DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Jan. 31, 2019 | Jun. 30, 2018 | |
Document and Entity Information | |||
Entity Registrant Name | WISCONSIN PUBLIC SERVICE CORP | ||
Entity Central Index Key | 107,833 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | false | ||
Entity Shell Company | false | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Public Float | $ 0 | ||
Entity Common Stock, Shares Outstanding | 23,896,962 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement [Abstract] | |||
Operating revenues | $ 1,498.5 | $ 1,485.4 | $ 1,448.2 |
Cost of sales | 602 | 573.9 | 527.6 |
Other operation and maintenance | 448 | 447.6 | 503.7 |
Depreciation and amortization | 141.9 | 139.3 | 124.1 |
Property and revenue taxes | 40.2 | 39.5 | 39.8 |
Total operating expenses | 1,232.1 | 1,200.3 | 1,195.2 |
Operating income | 266.4 | 285.1 | 253 |
Other income, net | 37.6 | 23.7 | 41.3 |
Interest expense | 53.9 | 54.2 | 48.1 |
Other expense | (16.3) | (30.5) | (6.8) |
Income before income taxes | 250.1 | 254.6 | 246.2 |
Income tax expense | 77.3 | 99.7 | 90.5 |
Net income | $ 172.8 | $ 154.9 | $ 155.7 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Cash and cash equivalents | $ 8.9 | $ 7.9 |
Accounts receivable and unbilled revenues, net of reserves of $4.2 and $4.0, respectively | 217.1 | 205 |
Accounts receivable from related parties | 26.6 | 4.4 |
Materials, supplies, and inventories | 103 | 107 |
Prepaid taxes | 41.4 | 52.7 |
Other | 9.2 | 13 |
Current assets | 406.2 | 390 |
Property, plant, and equipment, net of accumulated depreciation of $1,620.5 and $1,633.3, respectively | 4,150.1 | 3,823 |
Regulatory assets | 485.6 | 382.8 |
Goodwill | 36.4 | 36.4 |
Pension and OPEB assets | 92.8 | 62 |
Other | 46.6 | 54.5 |
Long-term assets | 4,811.5 | 4,358.7 |
Total assets | 5,217.7 | 4,748.7 |
Liabilities and Shareholders' Equity | ||
Short-term debt | 284.4 | 293.1 |
Current portion of long-term debt | 0 | 250 |
Accounts payable | 145.4 | 130.4 |
Accounts payable to related parties | 54.2 | 30 |
Other | 79.4 | 66.4 |
Current liabilities | 563.4 | 769.9 |
Long-term debt | 1,314.7 | 916.2 |
Deferred income taxes | 520.8 | 512.7 |
Deferred investment tax credits | 6.4 | 6.7 |
Regulatory liabilities | 785.7 | 689.3 |
Environmental remediation liabilities | 90.3 | 99.6 |
Pension and OPEB obligations | 37.3 | 24 |
Payables to related parties | 2.8 | 3.5 |
Other | 126.4 | 109.5 |
Long-term liabilities | 2,884.4 | 2,361.5 |
Commitments and contingencies (Note 19) | ||
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding | 95.6 | 95.6 |
Additional paid in capital | 1,115.9 | 996.1 |
Retained earnings | 558.4 | 525.6 |
Shareholder's equity | 1,769.9 | 1,617.3 |
Total liabilities and equity | $ 5,217.7 | $ 4,748.7 |
CONSOLIDATED BALANCE SHEETS (PA
CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves (in dollars) | $ 4.2 | $ 4 |
Property, plant, and equipment, accumulated depreciation (in dollars) | $ 1,620.5 | $ 1,633.3 |
Common stock, par value (in dollars per share) | $ 4 | |
Common stock, shares authorized | 32,000,000 | |
Common stock, shares issued | 23,896,962 | 23,896,962 |
Common stock, shares outstanding | 23,896,962 | 23,896,962 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Operating Activities | |||
Net income | $ 172.8 | $ 154.9 | $ 155.7 |
Reconciliation to cash provided by operating activities | |||
Depreciation and amortization | 141.9 | 139.3 | 124.1 |
Contributions and payments related to pension and OPEB plans | (0.7) | (66.7) | (1.4) |
Deferred income taxes and investment tax credits, net | 20.6 | 77.7 | 143 |
Cash received for pension plan assets transferred | 0 | 157.8 | 0 |
Change in – | |||
Collateral on deposit | 4.4 | 10.2 | (0.2) |
Accounts receivable and unbilled revenues | (28.5) | (15.8) | (33.1) |
Materials, supplies, and inventories | 4.3 | 18.9 | 20.3 |
Prepaid taxes | 11.3 | 4.6 | (9.2) |
Other current assets | 0.9 | 0.4 | 0.9 |
Accounts payable | 77.6 | (6.3) | (24.4) |
Other current liabilities | 11.9 | 1.2 | 17.7 |
Other, net | 18 | 0.4 | (4.4) |
Net cash provided by operating activities | 434.5 | 476.6 | 389 |
Investing activities | |||
Capital expenditures | (444.3) | (335.8) | (311.1) |
Acquisition of Forward Wind Energy Center | (77.1) | 0 | 0 |
Payments for assets received from WBS | (30) | (10.1) | (34.1) |
Other, net | (0.9) | 3.5 | 4.4 |
Net cash used in investing activities | (552.3) | (342.4) | (340.8) |
Financing activities | |||
Change in short-term debt | (8.7) | 116.3 | (6) |
Repayment of loan | 0 | 0 | (28.6) |
Repayment of long-term debt | (250) | (125) | 0 |
Repayment of subsidiary note to parent | 0 | 0 | (2.9) |
Issuance of long-term debt | 400 | 0 | 0 |
Payment of dividends to parent | (140) | (195) | (118.5) |
Equity contribution from parent | 120 | 75 | 105 |
Other, net | (2.5) | (0.7) | (0.2) |
Net cash provided by (used in) financing activities | 118.8 | (129.4) | (51.2) |
Net change in cash and cash equivalents | 1 | 4.8 | (3) |
Cash and cash equivalents at beginning of year | 7.9 | 3.1 | 6.1 |
Cash and cash equivalents at end of year | $ 8.9 | $ 7.9 | $ 3.1 |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions | Total | Total Common Shareholder's Equity | Common Stock | Additional Paid in Capital | Retained Earnings | WPSI TransferTotal Common Shareholder's Equity | WPSI TransferCommon Stock | WPSI TransferAdditional Paid in Capital | WPSI TransferRetained Earnings | UMERC transferTotal Common Shareholder's Equity | UMERC transferCommon Stock | UMERC transferAdditional Paid in Capital | UMERC transferRetained Earnings |
Balance at Dec. 31, 2015 | $ 1,485.9 | $ 95.6 | $ 861.8 | $ 528.5 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net income attributed to common shareholder | 155.7 | 0 | 0 | 155.7 | |||||||||
Equity contribution from parent | $ 105 | 105 | 0 | 105 | 0 | ||||||||
Payment of dividends to parent | (118.5) | 0 | 0 | (118.5) | |||||||||
Other | 0.1 | 0 | 0.1 | 0 | |||||||||
Balance at Dec. 31, 2016 | 1,628.2 | 95.6 | 966.9 | 565.7 | |||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net income attributed to common shareholder | 154.9 | 154.9 | 0 | 0 | 154.9 | ||||||||
Equity contribution from parent | 75 | 75 | 0 | 75 | 0 | ||||||||
Transfer of WPSI's ownership interest in ATC and related taxes | $ (25.3) | $ 0 | $ (25.3) | $ 0 | |||||||||
Transfer of net assets to UMERC | $ (20.6) | $ 0 | $ (20.6) | $ 0 | |||||||||
Payment of dividends to parent | (195) | 0 | 0 | (195) | |||||||||
Other | 0.1 | 0 | 0.1 | 0 | |||||||||
Balance at Dec. 31, 2017 | 1,617.3 | 1,617.3 | 95.6 | 996.1 | 525.6 | ||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Net income attributed to common shareholder | 172.8 | 172.8 | 0 | 0 | 172.8 | ||||||||
Equity contribution from parent | 120 | 120 | 0 | 120 | 0 | ||||||||
Payment of dividends to parent | (140) | 0 | 0 | (140) | |||||||||
Other | (0.2) | 0 | (0.2) | 0 | |||||||||
Balance at Dec. 31, 2018 | $ 1,769.9 | $ 1,769.9 | $ 95.6 | $ 1,115.9 | $ 558.4 |
CONSOLIDATED STATEMENTS OF CAPI
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Schedule of Capitalization | ||
Common shareholder's equity | $ 1,769.9 | $ 1,617.3 |
Total | 1,325 | 1,175 |
Unamortized debt issuance costs | (9.6) | (8.3) |
Unamortized discount, net | (0.7) | (0.5) |
Total long-term debt, including current portion | 1,314.7 | 1,166.2 |
Current portion of long-term debt | 0 | (250) |
Total long-term debt | 1,314.7 | 916.2 |
Total long-term capitalization | $ 3,084.6 | 2,533.5 |
Senior Notes (unsecured),1.65% due 2018 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 1.65% | |
Senior Notes (unsecured) | $ 0 | 250 |
Senior Notes (unsecured), 3.35% due 2021 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 3.35% | |
Senior Notes (unsecured) | $ 400 | 0 |
Senior Notes (unsecured), 6.08% due 2028 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 6.08% | |
Senior Notes (unsecured) | $ 50 | 50 |
Senior Notes (unsecured), 5.55% due 2036 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 5.55% | |
Senior Notes (unsecured) | $ 125 | 125 |
Senior Notes (unsecured), 3.671% due 2042 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 3.671% | |
Senior Notes (unsecured) | $ 300 | 300 |
Senior Notes (unsecured), 4.752% due 2044 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 4.752% | |
Senior Notes (unsecured) | $ 450 | $ 450 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Nature of Operations —We are an electric and natural gas utility company that serves customers in northeastern Wisconsin and, prior to the formation of UMERC, we also served customers in the Upper Peninsula of Michigan. We are subject to the jurisdiction of, and regulation by, the PSCW, which has general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin. In addition, we are subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. We are an indirect, wholly owned subsidiary of WEC Energy Group. In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets previously held by us, and the electric assets previously held by WE, located in the Upper Peninsula of Michigan. As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted. The financial statements include our accounts and the accounts of our former wholly owned subsidiary, WPS Leasing, which was dissolved in July 2016. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 7, Jointly Owned Utility Facilities, for more information . Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. (b) Basis of Presentation —We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (d) Operating Revenues —The following discussion includes our significant accounting policies related to operating revenues, including our adoption of ASU 2014-09, Revenues from Contracts with Customers. For additional required disclosures on disaggregation of operating revenues as required by this ASU, see Note 4, Operating Revenues . Adoption of ASU 2014-09, Revenues from Contracts with Customers On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period. We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods. We adopted the following practical expedients and optional exemptions for the implementation of this standard: • We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes. • When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts. • We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period. • We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less. • We elected to apply this standard only to contracts that are not completed as of the date of initial application. Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by 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 that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligation for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include 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. 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 Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues. (e) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2018 2017 Materials and supplies $ 48.9 $ 40.8 Fossil fuel 29.2 43.8 Natural gas in storage 24.9 22.4 Total $ 103.0 $ 107.0 Substantially all fossil fuel, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. (f) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 5, Regulatory Assets and Liabilities, for more information . (g) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the applicable regulators. Depreciation as a percent of average depreciable utility plant was 2.50% , 2.55% , and 2.58% in 2018 , 2017 , and 2016 , respectively. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 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 us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. See Note 6, Property, Plant, and Equipment, for more information . (h) Allowance for Funds Used During Construction —AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 7.72% for 2018 , 2017 , and 2016 . Our average AFUDC wholesale rates were 1.96% , 1.01% , and 3.00% for 2018 , 2017 , and 2016 , respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2018 2017 2016 AFUDC – Debt $ 1.9 $ 1.6 $ 8.1 AFUDC – Equity 4.6 4.1 19.5 (i) Asset Impairment —Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are also performed when impairment indicators are present. Our utility reporting unit containing goodwill performs an annual goodwill impairment test in the third quarter of each year. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit 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 9, Goodwill and Other Intangible Assets, for more information . Intangible assets with definite lives are reviewed for impairment on a quarterly basis. 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. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining carrying 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 carrying value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers. See Note 6, Property, Plant, and Equipment, for more information . (j) Asset Retirement Obligations —We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 8, Asset Retirement Obligations, for more information . (k) Emission Allowances —We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers. (l) Stock-Based Compensation —Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million . Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. Stock Options Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after a three -year period. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options may not be exercised within 6 months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2018 2017 2016 Stock options granted 21,265 23,300 24,485 Estimated weighted-average fair value per stock option $ 7.68 $ 7.53 $ 5.63 Assumptions used to value the options: Risk-free interest rate 1.6% – 2.5% 0.7% – 2.5% 0.4% – 1.8% Dividend yield 3.5 % 3.5 % 4.0 % Expected volatility 18.0 % 19.0 % 18.0 % Expected life (years) 5.8 6.9 7.5 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares granted to our employees have a three -year vesting period with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. 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 WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are recorded over the three -year performance period. See Note 10, Common Equity , for more information on WEC Energy Group's stock-based compensation plans. (m) Income Taxes —We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 14, Income Taxes, for more information . We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. (n) Fair Value Measurements —Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period. See Note 15, Fair Value Measurements, for more information . (o) Derivative Instruments —We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. See Note 16, Derivative Instruments, for more information . (p) Guarantees —We follow the guidance of the Guarantees Topic of the FASB ASC, which requires, under certain circumstances, that the guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee at its inception. As of December 31, 2018 , we had $20.6 million of standby letters of credit issued by financi |
ACQUISITIONS
ACQUISITIONS | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
ACQUISITIONS | 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. Acquisition of a Wind Energy Generation Facility in Wisconsin In April 2018, we, 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 our proportionate share was 44.6% , or $77.1 million . In addition, we incurred transactions costs that are recorded to a regulatory asset. Since 2008 and up until the acquisition, we purchased 44.6% of the facility’s energy output under a power purchase agreement. 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, we are entitled to our share of generating capability and output of the facility equal to our ownership interest. We are also paying our ownership share of additional capital expenditures and operating expenses. |
RELATED PARTIES
RELATED PARTIES | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
