects in April 2019. Commercial operation was achieved in November 2020 for Two Creeks, and is targeted for the second quarter of 2021 for Badger Hollow I. WPS owns 100 MW of Two Creeks and will own 100 MW of Badger Hollow I for a total of 200 MW. WPS's share of the cost of both projects is estimated to be approximately $260 million.
Acquisition of a Wind Energy Generation Facility in Wisconsin
In October 2017, WPS, along with two other unaffiliated utilities, entered into an agreement to purchase Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 138 MW. The FERC approved the transaction in January 2018, and the PSCW approved the transaction in March 2018. The transaction closed in April 2018. See Note 2, Acquisitions, for more information.
The Peoples Gas Light and Coke Company and North Shore Gas Company
North Shore Gas Company 2021 Rate Case
On October 15, 2020, NSG filed a request with the ICC to increase its natural gas rates. NSG's request is targeting a rate increase of $7.6 million (8.5%) and reflects a 10.0% ROE and a common equity component average of 52.5%. The proposed natural gas rate increase is primarily driven by NSG's ongoing significant investment in its distribution system since its last rate review that resulted in revised base rates effective January 1, 2015. New rates are expected to be effective in September 2021.
Illinois Proceedings
In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP, which were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program, and issued a final order in January 2018. The order did not have a significant impact on PGL's existing SMP design and execution. An appeal related to the final order was filed by the Illinois AG in April 2018. In June 2019, the Illinois Appellate Court issued its ruling affirming the ICC’s final order. The appeal period has since expired for this ruling.
Qualifying Infrastructure Plant Rider
In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. This law provides natural gas utilities with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In January 2014, the ICC approved a QIP rider for PGL, which is in effect through 2023.
PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2020, PGL filed its 2019 reconciliation with the ICC, which, along with the 2018, 2017 and 2016 reconciliations, are still pending. In July 2019, the ICC approved a settlement of the 2015 reconciliation, which included a rate base reduction of $7.0 million and a $7.3 million refund to ratepayers. In February 2018, PGL agreed to a settlement of the 2014 reconciliation, which included a rate base reduction of $5.4 million and a $4.7 million refund to ratepayers.
As of December 31, 2020, there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC.
Variable Income Tax Adjustment Rider
In April 2018, the ICC approved the VITA proposed by PGL and NSG. The VITA recovers or refunds changes in income tax expense resulting from differences in income tax rates and amortization of deferred tax excesses and deficiencies (in accordance with the Tax Legislation) from the amounts used in the last PGL and NSG rate case, effective January 25, 2018.
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2020 Form 10-K
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146
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WEC Energy Group, Inc.
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Minnesota Energy Resources Corporation
2018 Minnesota Rate Order
In October 2017, MERC initiated a rate proceeding with the MPUC. In December 2018, the MPUC issued a final written order for MERC. The order authorized a retail natural gas rate increase of $3.1 million (1.26%). The rates reflect a 9.7% ROE and a common equity component average of 50.9%. The final rates were implemented on July 1, 2019. The final approved rate increase was lower than the interim rates collected from customers during 2018 and through June 30, 2019. Therefore, MERC refunded $8.2 million to its customers during the second half of 2019.
The final order addressed the various impacts of the Tax Legislation, including the remeasurement of deferred tax balances. All of the impacts from the Tax Legislation have been included in base rates. The order also approved MERC's continued use of its decoupling mechanism for residential customers. Effective January 1, 2019, MERC's small commercial and industrial customers are no longer included in the decoupling mechanism.
Michigan Gas Utilities Corporation
2021 Rate Application
In February 2020, MGU provided notification to the MPSC of its intent to file an application requesting an increase to MGU's natural gas rates to be effective January 1, 2021. However, MGU decided that it would not file a rate case during the COVID-19 pandemic and would re-evaluate the timing of the rate filing at a later date.
In May 2020, MGU filed an application with the MPSC requesting approval to defer $5.0 million of depreciation and interest expense during 2021 related to capital investments made by MGU since its last rate case. In July 2020, the MPSC issued a written order approving MGU's request. The deferral of these costs will help to mitigate the impacts from delaying the filing of the rate case.