RELATED PARTIES | RELATED PARTIES We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities. We provide and receive services, property, and other items of value to and from our ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following WEC Energy Group's acquisition of Integrys on June 29, 2015, Integrys Business Support, LLC (IBS) changed its name to WBS, and a new AIA (Non-WBS AIA) went into effect. The Non-WBS AIA included WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries. It governed the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS continued to provide services to Integrys and its subsidiaries only under the existing WBS AIAs. WBS provided services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries under interim WBS AIAs. The Non-WBS AIA included no other significant changes from the prior Non-IBS AIA. The PSCW and all other relevant state commissions approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA. Services under the Non-WBS AIA were subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary were priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary were priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary were priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS were priced at cost. WBS provided several categories of services (including financial, human resource, and administrative services) to us pursuant to the WBS AIAs, which were approved, or from which we were granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the WBS AIAs. Other modifications or amendments to the WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases. A new AIA took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. All of the applicable state commissions approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater. See below for more information about the acquisition. Prior to January 1, 2017, we held a 10.37% investment in WPSI which held an approximate 34% interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our $67.2 million ownership interest in WPSI to another subsidiary of Integrys. In addition, during 2017 we transferred $41.9 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs. We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC where we are billed for services provided by WRPC. Services are billed to and from WRPC under these agreements at a fully allocated cost. Our balance sheets included the following receivables and payables related to transactions entered into with certain related parties: (in millions) December 31, 2018 December 31, 2017 Accounts receivable Service provided to ATC $ 1.2 $ 0.7 Accounts payable Network transmission services from ATC 8.8 9.0 Liability related to income tax allocation Integrys 3.5 4.1 The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2018 2017 2016 Transactions with WE (1) Natural gas sales to WE 1.9 1.6 1.9 Billings to WE 10.9 4.5 4.2 Billings from WE 17.8 (2) 28.2 9.0 Transactions with WBS (1) Billings to WBS 17.0 174.9 (3) 21.7 (3) Billings from WBS (2) 111.0 132.9 171.0 Transactions with UMERC (4) Electric sales to UMERC 15.8 16.2 — Natural gas sales to UMERC 2.7 2.5 — Transactions with Bluewater (5) Storage service fees 4.7 0.3 — Transactions related to ATC Charges to ATC for services and construction 7.9 6.2 8.6 Charges from ATC for network transmission services 106.1 107.8 109.4 Refund from ATC related to a FERC audit 6.6 — — Refund from ATC per FERC ROE order — 8.9 — Transactions with equity-method investees Rental payments to WRPC (6) 1.3 1.3 — Purchases of energy from WRPC (6) — 0.5 3.7 Charges from WRPC for services 2.4 2.2 — Charges to WRPC for operations 1.2 0.9 0.7 Equity earnings from WPSI — — 8.7 (1) Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs. (2) Includes $32.9 million , $10.1 million , and $34.1 million for the transfer of certain software assets from affiliates for the years ended December 31, 2018, 2017, and 2016, respectively. Includes $18.2 million for the transfer of certain benefit-related liabilities to WBS for the year ended December 31, 2016. (3) The year ended December 31, 2017 included $157.8 million of net cash received related to our transfer of pension trust assets in conjunction with the Integrys pension plan split. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017. Includes $7.3 million for the transfer of certain software assets to WBS for the year ended December 31, 2016. (4) UMERC became operational effective January 1, 2017. See below for more information. (5) WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information. (6) In March 2017, we terminated our purchased power agreement with WRPC and entered into an agreement with WRPC to rent 50% of its hydroelectric power generation facilities. Parent Company's Acquisition of Natural Gas Storage Facilities in Michigan In June 2017, WEC Energy Group completed its acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we entered into a long-term service agreement with a wholly owned subsidiary of Bluewater to take a portion of the storage, which was then approved by the PSCW in November 2017. Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 9,000 retail electric customers and 5,300 natural gas customers to UMERC, along with approximately 600 miles of electric distribution lines and approximately 100 miles of natural gas distribution mains. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of the net assets (including the related deferred income tax liabilities) transferred to UMERC from us as of January 1, 2017, was $20.6 million . This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WE. |
OPERATING REVENUES
OPERATING REVENUES | 12 Months Ended |
Dec. 31, 2018 | |
Revenue from Contract with Customer [Abstract] | |
OPERATING REVENUES | OPERATING REVENUES Disaggregation of Operating Revenues The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions. Comparable amounts have not been presented for the years ended December 31, 2017 and 2016 , due to our adoption of ASU 2014-09, Revenues from Contracts with Customers, under the modified retrospective method. See Note 1(d), Operating Revenues, for more information about our significant accounting policies related to operating revenues. Wisconsin Public Service Corporation Consolidated (in millions) Year ended December 31, 2018 Electric utility $ 1,192.2 Natural gas utility 305.5 Total revenues from contracts with customers 1,497.7 Other operating revenues 0.8 Total operating revenues $ 1,498.5 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues (in millions) Year ended December 31, 2018 Residential $ 381.5 Small commercial and industrial 371.4 Large commercial and industrial 238.8 Other 8.5 Total retail revenues 1,000.2 Wholesale 142.3 Resale 38.5 Other utility revenues 11.2 Total electric utility operating revenues $ 1,192.2 Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues (in millions) Year ended December 31, 2018 Residential $ 177.7 Commercial and industrial 107.6 Total retail revenues 285.3 Transport 19.7 Other utility revenues 0.5 Total natural gas utility operating revenues $ 305.5 Other Operating Revenues Other operating revenues consist primarily of the following: (in millions) Year ended December 31, 2018 Late payment charges $ 2.9 Leases 0.2 Alternative revenues * (2.3 ) Total other operating revenues $ 0.8 * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed in Note 1(d), Operating Revenues . |
REGULATORY ASSETS AND LIABILITI
REGULATORY ASSETS AND LIABILITIES | 12 Months Ended |
Dec. 31, 2018 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2018 2017 See Note Regulatory assets (1) (2) Pension and OPEB costs (3) $ 189.8 $ 161.3 17 Environmental remediation costs (4) 108.3 116.0 19 Plant retirements 78.1 8.3 6 Income tax related items (5) 38.1 8.2 14 Termination of a tolling agreement with Fox Energy Company LLC (6) 21.7 27.2 AROs 11.5 9.7 8 De Pere Energy Center (7) 10.1 14.0 Crane Creek wind project production tax credits (8) 0.4 22.8 Other, net 27.9 15.3 Total regulatory assets $ 485.9 $ 382.8 Balance Sheet Presentation Current assets $ 0.3 $ — Regulatory assets 485.6 382.8 Total regulatory assets $ 485.9 $ 382.8 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $14.7 million and $14.4 million at December 31, 2018 and 2017 , respectively. (2) As of December 31, 2018 , we had $31.9 million of regulatory assets not earning a return and $5.3 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures, as well as our electric real-time market pricing program. The other regulatory assets in the table either earn a return 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, 2018 , we had made cash expenditures of $18.0 million related to these environmental remediation costs. The remaining $90.3 million represents our estimated future cash expenditures. (5) For information on the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment . (6) Represents an early termination fee of a tolling agreement we had with the Fox Energy Center. Prior to the purchase of the Fox Energy Center in 2013, we supplied natural gas for the facility and purchased capacity and the associated energy output under the tolling agreement. We are authorized recovery of this asset over a nine -year period that began on January 1, 2014. (7) Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023. (8) In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits and recorded regulatory assets. In May 2018, the PSCW issued an order requiring us to use a portion of our tax benefits from the Tax Legislation that was signed into law in December 2017 to reduce the regulatory assets related to our Crane Creek wind project production tax credits. See Note 21, Regulatory Environment, for more information . The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2018 2017 See Note Regulatory liabilities Income tax related items (1) $ 418.8 $ 393.8 14 Removal costs (2) 241.8 238.9 Pension and OPEB costs (3) 72.6 30.2 17 Earnings sharing mechanism 21.2 — 21 Energy costs refundable through rate adjustments (4) 14.3 8.2 Electric transmission costs 9.7 6.0 21 Other, net 14.5 20.1 Total regulatory liabilities $ 792.9 $ 697.2 Balance Sheet Presentation Current liabilities $ 7.2 $ 7.9 Regulatory liabilities 785.7 689.3 Total regulatory liabilities $ 792.9 $ 697.2 (1) For information on the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment . (2) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. (3) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (4) Represents an over-collection of energy costs that will be refunded to customers in the future. When the rates we charge to customers include energy costs that are higher than our actual energy costs, any over-collection outside of the allowable energy cost price variance is refunded to customers. |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT, AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following utility and non-utility assets at December 31: (in millions) 2018 2017 Electric – generation $ 2,831.2 $ 2,624.9 Electric – distribution 1,510.0 1,361.9 Natural gas – distribution, storage, and transmission 910.6 846.4 Property, plant, and equipment to be retired — 57.9 Other 351.9 287.6 Less: Accumulated depreciation 1,620.1 1,479.1 Net 3,983.6 3,699.6 CWIP 166.0 121.4 Net utility property, plant, and equipment 4,149.6 3,821.0 Non-utility property, plant, and equipment 0.9 2.3 Less: Accumulated depreciation 0.4 0.4 Net 0.5 1.9 CWIP — 0.1 Net non-utility property, plant, and equipment 0.5 2.0 Total property, plant, and equipment $ 4,150.1 $ 3,823.0 Utility Segment Plant to be Retired We have evaluated future plans for our older and less efficient fossil fuel generating units and have retired our plants identified below. In December 2017, a severance liability in the amount of $3.6 million was recorded in other current liabilities related to these plant retirements. (in millions) Severance liability at December 31, 2017 $ 3.6 Severance payments (0.8 ) Total severance liability at December 31, 2018 $ 2.8 Pulliam Power Plant In connection with a MISO ruling, we retired Pulliam Units 7 and 8 effective October 21, 2018. The carrying value of the Pulliam units was $33.8 million at December 31, 2018 . This amount included the net book value of $57.2 million at December 31, 2018 , which was classified as a regulatory asset on our balance sheet. In addition, a $23.4 million cost of removal reserve related to the Pulliam units was classified as a regulatory liability at December 31, 2018 . We continue to amortize this regulatory asset on a straight-line basis 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. We have FERC approval to continue to collect the carrying value of the Pulliam power plant using the approved composite depreciation rates, in addition to a return on the remaining carrying value. FERC has completed its prudency review of Pulliam, concluding that the retirement of this plant was prudent. We will address the accounting and regulatory treatment related to the retirement of the Pulliam power plant with the PSCW in conjunction with our anticipated 2019 rate case. See Note 19, Commitments and Contingencies, for more information . Edgewater Unit 4 The Edgewater 4 generating unit was retired effective September 28, 2018. The carrying value of the generating unit was $8.1 million at December 31, 2018 . This amount included the net book value of our ownership share of this generating unit of $10.0 million , which was classified as a regulatory asset on our balance sheet. In addition, a $1.9 million cost of removal reserve related to the Edgewater 4 generating unit was classified as a regulatory liability at December 31, 2018 . We continue to amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before this generating unit was retired. Amortization is included in depreciation and amortization in the income statement. We have FERC approval to continue to collect the carrying value of the Edgewater 4 generating unit using the approved composite depreciation rates, in addition to a return on the remaining carrying value. FERC has completed its prudency review of Edgewater 4, concluding that the retirement of this plant was prudent. We will address the accounting and regulatory treatment related to the retirement of the Edgewater 4 generating unit with the PSCW in conjunction with our anticipated 2019 rate case. See Note 19, Commitments and Contingencies, for more information . |
JOINTLY OWNED UTILITY FACILITIE
JOINTLY OWNED UTILITY FACILITIES | 12 Months Ended |
Dec. 31, 2018 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
JOINTLY OWNED UTILITY FACILITIES | JOINTLY OWNED UTILITY FACILITIES We hold a joint ownership interest in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We also pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. Information related to jointly owned utility facilities at December 31, 2018 was as follows: (in millions, except for percentages and MW) Weston Unit 4 Columbia Energy Center Units 1 and 2 (2) Forward Wind Energy Center Ownership 70.0 % 28.1 % 44.6 % Our share of rated capacity (MW) (1) 384.9 314.8 8.7 In-service date 2008 1975 and 1978 2008 Property, plant, and equipment $ 615.4 $ 438.8 $ 123.7 Accumulated depreciation $ (205.2 ) $ (132.2 ) $ (43.7 ) CWIP $ 1.9 $ 0.3 $ 0.1 (1) Values are primarily based on the net dependable capacity ratings for summer 2019 using historical generation. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Columbia Energy Center (Columbia) is jointly owned by Wisconsin Power and Light (WPL), Madison Gas and Electric (MGE), and us. In October 2016, WPL received an order from the PSCW approving amendments to the Columbia joint operating agreement between the parties allowing MGE and us to forgo certain capital expenditures at Columbia. As a result, WPL will incur these capital expenditures in exchange for a proportional increase in its ownership share of Columbia. Based upon the additional capital expenditures WPL expects to incur through June 1, 2020, our ownership interest would decrease to 27.5% . Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. We have supplied our own financing for all jointly owned projects. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS We have recorded AROs primarily for asbestos abatement at certain generation facilities, office buildings, and service centers; the dismantling of wind generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the closure of fly-ash landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the applicable regulators. 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) 2018 2017 2016 Balance as of January 1 $ 34.1 $ 32.6 $ 32.7 Accretion 1.8 1.6 1.5 Additions and revisions to estimated cash flows 16.6 (1) 0.4 (1.6 ) (2) Liabilities settled (1.7 ) (0.5 ) — Balance as of December 31 $ 50.8 $ 34.1 $ 32.6 (1) AROs increased $10.7 million in 2018 due to revisions made to estimated cash flows for the abatement of asbestos at our Pulliam power plant. A $5.6 million ARO was also recorded during 2018 for the legal requirement to dismantle, at retirement, the wind generation project known as Forward Wind Energy Center. See Note 2, Acquisitions, for more information on Forward Wind Energy Center. (2) During 2016, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs. |
GOODWILL AND OTHER INTANGIBLE A
GOODWILL AND OTHER INTANGIBLE ASSETS | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL AND OTHER INTANGIBLE ASSETS | GOODWILL AND OTHER INTANGIBLE ASSETS Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. We had no changes to the carrying amount of goodwill during the years ended December 31, 2018 and 2017 . In the third quarter of 2018 , we completed our annual goodwill impairment test, and no impairment resulted from this test. The identifiable intangible assets other than goodwill listed below are classified as other long-term assets on our balance sheets. December 31, 2018 December 31, 2017 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 8.3 $ (6.8 ) $ 1.5 $ 8.3 $ (5.6 ) $ 2.7 Unamortized intangible assets 0.4 — 0.4 0.4 — 0.4 Total intangible assets $ 8.7 $ (6.8 ) $ 1.9 $ 8.7 $ (5.6 ) $ 3.1 * Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining amortization period at December 31, 2018 , was approximately one year . |
COMMON EQUITY
COMMON EQUITY | 12 Months Ended |
Dec. 31, 2018 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation 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) 2018 2017 2016 Stock options $ 0.9 $ 0.6 $ 0.5 Restricted stock 1.7 0.7 1.4 Performance units 3.6 3.3 1.5 Stock-based compensation expense $ 6.2 $ 4.6 $ 3.4 Related tax benefit $ 1.7 $ 1.8 $ 1.4 Stock-based compensation costs capitalized during 2018 , 2017 , and 2016 were not significant. Stock Options The following is a summary of our employees' WEC Energy Group stock option activity during 2018 : 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, 2018 47,785 $ 56.80 Granted 21,265 $ 66.02 Transferred 1,965 $ 62.01 Outstanding as of December 31, 2018 71,015 $ 59.70 8.0 $ 0.7 Exercisable as of December 31, 2018 7,410 $ 58.26 7.7 $ 0.1 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, 2018 . This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2018 , and the option exercise price, multiplied by the number of in-the-money stock options. As of December 31, 2018 , we expected to recognize approximately $0.6 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.6 years on a weighted-average basis. During the first quarter of 2019 , the Compensation Committee awarded 21,638 non-qualified WEC Energy Group stock options with an exercise price of $68.18 and a weighted-average grant date fair value of $8.60 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restricted Shares The following is a summary of our employees' WEC Energy Group restricted stock activity during 2018 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2018 11,202 $ 56.01 Granted 1,953 $ 64.99 Released (5,394 ) $ 55.86 Transferred 457 $ 57.88 Forfeited (793 ) $ 57.38 Outstanding and unvested as of December 31, 2018 7,425 $ 58.45 The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.3 million for each of the years ended December 31, 2018 and 2017 . The actual tax benefit from released restricted shares for the same years was $0.1 million in each year. No shares of WEC Energy Group restricted stock held by our employees were released during 2016. As of December 31, 2018 , we expected to recognize approximately $0.6 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group restricted stock over the next 1.5 years on a weighted-average basis. During the first quarter of 2019 , the Compensation Committee awarded 1,889 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $68.18 per share. Performance Units During 2018 , 2017 , and 2016 , the Compensation Committee awarded 8,500 ; 10,025 ; and 9,235 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan. At December 31, 2018 , our employees held 26,454 of outstanding WEC Energy Group performance units, including dividend equivalents. A liability of $1.7 million was recorded on our balance sheet at December 31, 2018 related to these outstanding units. As of December 31, 2018 , we expected to recognize approximately $3.4 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 1.3 years on a weighted-average basis. During the first quarter of 2019 , performance units held by our employees with an intrinsic value of $0.8 million were settled. The actual tax benefit from the distribution of these awards was $0.2 million . In January 2019 , the Compensation Committee awarded 8,178 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to the sole holder of our common stock, Integrys, in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their subsidiaries. In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 51 %. A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level. See Note 12, Short-Term Debt and Lines of Credit , for discussion of certain financial covenants related to short-term debt obligations. As of December 31, 2018 , our restricted retained earnings totaled approximately $531 million . We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. |
PREFERRED STOCK
PREFERRED STOCK | 12 Months Ended |
Dec. 31, 2018 | |
Class of Stock Disclosures [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK We have 1,000,000 shares of preferred stock with a $100 par value authorized for issuance, of which none were issued and outstanding at December 31, 2018 and 2017 . |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 12 Months Ended |
Dec. 31, 2018 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | 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) 2018 2017 Commercial paper Amount outstanding at December 31 $ 284.4 $ 293.1 Average interest rate on amounts outstanding at December 31 2.85 % 1.72 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2018 was $285.5 million , with a weighted-average interest rate during the period of 2.25% . We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a total funded debt to capitalization ratio of 65% or less. As of December 31, 2018 , we were in compliance with this ratio. The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 : (in millions) Maturity 2018 Revolving credit facility October 2022 $ 400.0 Less: Letters of credit issued inside credit facility 1.3 Commercial paper outstanding 284.4 Available capacity under existing agreement $ 114.3 This facility has a renewal provision for two one -year extensions, subject to lender approval. Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control. |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT See our statements of capitalization for details on our long-term debt. In November 2018, we issued $400.0 million of 3.35% Senior Notes due November 21, 2021. We used the net proceeds to pay all $250.0 million outstanding principal amount of our 1.65% Senior Notes at maturity in December 2018, to repay short-term debt, and for working capital and other corporate purposes. The following table shows the future maturities of our long-term debt outstanding as of December 31, 2018 : (in millions) Payments 2019 $ — 2020 — 2021 400.0 2022 — 2023 — Thereafter 925.0 Total $ 1,325.0 We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2018 2017 2016 Current tax expense (benefit) $ 56.7 $ 22.0 $ (52.5 ) Deferred income taxes, net 20.9 78.0 143.3 Investment tax credit, net (0.3 ) (0.3 ) (0.3 ) Total income tax expense $ 77.3 $ 99.7 $ 90.5 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: 2018 2017 2016 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 52.5 21.0 % $ 89.1 35.0 % $ 86.2 35.0 % State income taxes net of federal tax benefit 15.4 6.2 % 12.7 5.0 % 11.6 4.7 % Federal excess amortization * 11.6 4.6 % — — % — — % AFUDC – Equity (1.0 ) (0.4 )% (1.4 ) (0.5 )% (6.8 ) (2.7 )% Other, net (1.2 ) (0.5 )% (0.7 ) (0.3 )% (0.5 ) (0.2 )% Total income tax expense $ 77.3 30.9 % $ 99.7 39.2 % $ 90.5 36.8 % * See Note 21, Regulatory Environment, for more information about the impact of the Tax Legislation. Deferred Income Tax Assets and Liabilities On December 22, 2017, the Tax Legislation was signed into law. For businesses, the Tax Legislation reduced the corporate federal tax rate from a maximum of 35% to a 21% rate effective January 1, 2018. In December 2017, we recorded a tax benefit related to the re-measurement of our deferred taxes in the amount of $444.7 million . Accordingly, this amount was recorded as both an increase to regulatory liabilities as well as a decrease to certain existing regulatory assets as of December 31, 2017. On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provided for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation were considered "provisional" and subject to revision at December 31, 2017, and through 2018, as discussed in SAB 118. In 2018, we considered all available guidance from industry and income tax authorities related to these tax items, analyzed the impact on Alternative Minimum Tax Credit carryforwards, and revised our estimates for re-measurement of deferred income taxes related to guidance on bonus depreciation. At December 31, 2018, we no longer considered any amounts related to bonus depreciation and future tax benefit utilization "provisional." However, any further amendments or technical corrections to the Tax Legislation could subject these tax items to revision. The components of deferred income taxes as of December 31 are as follows: (in millions) 2018 2017 Deferred tax assets Tax gross up – regulatory items $ 105.5 $ 99.3 Other 23.9 7.9 Total deferred tax assets $ 129.4 $ 107.2 Deferred tax liabilities Property-related 588.1 563.5 Employee benefits and compensation 40.9 37.7 Other 21.2 18.7 Total deferred tax liabilities 650.2 619.9 Deferred tax liability, net $ 520.8 $ 512.7 Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities. At December 31, 2018, we had $1.3 million of tax credit carryforwards resulting in deferred tax assets of $1.3 million . Federal tax credit carryforwards begin to expire in 2038. We expect to have future taxable income sufficient to utilize these deferred tax assets. At December 31, 2017, we had $1.4 million and $6.3 million of federal charitable contribution and tax credit carryforwards resulting in deferred tax assets of $0.3 million and $6.3 million , respectively. At December 31, 2018, we had $1.1 million of state net operating losses resulting in deferred tax assets of $0.4 million . These state net operating loss carryforwards begin to expire in 2029. We expect to have future taxable income sufficient to utilize these deferred tax assets. At December 31, 2017, we had $6.7 million and $1.4 million of state net operating loss and charitable contribution carryforwards resulting in deferred tax assets of $0.4 million and $0.1 million , respectively. Unrecognized Tax Benefits We had no unrecognized tax benefits at December 31, 2018 and 2017 . We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2018 . For the years ended December 31, 2018, 2017, and 2016, we recognized no interest and no penalties related to unrecognized tax benefits in our income statements. For the years ended December 31, 2018 and 2017, we had no interest accrued and no penalties accrued related to unrecognized tax benefits on our balance sheets. We do not anticipate any significant increases in the total amounts of unrecognized tax benefits within the next 12 months. Our primary tax jurisdictions include Federal and the state of Wisconsin. With a few exceptions, we are no longer subject to Federal income tax examinations by the IRS for years prior to 2015. As of December 31, 2018 , we were subject to examination by the Wisconsin taxing authority for tax years 2014 through 2018. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | 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, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.8 $ — $ — $ 0.8 FTRs — — 3.0 3.0 Coal contracts — 0.4 — 0.4 Total derivative assets $ 0.8 $ 0.4 $ 3.0 $ 4.2 Derivative liabilities Natural gas contracts $ 1.1 $ — $ — $ 1.1 December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.8 $ — $ — $ 0.8 Petroleum products contracts 0.3 — — 0.3 FTRs — — 2.0 2.0 Coal contracts — 0.4 — 0.4 Total derivative assets $ 1.1 $ 0.4 $ 2.0 $ 3.5 Derivative liabilities Natural gas contracts $ 2.3 $ — $ — $ 2.3 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 2.3 $ 0.5 $ — $ 2.8 The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2018 2017 2016 Balance at the beginning of the period $ 2.0 $ 2.0 $ 2.0 Realized and unrealized losses — — (0.2 ) Purchases 9.0 6.9 7.1 Sales — — (0.2 ) Settlements (8.0 ) (6.9 ) (6.7 ) Balance at the end of the period $ 3.0 $ 2.0 $ 2.0 Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on our income statements. Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2018 December 31, 2017 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,314.7 $ 1,372.9 $ 1,166.2 $ 1,302.4 The fair value of long-term debt is categorized within Level 2 of the fair value hierarchy. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities, none of which are designated as hedging instruments. December 31, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.8 $ 1.0 $ 0.8 $ 1.9 Petroleum products contracts — — 0.3 — FTRs 3.0 — 2.0 — Coal contracts 0.2 — — 0.5 Total other current $ 4.0 $ 1.0 $ 3.1 $ 2.4 Other long-term Natural gas contracts $ — $ 0.1 $ — $ 0.4 Coal contracts 0.2 — 0.4 — Total other long-term $ 0.2 $ 0.1 $ 0.4 $ 0.4 Total $ 4.2 $ 1.1 $ 3.5 $ 2.8 Realized gains (losses) on derivatives are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2018 December 31, 2017 December 31, 2016 (in millions) Volume Gains Volume Gains (Losses) Volume Gains (Losses) Natural gas contracts 38.4 Dth $ 5.1 18.6 Dth $ (2.4 ) 28.6 Dth $ (1.4 ) Petroleum products contracts 1.8 gallons 0.4 1.3 gallons 0.1 4.4 gallons (0.6 ) FTRs 9.3 MWh 12.5 9.1 MWh 6.4 8.4 MWh 6.0 Total $ 18.0 $ 4.1 $ 4.0 At December 31, 2018 and 2017 , we had posted cash collateral of $0.5 million and $4.9 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, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 4.2 $ 1.1 $ 3.5 $ 2.8 Gross amount not offset on the balance sheet (0.8 ) (1.1 ) (1) (1.1 ) (2.3 ) (2) Net amount $ 3.4 $ — $ 2.4 $ 0.5 (1) Includes cash collateral posted of $0.3 million . (2) Includes cash collateral posted of $1.2 million . |
EMPLOYEE BENEFITS