NOTE 27—OTHER INCOME, NET
Total other income, net was as follows for the years ended December 31:
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(in millions)
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2020
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2019
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2018
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Non-service components of net periodic benefit costs
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$
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41.2
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|
|
$
|
36.2
|
|
|
$
|
26.0
|
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AFUDC – Equity
|
|
20.9
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|
|
14.4
|
|
|
15.2
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Gains (losses) from investments held in rabbi trust
|
|
12.7
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|
|
21.2
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|
(1.8)
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Other, net
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|
4.7
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|
|
30.4
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|
|
30.9
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Other income, net
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|
$
|
79.5
|
|
|
$
|
102.2
|
|
|
$
|
70.3
|
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|
|
|
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|
2020 Form 10-K
|
147
|
WEC Energy Group, Inc.
|
NOTE 28—QUARTERLY FINANCIAL INFORMATION (Unaudited)
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(in millions, except per share amounts)
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First Quarter
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Second Quarter
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Third Quarter
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Fourth Quarter
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Total
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2020
|
|
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|
|
|
|
|
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|
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Operating revenues
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|
$
|
2,108.6
|
|
|
$
|
1,548.7
|
|
|
$
|
1,651.0
|
|
|
$
|
1,933.4
|
|
|
$
|
7,241.7
|
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Operating income
|
|
626.6
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|
|
338.8
|
|
|
370.2
|
|
|
370.5
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|
|
1,706.1
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Net income attributed to common shareholders
|
|
452.5
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|
|
241.6
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|
|
266.8
|
|
|
239.0
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|
|
1,199.9
|
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Earnings per share (1)
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|
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Basic
|
|
$
|
1.43
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|
|
$
|
0.77
|
|
|
$
|
0.85
|
|
|
$
|
0.76
|
|
|
$
|
3.80
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Diluted
|
|
1.43
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|
|
0.76
|
|
|
0.84
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|
|
0.76
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|
|
3.79
|
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|
|
|
|
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|
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2019
|
|
|
|
|
|
|
|
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Operating revenues
|
|
$
|
2,377.4
|
|
|
$
|
1,590.2
|
|
|
$
|
1,608.0
|
|
|
$
|
1,947.5
|
|
|
$
|
7,523.1
|
|
Operating income
|
|
542.8
|
|
|
314.6
|
|
|
310.9
|
|
|
363.1
|
|
|
1,531.4
|
|
Net income attributed to common shareholders
|
|
420.1
|
|
|
235.7
|
|
|
234.3
|
|
|
243.9
|
|
|
1,134.0
|
|
Earnings per share (1)
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.33
|
|
|
$
|
0.75
|
|
|
$
|
0.74
|
|
|
$
|
0.77
|
|
|
$
|
3.60
|
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Diluted
|
|
1.33
|
|
|
0.74
|
|
|
0.74
|
|
|
0.77
|
|
|
3.58
|
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(1) Earnings per share for the individual quarters may not total the year ended earnings per share amount because of changes to the average number of shares outstanding and changes in incremental issuable shares throughout the year.
NOTE 29—NEW ACCOUNTING PRONOUNCEMENTS
Cloud Computing
In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The standard allows entities who are customers in hosting arrangements that are service contracts to apply the existing internal-use software guidance to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. The guidance specifies classification for capitalizing implementation costs and related amortization expense within the financial statements and requires additional disclosures. The adoption of ASU 2018-15, effective January 1, 2020, did not have a significant impact on our financial statements and related disclosures.
Disclosure Requirements for Defined Benefit Plans
In August 2018, the FASB issued ASU 2018-14, Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans. The pronouncement modifies the disclosure requirements for defined benefit pension and OPEB plans. The guidance removes disclosures that are no longer considered cost beneficial, clarifies the specific requirements of disclosures and adds disclosure requirements identified as relevant. The modifications affect annual period disclosures and must be applied on a retrospective basis to all periods presented. We adopted the disclosure provisions of ASU 2018-14, effective December 31, 2020. These disclosure modifications are included in Note 20, Employee Benefits.
Simplifying the Accounting for Income Taxes
In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes. The new standard removes certain exceptions for performing intraperiod allocation and calculating income taxes in interim periods and also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The guidance was effective for annual and interim periods beginning after December 15, 2020. The adoption of ASU 2019-12, effective January 1, 2021, did not have a significant impact on our financial statements and related disclosures.
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|
|
|
2020 Form 10-K
|
148
|
WEC Energy Group, Inc.
|
Reference Rate Reform
In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The amendments are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the impact this guidance may have on our financial statements and related disclosures.
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|
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2020 Form 10-K
|
149
|
WEC Energy Group, Inc.
|