EMPLOYEE BENEFITS | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits Through December 31, 2016, we participated in the Integrys Energy Group Retirement Plan, a noncontributory, qualified pension plan sponsored by WBS. We were responsible for our share of the plan assets and obligations. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017; however, we made additional contributions to the plan as discussed below. We serve as plan sponsor and administrator for certain OPEB plans. The benefits are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. WEC Energy Group also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred. 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 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 the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset. The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2018 2017 2018 2017 Change in benefit obligation Obligation at January 1 $ 704.7 $ 655.2 $ 220.2 $ 223.1 Service cost 10.4 9.0 6.1 6.2 Interest cost 26.0 26.7 8.2 9.1 Plan amendments — — (1.5 ) (21.7 ) Net transfer to/from affiliates — — (0.1 ) — Actuarial (gain) loss (42.7 ) 45.1 (70.7 ) 12.2 Participant contributions — — 1.2 1.0 Benefit payments (34.3 ) (31.3 ) (9.9 ) (9.7 ) Transfer — — (2.1 ) $ — Obligation at December 31 $ 664.1 $ 704.7 $ 151.4 $ 220.2 Change in fair value of plan assets Fair value at January 1 $ 712.4 $ 736.6 $ 250.5 $ 231.1 Actual return on plan assets (39.4 ) 99.2 (10.3 ) 27.1 Employer contributions 0.6 65.7 0.1 1.0 Participant contributions — — 1.2 1.0 Benefit payments (34.3 ) (31.3 ) (9.9 ) (9.7 ) Net transfer to/from affiliates — (157.8 ) * 0.1 — Fair value at December 31 $ 639.3 $ 712.4 $ 231.7 $ 250.5 Funded status at December 31 $ (24.8 ) $ 7.7 $ 80.3 $ 30.3 * Related to our transfer of pension trust assets in conjunction with the Integrys pension plan split for the year ended December 31, 2017. Assets were transferred out of our plan in January 2017. See Note 3, Related Parties, for more information . The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2018 2017 2018 2017 Pension and OPEB assets $ — $ 15.6 $ 92.8 $ 46.4 Pension and OPEB obligations 24.8 7.9 12.5 16.1 Total net (liabilities) assets $ (24.8 ) $ 7.7 $ 80.3 $ 30.3 The accumulated benefit obligation for the defined benefit pension plans was $594.1 million and $652.0 million at December 31, 2018 and 2017 , respectively. The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2018 2017 Projected benefit obligation $ 7.3 $ 7.9 Accumulated benefit obligation 7.3 7.9 The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2018 2017 2018 2017 Net regulatory assets (liabilities) Net actuarial loss (gain) $ 220.4 $ 196.5 $ (17.9 ) $ 27.2 Prior service credits — — (82.8 ) (92.6 ) Total $ 220.4 $ 196.5 $ (100.7 ) $ (65.4 ) The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2019 : (in millions) Pension Costs OPEB Costs Net actuarial loss $ 17.8 $ 1.6 Prior service credits — (11.4 ) Total 2019 – estimated amortization $ 17.8 $ (9.8 ) The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2018 2017 2016 2018 2017 2016 Service cost $ 10.4 $ 9.0 $ 9.9 $ 6.1 $ 6.2 $ 7.3 Interest cost 26.0 26.7 27.0 8.2 9.1 10.6 Expected return on plan assets (48.3 ) (46.4 ) (52.6 ) (17.8 ) (16.7 ) (15.9 ) Loss on plan settlement — — 3.4 — — — Amortization of prior service credit — — — (11.3 ) (9.8 ) (7.4 ) Amortization of net actuarial loss 21.1 17.3 18.0 2.5 2.5 2.5 Net periodic benefit cost (credit) $ 9.2 $ 6.6 $ 5.7 $ (12.3 ) $ (8.7 ) $ (2.9 ) Effective January 1, 2018, we adopted ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which modifies certain aspects of the accounting for employee benefit costs. Under the new guidance, only the service cost component can be included in total operating expenses. The remaining components of net periodic benefit cost are required to be presented in the income statement separately from the service cost component, outside of operating income. As required, this change was applied retrospectively to all prior periods presented. Accordingly, for the years ended December 31, 2018 , 2017 , and 2016 , we have presented the service cost component of our retirement benefit plans in other operation and maintenance on the income statements, while presenting the non-service cost components in other income, net. As required by ASU 2017-07, our income statements for the years ended December 31, 2017 and 2016, were retroactively restated from what was previously presented in our 2017 Annual Report on Form 10-K. The impacts to our income statements from adoption of this standard are reflected in the table below. Year Ended December 31, 2017 Year Ended December 31, 2016 (in millions) Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Operating expenses Other operation and maintenance $ 435.8 $ 11.8 $ 447.6 $ 493.2 $ 10.5 $ 503.7 Other expense Other income, net 11.9 11.8 23.7 30.8 10.5 41.3 In addition, under ASU 2017-07, only the service cost component of net periodic benefit cost is eligible for capitalization to property, plant, and equipment. In prior periods, a portion of all net benefit cost components was capitalized to property, plant, and equipment. As required, this amendment was applied prospectively, beginning January 1, 2018. As a result of the application of accounting principles for rate regulated entities, the non-service cost components of the net benefit cost that are no longer eligible for capitalization under this standard, but are capitalized under the regulatory framework, will be presented as regulatory assets or liabilities rather than property, plant, and equipment. The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2018 2017 2018 2017 Discount rate 4.30% 3.70% 4.29% 3.67% Rate of compensation increase 4.00% 4.00% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.25% 6.50% 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 2024 2024 Assumed medical cost trend rate (Post 65) N/A N/A 5.90% 6.00% 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 net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2018 2017 2016 Discount rate 3.70% 4.19% 4.25% Expected return on assets 7.25% 7.25% 7.25% Rate of compensation increase 4.00% 4.00% 4.00% OPEB Costs 2018 2017 2016 Discount rate 3.67% 4.11% 4.46% Expected return on assets 7.25% 7.25% 7.25% Assumed medical cost trend rate (Pre 65) 6.50% 7.00% 7.50% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2024 2021 2021 Assumed medical cost trend rate (Post 65) 6.00% 7.00% 7.50% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2021 2021 WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2019 , the expected return on asset assumption for the pension plan and OPEB plans is 7.25% . Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2018 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 2.5 $ (1.9 ) Effect on the health care component of the accumulated postretirement benefit obligation 15.2 (12.1 ) Plan Assets Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees. The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Our pension trust target asset allocation is 45% equity investments, 45% fixed income investments, and 10% private equity and real estate investments. The OPEB trust has a target asset allocation 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(n), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. The following tables provide the fair values of our investments by asset class: December 31, 2018 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States Equity $ 79.0 $ — $ — $ 79.0 $ 24.0 $ — $ — $ 24.0 International Equity 80.1 0.3 — 80.4 27.0 0.2 — 27.2 Fixed income securities: * United States Bonds 16.3 119.1 — 135.4 46.9 37.0 — 83.9 International Bonds 2.3 21.0 — 23.3 2.5 1.6 — 4.1 $ 177.7 $ 140.4 $ — $ 318.1 $ 100.4 $ 38.8 $ — $ 139.2 Investments measured at net asset value $ 321.2 $ 92.5 Total $ 177.7 $ 140.4 $ — $ 639.3 $ 100.4 $ 38.8 $ — $ 231.7 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2017 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ — $ 22.2 $ — $ 22.2 $ 9.2 $ 0.3 $ — $ 9.5 Equity securities: United States Equity 97.9 — — 97.9 26.5 — — 26.5 International Equity 98.2 — 0.4 98.6 31.8 — 0.2 32.0 Fixed income securities: * United States Bonds 17.8 129.2 — 147.0 47.0 35.7 — 82.7 International Bonds 2.3 21.2 — 23.5 2.5 1.8 — 4.3 Private Equity and Real Estate — 62.9 12.5 75.4 — 0.7 0.1 0.8 $ 216.2 $ 235.5 $ 12.9 $ 464.6 $ 117.0 $ 38.5 $ 0.3 $ 155.8 Investments measured at net asset value $ 247.8 $ 94.7 Total $ 216.2 $ 235.5 $ 12.9 $ 712.4 $ 117.0 $ 38.5 $ 0.3 $ 250.5 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate International Equity (in millions) Pension OPEB Pension OPEB Beginning balance at January 1, 2018 $ 12.5 $ 0.1 $ 0.4 $ 0.2 Realized and unrealized losses 0.7 — (0.1 ) — Purchases 2.4 — — — Transfers out of level 3 (15.6 ) (0.1 ) (0.3 ) (0.2 ) Ending balance at December 31, 2018 $ — $ — $ — $ — Private Equity and Real Estate International Equity U.S. Bonds (in millions) Pension OPEB Pension OPEB Pension Beginning balance at January 1, 2017 $ — $ — $ — $ — $ 0.5 Realized and unrealized losses — — (0.1 ) — (0.5 ) Purchases 12.5 0.1 0.5 0.2 — Ending balance at December 31, 2017 $ 12.5 $ 0.1 $ 0.4 $ 0.2 $ — Cash Flows We expect to contribute $0.7 million to the pension plans in 2019 , dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation. We expect to contribute an insignificant amount to the OPEB plans in 2019 . The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB. (in millions) Pension Costs OPEB Costs 2019 $ 34.7 $ 7.8 2020 35.5 8.9 2021 36.5 9.2 2022 37.0 8.7 2023 36.3 8.9 2024-2028 185.7 46.9 Savings Plans WEC Energy Group sponsors a 401(k) savings plan that allows substantially all of our full-time employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. The 401(k) savings plans include an Employee Stock Ownership Plan. Certain employees receive an employer retirement contribution, which amounts are contributed to an employee's savings plan account based on the employee's wages, age, and years of service. Our share of the total costs incurred under all of these plans was $9.9 million in 2018 , $9.6 million in 2017 , and $9.0 million in 2016 . |
SEGMENTS INFORMATION
SEGMENTS INFORMATION | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
SEGMENTS OF BUSINESS | SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2018 , we reported two segments, which are described below. Our utility segment includes our electric and natural gas utility operations, which serve customers in northeastern and central Wisconsin. Our electric utility operations are engaged in the generation, distribution, and sale of electricity. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers as well as the transportation of customer-owned natural gas. Effective January 1, 2017, we transferred our customers and electric and natural gas distribution assets located in the Upper Peninsula of Michigan to UMERC. See Note 3, Related Parties for more information. During 2018 and 2017, the other segment included non-utility activities, as well as equity earnings from our investment in WRPC. During 2016, the other segment included non-utility activities as well as equity earnings from our investments in WRPC and WPSI. Effective January 1, 2017, we transferred our 10.37% ownership interest in WPSI to another subsidiary of Integrys. See Note 3, Related Parties , for more information. 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, 2018 , 2017 , and 2016 . 2018 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,498.5 $ — $ — $ 1,498.5 Other operation and maintenance 447.5 0.5 — 448.0 Depreciation and amortization 141.9 — — 141.9 Operating income (loss) 267.1 (0.7 ) — 266.4 Other income, net 35.2 2.4 — 37.6 Interest expense 53.9 — — 53.9 Capital expenditures and asset acquisitions 521.4 — — 521.4 Total assets 5,151.5 66.2 — 5,217.7 2017 (in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated External revenues $ 1,485.4 $ — $ — $ 1,485.4 Other operation and maintenance * 446.1 1.5 — 447.6 Depreciation and amortization 139.3 — — 139.3 Operating income (loss) * 286.7 (1.6 ) — 285.1 Other income, net * 21.0 2.7 — 23.7 Interest expense 54.2 — — 54.2 Capital expenditures 335.8 — — 335.8 Total assets 4,678.1 70.6 — 4,748.7 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 17, Employee Benefits, for more information on this new standard. 2016 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,448.2 $ — $ — $ 1,448.2 Intersegment revenues — 0.3 (0.3 ) — Other operation and maintenance * 503.0 1.0 (0.3 ) 503.7 Depreciation and amortization 124.0 0.1 — 124.1 Operating income (loss) * 253.9 (0.9 ) — 253.0 Other income, net * 33.8 7.5 — 41.3 Interest expense 48.0 0.1 — 48.1 Capital expenditures 311.1 — — 311.1 Total assets 4,686.4 121.8 — 4,808.2 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 17, Employee Benefits, for more information on this new standard. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, operating leases, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2018 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2019 2020 2021 2022 2023 Later Years Electric utility: Purchased power 2041 $ 410.8 $ 75.1 $ 48.2 $ 46.8 $ 41.8 $ 39.7 $ 159.2 Coal supply and transportation 2024 325.4 115.0 63.1 48.2 47.6 50.8 0.7 Natural gas utility supply and transportation 2048 449.9 51.7 50.3 46.4 43.0 26.9 231.6 Total $ 1,186.1 $ 241.8 $ 161.6 $ 141.4 $ 132.4 $ 117.4 $ 391.5 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 SO 2 , NOx, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. 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 old 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 generating units; and • the remediation of former manufactured gas plant sites. Air Quality National Ambient Air Quality Standards After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service territory were designated as partial nonattainment: Door, Manitowoc, and Sheboygan shorelines. The state of Wisconsin will need to develop a state implementation plan to bring these areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. 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. Mercury and Air Toxics Standards In December 2018, the EPA proposed to revise the Supplemental Cost Finding for the mercury and air toxics standards (MATS) rule as well as the CAA required risk and technology review (RTR). The EPA was required by the Supreme Court to review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from power plants under Section 112 of the CAA. As a result, under the proposed rule, the emission standards and other requirements of the MATS rule first enacted in 2012 would remain in place. The EPA is not proposing to remove coal and oil fired power plants from the list of sources that are regulated under Section 112. The EPA also proposes that no revisions to MATS are warranted based on the results of the RTR. As a result, we do not expect the proposed rule to have a material impact on our financial condition or operations. Climate Change In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of certain litigation in the D.C. Circuit Court of Appeals challenging the rule and, to the extent that further appellate review is sought, at the Supreme Court. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the challenges to the CPP, as well as related performance standards for new, reconstructed, and modified fossil-fueled power plants, to be held in abeyance, which remains the case. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. Then, in August 2018, the EPA issued a proposed replacement rule for the CPP, the ACE rule. The proposed ACE rule would require the EPA to develop emission guidelines for states to use to develop their individual state plans. The state plans would focus on reducing GHG emissions by improving the efficiency of fossil-fueled power plants. In December 2018, the EPA proposed to revise the New Source Performance Standards for GHG emissions from new, modified, and reconstructed fossil fueled power plants. The EPA determined that the best system of emission reduction (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 2015 rule, which identified BSER as partial carbon capture and storage. In addition, we are evaluating our goals, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius. We are working with industry members to evaluate potential GHG reduction pathways. We continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. WEC Energy Group's plan, which includes us, is to work with its industry partners, environmental groups, and the State of Wisconsin, with goals of reducing CO 2 emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. We have implemented and continue to evaluate numerous options in order to meet WEC Energy Group's CO 2 reduction goals. As a result of WEC Energy Group's generation reshaping plan, we retired approximately 300 MW of coal generation in 2018, consisting of the Pulliam power plant and the jointly-owned Edgewater Unit 4 generation units. See Note 6, Property, Plant, and Equipment, for more information . We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2017 , we reported aggregated CO 2 equivalent emissions of approximately 5.7 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 6.4 million metric tonnes to the EPA for 2018 . The level of CO 2 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 CO 2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2017 , we reported aggregated CO 2 equivalent emissions of approximately 3.5 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 3.8 million metric tonnes to the EPA for 2018 . 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 Best Technology Available (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. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Weston Unit 2, satisfy the BTA requirements. We retired Pulliam Units 7 and 8 effective October 21, 2018. See Note 6, Property, Plant, and Equipment, for more information on the retirement of the Pulliam generating units. Therefore, we will not be required to make alterations to the existing water intake at these units. Based on the March 2018 reissued WPDES permit for Weston, the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the BTA requirements based on low capacity use of the unit. There has been an interim BTA determination made by the WDNR as part of the March 2018 reissued WPDES permit for Weston Units 3 and 4. We expect that the WDNR will conclude, in the next permit reissuance, that the existing cooling tower systems for Weston Units 3 and 4 are BTA. Due to the retirement of Pulliam Units 7 and 8, we do not believe that BTA determinations will be necessary for these units. We also have provided information to the WDNR about planned unit retirements. As a result of past capital investments completed to address 316(b) compliance, we believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Limitation Guidelines The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. This rule created new requirements for several types of power plant wastewaters. The requirement that affects us relates to discharge limits for bottom ash transport water (BATW). Various petitions challenging the rule were consolidated and are pending in the United States Court of Appeals for the Fifth Circuit. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule (Postponement Rule) to postpone the earliest compliance date to November 1, 2020 for the BATW. The latest ELG rule compliance date remains December 31, 2023 for any new wastewater treatment requirements contained in power plant discharge permits. This rule applies to wastewater discharges from our power plant processes in Wisconsin. Litigation over various aspects of the final ELG rule and the Postponement Rule is pending in several Federal Courts. As a result of past capital investments completed to address ELG compliance, we believe our fleet overall is well positioned to meet this new regulation. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. Due to completed generating unit retirements, the only facility that will require bottom ash system modifications is Weston Unit 3. Based on preliminary engineering, the estimated rule compliance cost is approximately $20 million . Land Quality Manufactured Gas Plant Remediation We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites, 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 related to manufactured gas plant sites as of December 31: (in millions) 2018 2017 Regulatory assets $ 108.3 $ 116.0 Reserves for future remediation 90.3 99.6 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 by December 31, 2015. We have achieved a renewable energy percentage of 9.74% and met our compliance requirements by constructing various wind parks and by also relying on renewable energy purchases. We continue to review our renewable energy portfolio and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual operating revenues. Enforcement and Litigation Matters We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations. Consent Decrees Consent Decree – Weston and Pulliam Power Plants In November 2009, the EPA issued an NOV to us, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. 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 Eastern District of Wisconsin in March 2013. The final Consent Decree includes: • the installation of emission control technology, including ReACT™ on Weston 3, • changed operating conditions, • limitations on plant emissions, • beneficial environmental projects totaling $6.0 million , and • a civil penalty of $1.2 million . The Consent Decree also contains requirements to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6. In May 2016, the EPA approved our proposed revision to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel, and also proposed revisions to the list of beneficial environmental projects required by the Consent Decree. We retired Pulliam Units 7 and 8 on October 21, 2018. See Note 6, Property, Plant, and Equipment, for more information about the retirement. We completed the mitigation projects required and received a completeness letter from the EPA in October 2018. We plan to request termination of the Consent Decree during 2019. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant related to Weston Unit 1 and Pulliam Units 5 and 6 starting June 1, 2015, and concluding by 2023. Therefore, in June 2015, we recorded a regulatory asset of $11.5 million for the undepreciated book value. In addition, we received approval from the PSCW in our rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. Joint Ownership Power Plants Consent Decree – Columbia and Edgewater In December 2009, the EPA issued an NOV to Wisconsin Power and Light, 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 us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, along with Wisconsin Power and Light, 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. The final Consent Decree includes: • the installation of emission control technology, including scrubbers at the Columbia plant, • changed operating conditions, • limitations on plant emissions, • beneficial environmental projects, with our portion totaling $1.3 million , and • our portion of a civil penalty and legal fees totaling $0.4 million . 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 on September 28, 2018. See Note 6, Property, Plant, and Equipment, for more information about the retirement. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2018 2017 2016 Cash (paid) for interest, net of amount capitalized $ (52.9 ) $ (55.5 ) $ (54.6 ) Cash (paid) received for income taxes, net (36.6 ) (18.1 ) 39.9 Significant non-cash transactions: Accounts payable related to construction costs 8.1 46.4 67.2 Receivable related to corporate-owned life insurance proceeds 6.4 — — Transfer of ownership in WPSI to another subsidiary of Integrys * — 67.2 — Transfer of net assets to UMERC * 0.4 20.6 — * See Note 3, Related Parties, for more information on these transactions. |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 12 Months Ended |
Dec. 31, 2018 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT Tax Cuts and Jobs Act of 2017 In December 2017, we deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $444.7 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes. The Tax Legislation also reduced the corporate federal tax rate from a maximum of 35% to a 21% rate, effective January 1, 2018. In May 2018, the PSCW issued an order regarding the benefits associated with the Tax Legislation. The PSCW order requires our electric utility operations to use 40% of the current 2018 and 2019 tax benefits to reduce certain regulatory assets. The remaining 60% is to be returned to electric customers in the form of bill credits. For our natural gas utility operations, the PSCW indicated that 100% of the current 2018 and 2019 tax benefits should be returned to natural gas customers in the form of bill credits. Regarding the net tax benefit associated with the revaluation of deferred taxes, amortization required in accordance with normalization accounting is to be used to reduce certain regulatory assets for our electric utility operations and is being deferred for our natural gas utility operations. The timing and method of returning the remaining net tax benefit associated with the revaluation of deferred taxes for our electric and natural gas utility operations was not addressed and will be determined in a future rate proceeding. 2018 and 2019 Rates During April 2017, we, along with WE and WG, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which freezes base rates through 2019 for our electric and natural gas customers. Based on the PSCW order, our authorized ROE remains at 10.0% , and our current capital cost structure will remain unchanged through 2019. In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers. Additionally, the agreement allows us 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 our electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, was $342 million . Pursuant to the settlement agreement, we also agreed to adopt, beginning in 2018, the earnings sharing mechanism that has been in place for WE and WG since January 2016, and agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers. As required in the settlement agreement, we anticipate initiating a rate proceeding with the PSCW by April 1, 2019. Acquisition of a Wind Energy Generation Facility in Wisconsin In October 2017, we, 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 on April 2, 2018. See Note 2, Acquisitions , for more information. Proposed Solar Generation Projects On May 31, 2018, we, along with an unaffiliated utility, filed an application with the PSCW for approval to acquire ownership interests in two proposed solar projects in Wisconsin. Badger Hollow Solar Farm will be located in Iowa County, Wisconsin, and Two Creeks Solar Project will be located in Manitowoc County, Wisconsin. Subject to receipt of the PSCW's approval, we will own 100 MW of the output of each project for a total of 200 MW. Our share of the cost of both projects is estimated to be $260 million . Natural Gas Storage Facilities in Michigan In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that provide a portion of the current storage needs for our natural gas utility operations. As a result of this agreement, we, along with WE and WG, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreement and interstate natural gas transportation contracts related to the storage facilities. We, along with WE and WG, also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we entered into the long-term service agreement for the natural gas storage, which was then approved by the PSCW in November 2017. See Note 3, Related Parties , for more information. 2016 Wisconsin Rate Order In April 2015, we initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order, effective January 1, 2016. The order, which reflected a 10.0% ROE and a common equity component average of 51.0% , authorized a net retail electric rate decrease of $7.9 million ( -0.8% ) and a net retail natural gas rate decrease of $6.2 million ( -2.1% ). The decrease in retail electric rates was due to lower monitored fuel costs in 2016 compared with 2015. Absent the adjustment for electric fuel costs, we would have realized an electric rate increase. Based on the order, the PSCW allowed us to escrow ATC and MISO network transmission expenses through 2016. In addition, system support resource payments are being escrowed until a future rate proceeding. The order directed us to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which required us to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window. In March 2016, we requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, we also requested to extend through 2017 the previously approved deferral of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of our large commercial and industrial customers who entered into a service agreement with us under Real Time Market Pricing prior to April 15, 2016. These requests were approved by the PSCW in June 2016. |
OTHER INCOME, NET
OTHER INCOME, NET | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
OTHER INCOME, NET | OTHER INCOME, NET Total other income, net was as follows for the years ended December 31 : (in millions) 2018 2017 2016 AFUDC – Equity $ 4.6 $ 4.1 $ 19.5 Non-service components of net periodic benefit costs 16.7 11.8 10.5 Earnings from equity method investments 0.8 1.1 9.5 Other, net 15.5 6.7 1.8 Other income, net $ 37.6 $ 23.7 $ 41.3 |
QUARTERLY FINANCIAL INFORMATION
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (Unaudited) (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018 Operating revenues $ 393.6 $ 350.1 $ 379.2 $ 375.6 $ 1,498.5 Operating income 69.2 72.4 86.4 38.4 266.4 Net income 49.8 42.7 57.0 23.3 172.8 2017 Operating revenues $ 389.6 $ 341.6 $ 380.7 $ 373.5 $ 1,485.4 Operating income * 73.0 58.1 108.2 45.8 285.1 Net income 39.3 30.7 60.9 24.0 154.9 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 17, Employee Benefits, for more information on this new standard. |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 12 Months Ended |
Dec. 31, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS 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. For lessors however, accounting for leases was largely unchanged from previous provisions of GAAP. We have finalized our inventory of leases and did not identify any leases that were significant, documented our technical accounting issues, and implemented required changes to internal controls and processes as a result of the new lease guidance. In addition, we continue to finalize the related financial disclosures that will be incorporated into our quarterly report on Form 10-Q for the quarter ended March 31, 2019. As required, we adopted Topic 842 for interim and annual periods beginning 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. • We did not reassess the accounting for initial direct costs for any existing leases. We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with ASC 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract. We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right-of-use assets. No impairment losses were included in the measurement of our right-of-use assets upon our adoption of Topic 842. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient upon our adoption of Topic 842, resulting in none of our land easements being treated as leases. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We do not expect the adoption of Topic 842 to result in us recording any significant right of use assets or related lease liabilities related to operating leases, and we had no capital leases upon adoption. We did not require a cumulative-effect adjustment upon adoption of Topic 842, and the new guidance is not expected to have any impact on future net income or cash flows. Financial Instruments Credit Losses In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements. 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 guidance will be effective for annual reporting periods, including interim reporting within those periods, beginning after December 15, 2019. Early adoption is permitted and can be applied either retrospectively or prospectively. We are currently evaluating the transition methods and the impact the adoption of this standard may have on our consolidated financial statements. |
SCHEDULE II - VALUATION AND QUA
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | 12 Months Ended |
Dec. 31, 2018 | |
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | SCHEDULE II WISCONSIN PUBLIC SERVICE CORPORATION VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Expense (1) Net Write-offs (2) Balance at End of Period December 31, 2018 $ 4.0 $ 6.0 $ (5.8 ) $ 4.2 December 31, 2017 3.0 5.0 (4.0 ) 4.0 December 31, 2016 2.5 7.7 (7.2 ) 3.0 (1) Net of recoveries. (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Nature of operations | We are an electric and natural gas utility company that serves customers in northeastern Wisconsin and, prior to the formation of UMERC, we also served customers in the Upper Peninsula of Michigan. We are subject to the jurisdiction of, and regulation by, the PSCW, which has general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin. In addition, we are subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. We are an indirect, wholly owned subsidiary of WEC Energy Group. |
Consolidation | As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted. |
Investment | 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. |
Use of estimates | 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. |
Cash and cash equivalents | Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. |
Operating revenues | Adoption of ASU 2014-09, Revenues from Contracts with Customers On January 1, 2018, we adopted ASU 2014-09, Revenues from Contracts with Customers, and the related amendments. In accordance with the guidance, we recognize revenues when control of the promised goods or services is transferred to our customers in an amount that reflects the consideration we expect to be entitled to receive in exchange for those goods or services. These revenues include unbilled revenues, which are estimated using the amount of energy delivered to our customers but not billed until after the end of the period. We adopted this standard using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under the new standard. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Adoption of the standard did not result in an adjustment to our opening retained earnings balance as of January 1, 2018, and we do not expect the adoption of the standard to have a material impact on our net income in future periods. We adopted the following practical expedients and optional exemptions for the implementation of this standard: • We elected to exclude from the transaction price any amounts collected from customers for all sales taxes and other similar taxes. • When applicable, we elected to apply the standard to a portfolio of contracts with similar characteristics, primarily our tariff-based contracts, as we reasonably expect that the effects on the financial statements of applying this guidance to the portfolio would not differ materially from applying this guidance to the individual contracts. • We elected to recognize revenue in the amount we have the right to invoice for performance obligations satisfied over time when the consideration received from a customer corresponds directly with the value provided to the customer during the same period. • We elected to not disclose the remaining performance obligations of a contract that has an original expected duration of one year or less. • We elected to apply this standard only to contracts that are not completed as of the date of initial application. Revenues from Contracts with Customers Electric Utility Operating Revenues Electricity sales to residential and commercial and industrial customers are generally accomplished through requirements contracts, which provide for the delivery of as much electricity as the customer needs. These contracts represent discrete deliveries of electricity and consist of one distinct performance obligation satisfied over time, as the electricity is delivered and consumed by the customer simultaneously. For our residential and commercial and industrial customers, our performance obligation is bundled to consist of both the sale and the delivery of the electric commodity. The transaction price of the performance obligations for residential and commercial and industrial customers is valued using the rates, charges, terms, and conditions of service included in our tariffs, which have been approved by 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 that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. Wholesale customers who resell power can choose to either bundle capacity and electricity services together under one contract with a supplier or purchase capacity and electricity separately from multiple suppliers. Furthermore, wholesale customers can choose to have us provide generation to match the customer's load, similar to requirements contracts, or they can purchase specified quantities of electricity and capacity. Contracts with wholesale customers that include capacity bundled with the delivery of electricity contain two performance obligations, as capacity and electricity are often transacted separately in the marketplace at the wholesale level. When recognizing revenue associated with these contracts, the transaction price is allocated to each performance obligation based on its relative standalone selling price. Revenue is recognized as control of each individual component is transferred to the customer. Electricity is the primary product sold by our electric operations and represents a single performance obligation satisfied over time through discrete deliveries to a customer. Revenue from electricity sales is generally recognized as units are produced and delivered to the customer within the production month. Capacity represents the reservation of an electric generating facility and conveys the ability to call on a plant to produce electricity when needed by the customer. The nature of our performance obligation as it relates to capacity is to stand ready to deliver power. This represents a single performance obligation transferred over time, which generally represents a monthly obligation. Accordingly, capacity revenue is recognized on a monthly basis. The transaction price of the performance obligation for wholesale customers is valued using the rates, charges, terms, and conditions of service, which have been approved by the FERC. These wholesale rates include recovery of fuel and purchased power costs from customers on a one-for-one basis. For the majority of our wholesale customers, the price billed for energy and capacity is a formula-based rate. Formula-based rates initially set a customer's current year rates based on the previous year’s expenses. This is a predetermined formula derived from the utility’s costs and a reasonable rate of return. Because these rates are eventually trued up to reflect actual, current-year costs, they represent a form of variable consideration in certain circumstances. The variable consideration is estimated and recognized over time as wholesale customers receive and consume the capacity and electricity services. We are an active participant in the MISO Energy Markets, where we bid our generation into the Day Ahead and Real Time markets and procure electricity for our retail and wholesale customers at prices determined by the MISO Energy Markets. Purchase and sale transactions are recorded using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. Net purchases in a single hour are recorded as purchased power in cost of sales and net sales in a single hour are recorded as resale revenues on our income statements. For resale revenues, our performance obligation is created only when electricity is sold into the MISO Energy Markets. For all of our customers, consistent with the timing of when we recognize revenue, customer billings generally occur on a monthly basis, with payments typically due in full within 30 days . Natural Gas Utility Operating Revenues We recognize natural gas utility operating revenues under requirements contracts with residential, commercial and industrial, and transportation customers served under our tariffs. Tariffs provide our customers with the standard terms and conditions, including rates, related to the services offered. Requirements contracts provide for the delivery of as much natural gas as the customer needs. These requirements contracts represent discrete deliveries of natural gas and constitute a single performance obligation satisfied over time. Our performance obligation is both created and satisfied with the transfer of control of natural gas upon delivery to the customer. For most of our customers, natural gas is delivered and consumed by the customer simultaneously. A performance obligation can be bundled to consist of both the sale and the delivery of the natural gas commodity. In certain of our service territories, customers can purchase the commodity from a third party. In this case, the performance obligation only includes the delivery of the natural gas to the customer. The transaction price of the performance obligations for our natural gas customers is valued using rates, charges, terms, and conditions of service included in our tariffs, which have been approved by the PSCW. These rates often have a fixed component customer charge and a usage-based variable component charge. We recognize revenue for the fixed component customer charge monthly using a time-based output method. We recognize revenue for the usage-based variable component charge using an output method based on natural gas delivered each month. Our tariffs include various rate mechanisms that allow us to recover or refund changes in prudently incurred costs from rate case-approved amounts. Our rates include 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. 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 Operating Revenues Alternative Revenues Alternative revenues are created from programs authorized by regulators that allow us to record additional revenues by adjusting rates in the future, usually as a surcharge applied to future billings, in response to past activities or completed events. We record alternative revenues when the regulator-specified conditions for recognition have been met. We reverse these alternative revenues as the customer is billed, at which time this revenue is presented as revenues from contracts with customers. Our only alternative revenue program relates to the wholesale electric service that we provide to customers under market-based rates and FERC formula rates. The customer is charged a base rate each year based upon a formula using prior year actual costs and customer demand. A true-up is calculated based on the difference between the amount billed to customers for the demand component of their rates and what the actual cost of service was for the year. The true-up can result in an amount that we will recover from or refund to the customer. We consider the true-up portion of the wholesale electric revenues to be alternative revenues. |
Materials, Supplies, and Inventories | Substantially all fossil fuel, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
Regulatory assets and liabilities | The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. |
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. Depreciation as a percent of average depreciable utility plant was 2.50% , 2.55% , and 2.58% in 2018 , 2017 , and 2016 , respectively. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 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 us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. |
AFUDC | 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. |
Asset impairment | Goodwill and other intangible assets with indefinite lives are subject to an annual impairment test. Interim impairment tests are also performed when impairment indicators are present. Our utility reporting unit containing goodwill performs an annual goodwill impairment test in the third quarter of each year. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit 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 9, Goodwill and Other Intangible Assets, for more information . Intangible assets with definite lives are reviewed for impairment on a quarterly basis. 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. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. An impairment loss is recognized when the carrying amount of an asset is not recoverable and exceeds the fair value of the asset. The carrying amount of an asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. An impairment loss is measured as the excess of the carrying amount of the asset in comparison to the fair value of the asset. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets the applicable criteria to be considered probable of abandonment, and the unit has been abandoned, we assess the likelihood of recovery of the remaining carrying 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 carrying value of the generating unit is greater than the present value of the amount expected to be recovered from ratepayers. |
Asset retirement obligations | We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated capitalized retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. |
Emission allowances | We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers. |
Stock-based compensation | Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million . Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. Stock Options Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after a three -year period. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options may not be exercised within 6 months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2018 2017 2016 Stock options granted 21,265 23,300 24,485 Estimated weighted-average fair value per stock option $ 7.68 $ 7.53 $ 5.63 Assumptions used to value the options: Risk-free interest rate 1.6% – 2.5% 0.7% – 2.5% 0.4% – 1.8% Dividend yield 3.5 % 3.5 % 4.0 % Expected volatility 18.0 % 19.0 % 18.0 % Expected life (years) 5.8 6.9 7.5 The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares granted to our employees have a three -year vesting period with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. 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 WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are recorded over the three -year performance period. |
Stock-based compensation - forfeitures | We account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. |
Income taxes | We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 14, Income Taxes, for more information . We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. |
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. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period. |
Derivative instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets. |
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. |
Employee benefits | The costs of pension and OPEB are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. |
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. |
Environmental remediation costs | We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 8, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 19, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the PSCW's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year. |
Customer concentration of credit risk | We provide regulated electric and natural gas service to customers in northeastern and central Wisconsin. See Note 3, Related Parties , for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. 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. We did not have any significant concentrations of credit risk at December 31, 2018 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2018 . |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Accounting Policies [Abstract] | |
Schedule of inventory | Our inventory as of December 31 consisted of: (in millions) 2018 2017 Materials and supplies $ 48.9 $ 40.8 Fossil fuel 29.2 43.8 Natural gas in storage 24.9 22.4 Total $ 103.0 $ 107.0 |
Schedule of total AFUDC | We recorded the following AFUDC for the years ended December 31: (in millions) 2018 2017 2016 AFUDC – Debt $ 1.9 $ 1.6 $ 8.1 AFUDC – Equity 4.6 4.1 19.5 |
Schedule of assumptions used to estimate the fair value of stock options granted | The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2018 2017 2016 Stock options granted 21,265 23,300 24,485 Estimated weighted-average fair value per stock option $ 7.68 $ 7.53 $ 5.63 Assumptions used to value the options: Risk-free interest rate 1.6% – 2.5% 0.7% – 2.5% 0.4% – 1.8% Dividend yield 3.5 % 3.5 % 4.0 % Expected volatility 18.0 % 19.0 % 18.0 % Expected life (years) 5.8 6.9 7.5 |
ACQUISITIONS FORWARD WIND ENERG
ACQUISITIONS FORWARD WIND ENERGY ACQUISITION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
WPS | Forward Wind Energy Center Acquisition | |
Business Acquisition [Line Items] | |
Schedule of Business Acquisitions, by Acquisition [Table Text Block] | 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 |
RELATED PARTIES (Tables)
RELATED PARTIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Schedule of information summarizing other related party transactions | Our balance sheets included the following receivables and payables related to transactions entered into with certain related parties: (in millions) December 31, 2018 December 31, 2017 Accounts receivable Service provided to ATC $ 1.2 $ 0.7 Accounts payable Network transmission services from ATC 8.8 9.0 Liability related to income tax allocation Integrys 3.5 4.1 |
Schedule of activity associated with related party transactions | The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2018 2017 2016 Transactions with WE (1) Natural gas sales to WE 1.9 1.6 1.9 Billings to WE 10.9 4.5 4.2 Billings from WE 17.8 (2) 28.2 9.0 Transactions with WBS (1) Billings to WBS 17.0 174.9 (3) 21.7 (3) Billings from WBS (2) 111.0 132.9 171.0 Transactions with UMERC (4) Electric sales to UMERC 15.8 16.2 — Natural gas sales to UMERC 2.7 2.5 — Transactions with Bluewater (5) Storage service fees 4.7 0.3 — Transactions related to ATC Charges to ATC for services and construction 7.9 6.2 8.6 Charges from ATC for network transmission services 106.1 107.8 109.4 Refund from ATC related to a FERC audit 6.6 — — Refund from ATC per FERC ROE order — 8.9 — Transactions with equity-method investees Rental payments to WRPC (6) 1.3 1.3 — Purchases of energy from WRPC (6) — 0.5 3.7 Charges from WRPC for services 2.4 2.2 — Charges to WRPC for operations 1.2 0.9 0.7 Equity earnings from WPSI — — 8.7 (1) Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs. (2) Includes $32.9 million , $10.1 million , and $34.1 million for the transfer of certain software assets from affiliates for the years ended December 31, 2018, 2017, and 2016, respectively. Includes $18.2 million for the transfer of certain benefit-related liabilities to WBS for the year ended December 31, 2016. (3) The year ended December 31, 2017 included $157.8 million of net cash received related to our transfer of pension trust assets in conjunction with the Integrys pension plan split. Effective January 1, 2017, the Integrys Energy Group Retirement Plan was split into six separate plans. As a result, we now have our own pension plan. While the split did not impact our pension benefit obligation, federal regulations required a different allocation of assets among the new plans. Assets were transferred out of our plan in January 2017. Includes $7.3 million for the transfer of certain software assets to WBS for the year ended December 31, 2016. (4) UMERC became operational effective January 1, 2017. See below for more information. (5) WEC Energy Group's acquisition of Bluewater was completed June 30, 2017. See below for more information. (6) In March 2017, we terminated our purchased power agreement with WRPC and entered into an agreement with WRPC to rent 50% of its hydroelectric power generation facilities. |
OPERATING REVENUES (Tables)
OPERATING REVENUES (Tables) - Utility | 12 Months Ended |
Dec. 31, 2018 | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following tables present our operating revenues disaggregated by revenue source. We only have revenues associated with our utility segment. We do not have any revenues associated with our other segment. We disaggregate revenues into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions. Comparable amounts have not been presented for the years ended December 31, 2017 and 2016 , due to our adoption of ASU 2014-09, Revenues from Contracts with Customers, under the modified retrospective method. See Note 1(d), Operating Revenues, for more information about our significant accounting policies related to operating revenues. Wisconsin Public Service Corporation Consolidated (in millions) Year ended December 31, 2018 Electric utility $ 1,192.2 Natural gas utility 305.5 Total revenues from contracts with customers 1,497.7 Other operating revenues 0.8 Total operating revenues $ 1,498.5 |
Revenues from contracts with customers | Electric | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues (in millions) Year ended December 31, 2018 Residential $ 381.5 Small commercial and industrial 371.4 Large commercial and industrial 238.8 Other 8.5 Total retail revenues 1,000.2 Wholesale 142.3 Resale 38.5 Other utility revenues 11.2 Total electric utility operating revenues $ 1,192.2 |
Revenues from contracts with customers | Natural gas | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues (in millions) Year ended December 31, 2018 Residential $ 177.7 Commercial and industrial 107.6 Total retail revenues 285.3 Transport 19.7 Other utility revenues 0.5 Total natural gas utility operating revenues $ 305.5 |
Other operating revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other operating revenues consist primarily of the following: (in millions) Year ended December 31, 2018 Late payment charges $ 2.9 Leases 0.2 Alternative revenues * (2.3 ) Total other operating revenues $ 0.8 * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups, as discussed in Note 1(d), Operating Revenues . |
REGULATORY ASSETS AND LIABILI_2
REGULATORY ASSETS AND LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2018 2017 See Note Regulatory assets (1) (2) Pension and OPEB costs (3) $ 189.8 $ 161.3 17 Environmental remediation costs (4) 108.3 116.0 19 Plant retirements 78.1 8.3 6 Income tax related items (5) 38.1 8.2 14 Termination of a tolling agreement with Fox Energy Company LLC (6) 21.7 27.2 AROs 11.5 9.7 8 De Pere Energy Center (7) 10.1 14.0 Crane Creek wind project production tax credits (8) 0.4 22.8 Other, net 27.9 15.3 Total regulatory assets $ 485.9 $ 382.8 Balance Sheet Presentation Current assets $ 0.3 $ — Regulatory assets 485.6 382.8 Total regulatory assets $ 485.9 $ 382.8 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in this table. In accordance with GAAP, our regulatory assets do not include the allowance for ROE that is capitalized for regulatory purposes. This allowance was $14.7 million and $14.4 million at December 31, 2018 and 2017 , respectively. (2) As of December 31, 2018 , we had $31.9 million of regulatory assets not earning a return and $5.3 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return primarily relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures, as well as our electric real-time market pricing program. The other regulatory assets in the table either earn a return 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, 2018 , we had made cash expenditures of $18.0 million related to these environmental remediation costs. The remaining $90.3 million represents our estimated future cash expenditures. (5) For information on the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment . (6) Represents an early termination fee of a tolling agreement we had with the Fox Energy Center. Prior to the purchase of the Fox Energy Center in 2013, we supplied natural gas for the facility and purchased capacity and the associated energy output under the tolling agreement. We are authorized recovery of this asset over a nine -year period that began on January 1, 2014. (7) Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023. (8) In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits and recorded regulatory assets. In May 2018, the PSCW issued an order requiring us to use a portion of our tax benefits from the Tax Legislation that was signed into law in December 2017 to reduce the regulatory assets related to our Crane Creek wind project production tax credits. See Note 21, Regulatory Environment, for more information . |
Schedule of regulatory liabilities | The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2018 2017 See Note Regulatory liabilities Income tax related items (1) $ 418.8 $ 393.8 14 Removal costs (2) 241.8 238.9 Pension and OPEB costs (3) 72.6 30.2 17 Earnings sharing mechanism 21.2 — 21 Energy costs refundable through rate adjustments (4) 14.3 8.2 Electric transmission costs 9.7 6.0 21 Other, net 14.5 20.1 Total regulatory liabilities $ 792.9 $ 697.2 Balance Sheet Presentation Current liabilities $ 7.2 $ 7.9 Regulatory liabilities 785.7 689.3 Total regulatory liabilities $ 792.9 $ 697.2 (1) For information on the regulatory treatment of the impacts of the Tax Legislation, see Note 21, Regulatory Environment . (2) Represents amounts collected from customers to cover the future cost of property, plant, and equipment removals that are not legally required. Legal obligations related to the removal of property, plant, and equipment are recorded as AROs. (3) Primarily represents the unrecognized future pension and OPEB benefits related to our defined benefit pension and OPEB plans. We will amortize these regulatory liabilities into net periodic benefit cost over the average remaining service life of each plan. (4) Represents an over-collection of energy costs that will be refunded to customers in the future. When the rates we charge to customers include energy costs that are higher than our actual energy costs, any over-collection outside of the allowable energy cost price variance is refunded to customers. |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment -Balances | Property, plant, and equipment consisted of the following utility and non-utility assets at December 31: (in millions) 2018 2017 Electric – generation $ 2,831.2 $ 2,624.9 Electric – distribution 1,510.0 1,361.9 Natural gas – distribution, storage, and transmission 910.6 846.4 Property, plant, and equipment to be retired — 57.9 Other 351.9 287.6 Less: Accumulated depreciation 1,620.1 1,479.1 Net 3,983.6 3,699.6 CWIP 166.0 121.4 Net utility property, plant, and equipment 4,149.6 3,821.0 Non-utility property, plant, and equipment 0.9 2.3 Less: Accumulated depreciation 0.4 0.4 Net 0.5 1.9 CWIP — 0.1 Net non-utility property, plant, and equipment 0.5 2.0 Total property, plant, and equipment $ 4,150.1 $ 3,823.0 |
Schedule of changes to our severance liability | In December 2017, a severance liability in the amount of $3.6 million was recorded in other current liabilities related to these plant retirements. (in millions) Severance liability at December 31, 2017 $ 3.6 Severance payments (0.8 ) Total severance liability at December 31, 2018 $ 2.8 |
JOINTLY OWNED UTILITY FACILIT_2
JOINTLY OWNED UTILITY FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
Schedule of Jointly Owned Utility Plants | Information related to jointly owned utility facilities at December 31, 2018 was as follows: (in millions, except for percentages and MW) Weston Unit 4 Columbia Energy Center Units 1 and 2 (2) Forward Wind Energy Center Ownership 70.0 % 28.1 % 44.6 % Our share of rated capacity (MW) (1) 384.9 314.8 8.7 In-service date 2008 1975 and 1978 2008 Property, plant, and equipment $ 615.4 $ 438.8 $ 123.7 Accumulated depreciation $ (205.2 ) $ (132.2 ) $ (43.7 ) CWIP $ 1.9 $ 0.3 $ 0.1 (1) Values are primarily based on the net dependable capacity ratings for summer 2019 using historical generation. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. (2) Columbia Energy Center (Columbia) is jointly owned by Wisconsin Power and Light (WPL), Madison Gas and Electric (MGE), and us. In October 2016, WPL received an order from the PSCW approving amendments to the Columbia joint operating agreement between the parties allowing MGE and us to forgo certain capital expenditures at Columbia. As a result, WPL will incur these capital expenditures in exchange for a proportional increase in its ownership share of Columbia. Based upon the additional capital expenditures WPL expects to incur through June 1, 2020, our ownership interest would decrease to 27.5% . |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes to asset retirement obligations | The following table shows changes to our AROs during the years ended December 31: (in millions) 2018 2017 2016 Balance as of January 1 $ 34.1 $ 32.6 $ 32.7 Accretion 1.8 1.6 1.5 Additions and revisions to estimated cash flows 16.6 (1) 0.4 (1.6 ) (2) Liabilities settled (1.7 ) (0.5 ) — Balance as of December 31 $ 50.8 $ 34.1 $ 32.6 (1) AROs increased $10.7 million in 2018 due to revisions made to estimated cash flows for the abatement of asbestos at our Pulliam power plant. A $5.6 million ARO was also recorded during 2018 for the legal requirement to dismantle, at retirement, the wind generation project known as Forward Wind Energy Center. See Note 2, Acquisitions, for more information on Forward Wind Energy Center. (2) During 2016, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs. |
GOODWILL AND OTHER INTANGIBLE_2
GOODWILL AND OTHER INTANGIBLE ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of identifiable intangible assets other than goodwill | The identifiable intangible assets other than goodwill listed below are classified as other long-term assets on our balance sheets. December 31, 2018 December 31, 2017 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 8.3 $ (6.8 ) $ 1.5 $ 8.3 $ (5.6 ) $ 2.7 Unamortized intangible assets 0.4 — 0.4 0.4 — 0.4 Total intangible assets $ 8.7 $ (6.8 ) $ 1.9 $ 8.7 $ (5.6 ) $ 3.1 * Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining amortization period at December 31, 2018 , was approximately one year . |
COMMON EQUITY (Tables)
COMMON EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation expense and related deferred tax benefit recognized in income | 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) 2018 2017 2016 Stock options $ 0.9 $ 0.6 $ 0.5 Restricted stock 1.7 0.7 1.4 Performance units 3.6 3.3 1.5 Stock-based compensation expense $ 6.2 $ 4.6 $ 3.4 Related tax benefit $ 1.7 $ 1.8 $ 1.4 |
Schedule of stock option activity | The following is a summary of our employees' WEC Energy Group stock option activity during 2018 : 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, 2018 47,785 $ 56.80 Granted 21,265 $ 66.02 Transferred 1,965 $ 62.01 Outstanding as of December 31, 2018 71,015 $ 59.70 8.0 $ 0.7 Exercisable as of December 31, 2018 7,410 $ 58.26 7.7 $ 0.1 |
Schedule of restricted stock activity | The following is a summary of our employees' WEC Energy Group restricted stock activity during 2018 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding and unvested as of January 1, 2018 11,202 $ 56.01 Granted 1,953 $ 64.99 Released (5,394 ) $ 55.86 Transferred 457 $ 57.88 Forfeited (793 ) $ 57.38 Outstanding and unvested as of December 31, 2018 7,425 $ 58.45 |
SHORT-TERM DEBT AND LINES OF _2
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Short-term Debt [Abstract] | |
Short-term debt balances and their corresponding weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2018 2017 Commercial paper Amount outstanding at December 31 $ 284.4 $ 293.1 Average interest rate on amounts outstanding at December 31 2.85 % 1.72 % |
Schedule of revolving credit facilities and remaining available capacity | The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 : (in millions) Maturity 2018 Revolving credit facility October 2022 $ 400.0 Less: Letters of credit issued inside credit facility 1.3 Commercial paper outstanding 284.4 Available capacity under existing agreement $ 114.3 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of all principal debt payment amounts related to bond maturities | The following table shows the future maturities of our long-term debt outstanding as of December 31, 2018 : (in millions) Payments 2019 $ — 2020 — 2021 400.0 2022 — 2023 — Thereafter 925.0 Total $ 1,325.0 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Tax Disclosure [Abstract] | |
Summary of income tax expense | The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2018 2017 2016 Current tax expense (benefit) $ 56.7 $ 22.0 $ (52.5 ) Deferred income taxes, net 20.9 78.0 143.3 Investment tax credit, net (0.3 ) (0.3 ) (0.3 ) Total income tax expense $ 77.3 $ 99.7 $ 90.5 |
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: 2018 2017 2016 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 52.5 21.0 % $ 89.1 35.0 % $ 86.2 35.0 % State income taxes net of federal tax benefit 15.4 6.2 % 12.7 5.0 % 11.6 4.7 % Federal excess amortization * 11.6 4.6 % — — % — — % AFUDC – Equity (1.0 ) (0.4 )% (1.4 ) (0.5 )% (6.8 ) (2.7 )% Other, net (1.2 ) (0.5 )% (0.7 ) (0.3 )% (0.5 ) (0.2 )% Total income tax expense $ 77.3 30.9 % $ 99.7 39.2 % $ 90.5 36.8 % * See Note 21, Regulatory Environment, for more information about the impact of the Tax Legislation. |
Components of deferred income taxes classified as net current assets and net long-term liabilities | The components of deferred income taxes as of December 31 are as follows: (in millions) 2018 2017 Deferred tax assets Tax gross up – regulatory items $ 105.5 $ 99.3 Other 23.9 7.9 Total deferred tax assets $ 129.4 $ 107.2 Deferred tax liabilities Property-related 588.1 563.5 Employee benefits and compensation 40.9 37.7 Other 21.2 18.7 Total deferred tax liabilities 650.2 619.9 Deferred tax liability, net $ 520.8 $ 512.7 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy | 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, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.8 $ — $ — $ 0.8 FTRs — — 3.0 3.0 Coal contracts — 0.4 — 0.4 Total derivative assets $ 0.8 $ 0.4 $ 3.0 $ 4.2 Derivative liabilities Natural gas contracts $ 1.1 $ — $ — $ 1.1 December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.8 $ — $ — $ 0.8 Petroleum products contracts 0.3 — — 0.3 FTRs — — 2.0 2.0 Coal contracts — 0.4 — 0.4 Total derivative assets $ 1.1 $ 0.4 $ 2.0 $ 3.5 Derivative liabilities Natural gas contracts $ 2.3 $ — $ — $ 2.3 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 2.3 $ 0.5 $ — $ 2.8 |
Reconciliation of changes in the fair value of items categorized as Level 3 measurements | The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2018 2017 2016 Balance at the beginning of the period $ 2.0 $ 2.0 $ 2.0 Realized and unrealized losses — — (0.2 ) Purchases 9.0 6.9 7.1 Sales — — (0.2 ) Settlements (8.0 ) (6.9 ) (6.7 ) Balance at the end of the period $ 3.0 $ 2.0 $ 2.0 |
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2018 December 31, 2017 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,314.7 $ 1,372.9 $ 1,166.2 $ 1,302.4 |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative assets and derivative liabilities | The following table shows our derivative assets and derivative liabilities, none of which are designated as hedging instruments. December 31, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.8 $ 1.0 $ 0.8 $ 1.9 Petroleum products contracts — — 0.3 — FTRs 3.0 — 2.0 — Coal contracts 0.2 — — 0.5 Total other current $ 4.0 $ 1.0 $ 3.1 $ 2.4 Other long-term Natural gas contracts $ — $ 0.1 $ — $ 0.4 Coal contracts 0.2 — 0.4 — Total other long-term $ 0.2 $ 0.1 $ 0.4 $ 0.4 Total $ 4.2 $ 1.1 $ 3.5 $ 2.8 |
Estimated notional volumes and realized gains (losses) | Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2018 December 31, 2017 December 31, 2016 (in millions) Volume Gains Volume Gains (Losses) Volume Gains (Losses) Natural gas contracts 38.4 Dth $ 5.1 18.6 Dth $ (2.4 ) 28.6 Dth $ (1.4 ) Petroleum products contracts 1.8 gallons 0.4 1.3 gallons 0.1 4.4 gallons (0.6 ) FTRs 9.3 MWh 12.5 9.1 MWh 6.4 8.4 MWh 6.0 Total $ 18.0 $ 4.1 $ 4.0 |
Offsetting assets and liabilities | The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2018 December 31, 2017 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 4.2 $ 1.1 $ 3.5 $ 2.8 Gross amount not offset on the balance sheet (0.8 ) (1.1 ) (1) (1.1 ) (2.3 ) (2) Net amount $ 3.4 $ — $ 2.4 $ 0.5 (1) Includes cash collateral posted of $0.3 million . (2) Includes cash collateral posted of $1.2 million . |
EMPLOYEE BENEFITS (Tables)
EMPLOYEE BENEFITS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Retirement Benefits [Abstract] | |
Reconciliation of the changes in the plans' benefit obligations and fair value of assets | The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2018 2017 2018 2017 Change in benefit obligation Obligation at January 1 $ 704.7 $ 655.2 $ 220.2 $ 223.1 Service cost 10.4 9.0 6.1 6.2 Interest cost 26.0 26.7 8.2 9.1 Plan amendments — — (1.5 ) (21.7 ) Net transfer to/from affiliates — — (0.1 ) — Actuarial (gain) loss (42.7 ) 45.1 (70.7 ) 12.2 Participant contributions — — 1.2 1.0 Benefit payments (34.3 ) (31.3 ) (9.9 ) (9.7 ) Transfer — — (2.1 ) $ — Obligation at December 31 $ 664.1 $ 704.7 $ 151.4 $ 220.2 Change in fair value of plan assets Fair value at January 1 $ 712.4 $ 736.6 $ 250.5 $ 231.1 Actual return on plan assets (39.4 ) 99.2 (10.3 ) 27.1 Employer contributions 0.6 65.7 0.1 1.0 Participant contributions — — 1.2 1.0 Benefit payments (34.3 ) (31.3 ) (9.9 ) (9.7 ) Net transfer to/from affiliates — (157.8 ) * 0.1 — Fair value at December 31 $ 639.3 $ 712.4 $ 231.7 $ 250.5 Funded status at December 31 $ (24.8 ) $ 7.7 $ 80.3 $ 30.3 * Related to our transfer of pension trust assets in conjunction with the Integrys pension plan split for the year ended December 31, 2017. Assets were transferred out of our plan in January 2017. See Note 3, Related Parties, for more information . |
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans | The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2018 2017 2018 2017 Pension and OPEB assets $ — $ 15.6 $ 92.8 $ 46.4 Pension and OPEB obligations 24.8 7.9 12.5 16.1 Total net (liabilities) assets $ (24.8 ) $ 7.7 $ 80.3 $ 30.3 |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2018 2017 Projected benefit obligation $ 7.3 $ 7.9 Accumulated benefit obligation 7.3 7.9 |
Amounts that had not yet been recognized in the entity's net periodic benefit cost | The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2018 2017 2018 2017 Net regulatory assets (liabilities) Net actuarial loss (gain) $ 220.4 $ 196.5 $ (17.9 ) $ 27.2 Prior service credits — — (82.8 ) (92.6 ) Total $ 220.4 $ 196.5 $ (100.7 ) $ (65.4 ) |
Estimated amounts that will be amortized into net periodic benefit cost | The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2019 : (in millions) Pension Costs OPEB Costs Net actuarial loss $ 17.8 $ 1.6 Prior service credits — (11.4 ) Total 2019 – estimated amortization $ 17.8 $ (9.8 ) |
Schedule of the components of net periodic benefit cost | The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2018 2017 2016 2018 2017 2016 Service cost $ 10.4 $ 9.0 $ 9.9 $ 6.1 $ 6.2 $ 7.3 Interest cost 26.0 26.7 27.0 8.2 9.1 10.6 Expected return on plan assets (48.3 ) (46.4 ) (52.6 ) (17.8 ) (16.7 ) (15.9 ) Loss on plan settlement — — 3.4 — — — Amortization of prior service credit — — — (11.3 ) (9.8 ) (7.4 ) Amortization of net actuarial loss 21.1 17.3 18.0 2.5 2.5 2.5 Net periodic benefit cost (credit) $ 9.2 $ 6.6 $ 5.7 $ (12.3 ) $ (8.7 ) $ (2.9 ) |
Schedule of financial statement impacts from retrospective restatements | The impacts to our income statements from adoption of this standard are reflected in the table below. Year Ended December 31, 2017 Year Ended December 31, 2016 (in millions) Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Form 10-K Income Statement Impact of ASU 2017-07 Income Statement After Adoption Operating expenses Other operation and maintenance $ 435.8 $ 11.8 $ 447.6 $ 493.2 $ 10.5 $ 503.7 Other expense Other income, net 11.9 11.8 23.7 30.8 10.5 41.3 |
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans | The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2018 2017 2018 2017 Discount rate 4.30% 3.70% 4.29% 3.67% Rate of compensation increase 4.00% 4.00% N/A N/A Assumed medical cost trend rate (Pre 65) N/A N/A 6.25% 6.50% 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 2024 2024 Assumed medical cost trend rate (Post 65) N/A N/A 5.90% 6.00% 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 net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2018 2017 2016 Discount rate 3.70% 4.19% 4.25% Expected return on assets 7.25% 7.25% 7.25% Rate of compensation increase 4.00% 4.00% 4.00% OPEB Costs 2018 2017 2016 Discount rate 3.67% 4.11% 4.46% Expected return on assets 7.25% 7.25% 7.25% Assumed medical cost trend rate (Pre 65) 6.50% 7.00% 7.50% Ultimate trend rate (Pre 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Pre 65) 2024 2021 2021 Assumed medical cost trend rate (Post 65) 6.00% 7.00% 7.50% Ultimate trend rate (Post 65) 5.00% 5.00% 5.00% Year ultimate trend rate is reached (Post 65) 2028 2021 2021 |
Effects of a one-percentage-point change in assumed health care cost trend rates | For the year ended December 31, 2018 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 2.5 $ (1.9 ) Effect on the health care component of the accumulated postretirement benefit obligation 15.2 (12.1 ) |
Investments recorded at fair value, by asset class | The following tables provide the fair values of our investments by asset class: December 31, 2018 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Equity securities: United States Equity $ 79.0 $ — $ — $ 79.0 $ 24.0 $ — $ — $ 24.0 International Equity 80.1 0.3 — 80.4 27.0 0.2 — 27.2 Fixed income securities: * United States Bonds 16.3 119.1 — 135.4 46.9 37.0 — 83.9 International Bonds 2.3 21.0 — 23.3 2.5 1.6 — 4.1 $ 177.7 $ 140.4 $ — $ 318.1 $ 100.4 $ 38.8 $ — $ 139.2 Investments measured at net asset value $ 321.2 $ 92.5 Total $ 177.7 $ 140.4 $ — $ 639.3 $ 100.4 $ 38.8 $ — $ 231.7 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2017 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ — $ 22.2 $ — $ 22.2 $ 9.2 $ 0.3 $ — $ 9.5 Equity securities: United States Equity 97.9 — — 97.9 26.5 — — 26.5 International Equity 98.2 — 0.4 98.6 31.8 — 0.2 32.0 Fixed income securities: * United States Bonds 17.8 129.2 — 147.0 47.0 35.7 — 82.7 International Bonds 2.3 21.2 — 23.5 2.5 1.8 — 4.3 Private Equity and Real Estate — 62.9 12.5 75.4 — 0.7 0.1 0.8 $ 216.2 $ 235.5 $ 12.9 $ 464.6 $ 117.0 $ 38.5 $ 0.3 $ 155.8 Investments measured at net asset value $ 247.8 $ 94.7 Total $ 216.2 $ 235.5 $ 12.9 $ 712.4 $ 117.0 $ 38.5 $ 0.3 $ 250.5 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. |
Reconciliation of changes in the fair value of plan assets categorized as Level 3 measurements | The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate International Equity (in millions) Pension OPEB Pension OPEB Beginning balance at January 1, 2018 $ 12.5 $ 0.1 $ 0.4 $ 0.2 Realized and unrealized losses 0.7 — (0.1 ) — Purchases 2.4 — — — Transfers out of level 3 (15.6 ) (0.1 ) (0.3 ) (0.2 ) Ending balance at December 31, 2018 $ — $ — $ — $ — Private Equity and Real Estate International Equity U.S. Bonds (in millions) Pension OPEB Pension OPEB Pension Beginning balance at January 1, 2017 $ — $ — $ — $ — $ 0.5 Realized and unrealized losses — — (0.1 ) — (0.5 ) Purchases 12.5 0.1 0.5 0.2 — Ending balance at December 31, 2017 $ 12.5 $ 0.1 $ 0.4 $ 0.2 $ — |
Schedule of expected future benefit payments | The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB. (in millions) Pension Costs OPEB Costs 2019 $ 34.7 $ 7.8 2020 35.5 8.9 2021 36.5 9.2 2022 37.0 8.7 2023 36.3 8.9 2024-2028 185.7 46.9 |
SEGMENTS INFORMATION (Tables)
SEGMENTS INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Segment Reporting [Abstract] | |
Schedule of information related to reportable segments | The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2018 , 2017 , and 2016 . 2018 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,498.5 $ — $ — $ 1,498.5 Other operation and maintenance 447.5 0.5 — 448.0 Depreciation and amortization 141.9 — — 141.9 Operating income (loss) 267.1 (0.7 ) — 266.4 Other income, net 35.2 2.4 — 37.6 Interest expense 53.9 — — 53.9 Capital expenditures and asset acquisitions 521.4 — — 521.4 Total assets 5,151.5 66.2 — 5,217.7 2017 (in millions) Utility Other Reconciling Eliminations Wisconsin Public Service Corporation Consolidated External revenues $ 1,485.4 $ — $ — $ 1,485.4 Other operation and maintenance * 446.1 1.5 — 447.6 Depreciation and amortization 139.3 — — 139.3 Operating income (loss) * 286.7 (1.6 ) — 285.1 Other income, net * 21.0 2.7 — 23.7 Interest expense 54.2 — — 54.2 Capital expenditures 335.8 — — 335.8 Total assets 4,678.1 70.6 — 4,748.7 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 17, Employee Benefits, for more information on this new standard. 2016 (in millions) Utility Other Reconciling Wisconsin Public Service Corporation Consolidated External revenues $ 1,448.2 $ — $ — $ 1,448.2 Intersegment revenues — 0.3 (0.3 ) — Other operation and maintenance * 503.0 1.0 (0.3 ) 503.7 Depreciation and amortization 124.0 0.1 — 124.1 Operating income (loss) * 253.9 (0.9 ) — 253.0 Other income, net * 33.8 7.5 — 41.3 Interest expense 48.0 0.1 — 48.1 Capital expenditures 311.1 — — 311.1 Total assets 4,686.4 121.8 — 4,808.2 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 17, Employee Benefits, for more information on this new standard. |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum future commitments related to purchase obligations | The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2018 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2019 2020 2021 2022 2023 Later Years Electric utility: Purchased power 2041 $ 410.8 $ 75.1 $ 48.2 $ 46.8 $ 41.8 $ 39.7 $ 159.2 Coal supply and transportation 2024 325.4 115.0 63.1 48.2 47.6 50.8 0.7 Natural gas utility supply and transportation 2048 449.9 51.7 50.3 46.4 43.0 26.9 231.6 Total $ 1,186.1 $ 241.8 $ 161.6 $ 141.4 $ 132.4 $ 117.4 $ 391.5 |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2018 2017 Regulatory assets $ 108.3 $ 116.0 Reserves for future remediation 90.3 99.6 |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | (in millions) 2018 2017 2016 Cash (paid) for interest, net of amount capitalized $ (52.9 ) $ (55.5 ) $ (54.6 ) Cash (paid) received for income taxes, net (36.6 ) (18.1 ) 39.9 Significant non-cash transactions: Accounts payable related to construction costs 8.1 46.4 67.2 Receivable related to corporate-owned life insurance proceeds 6.4 — — Transfer of ownership in WPSI to another subsidiary of Integrys * — 67.2 — Transfer of net assets to UMERC * 0.4 20.6 — * See Note 3, Related Parties, for more information on these transactions. |
OTHER INCOME, NET (Tables)
OTHER INCOME, NET (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Income and Expenses [Abstract] | |
Schedule of other income, net | Total other income, net was as follows for the years ended December 31 : (in millions) 2018 2017 2016 AFUDC – Equity $ 4.6 $ 4.1 $ 19.5 Non-service components of net periodic benefit costs 16.7 11.8 10.5 Earnings from equity method investments 0.8 1.1 9.5 Other, net 15.5 6.7 1.8 Other income, net $ 37.6 $ 23.7 $ 41.3 |
QUARTERLY FINANCIAL INFORMATI_2
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of quarterly financial information (unaudited) | (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018 Operating revenues $ 393.6 $ 350.1 $ 379.2 $ 375.6 $ 1,498.5 Operating income 69.2 72.4 86.4 38.4 266.4 Net income 49.8 42.7 57.0 23.3 172.8 2017 Operating revenues $ 389.6 $ 341.6 $ 380.7 $ 373.5 $ 1,485.4 Operating income * 73.0 58.1 108.2 45.8 285.1 Net income 39.3 30.7 60.9 24.0 154.9 * Includes the retroactive restatement impacts of the implementation of ASU 2017-07. See Note 17, Employee Benefits, for more information on this new standard. |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CASH AND CASH EQUIVALENTS (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Cash and cash equivalents | |
Maximum term of original maturity to classify instrument as cash equivalents | 3 months |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES OPERATING REVENUES (Details) | 12 Months Ended |
Dec. 31, 2018contractperformance_obligations | |
Disaggregation of Operating Revenues | |
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required | 2.00% |
Electric | |
Disaggregation of Operating Revenues | |
Number of performance obligations | 1 |
Number of contracts | contract | 1 |
Number of days payment is due | 30 days |
Electric | Wholesale | |
Disaggregation of Operating Revenues | |
Number of performance obligations | 2 |
Natural gas | |
Disaggregation of Operating Revenues | |
Number of days payment is due | 30 days |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Accounting Policies [Abstract] | ||
Materials and supplies | $ 48.9 | $ 40.8 |
Fossil fuel | 29.2 | 43.8 |
Natural gas in storage | 24.9 | 22.4 |
Total | $ 103 | $ 107 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PROPERTY, PLANT, AND EQUIPMENT (Details) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.50% | 2.55% | 2.58% |
Software | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 3 years | ||
Software | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 15 years |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AFUDC (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
AFUDC | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC calculation | 50.00% | ||
Allowance for borrowed funds used during construction | $ 1.9 | $ 1.6 | $ 8.1 |
Allowance for equity funds used during construction | $ 4.6 | $ 4.1 | $ 19.5 |
Retail | |||
AFUDC | |||
Average AFUDC rate (as a percent) | 7.72% | 7.72% | 7.72% |
Wholesale | |||
AFUDC | |||
Average AFUDC rate (as a percent) | 1.96% | 1.01% | 3.00% |
SUMMARY OF SIGNIFICANT ACCOUN_9
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES STOCK-BASED COMPENSATION (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares of WEC Energy Group common stock authorized for issuance | 34,300,000 | ||
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Minimum exercise price of stock option as a percent of WEC Energy Group common stock fair value on the grant date | 100.00% | ||
Period after the grant date during which stock options can't be exercised (in months) | 6 months | ||
Maximum term of awards | 10 years | ||
Stock options granted | 21,265 | 23,300 | 24,485 |
Estimated weighted-average fair value per stock option (in dollars per share) | $ 7.68 | $ 7.53 | $ 5.63 |
Risk-free interest rate, minimum (as a percent) | 1.60% | 0.70% | 0.40% |
Risk-free interest rate, maximum (as a percent) | 2.50% | 2.50% | 1.80% |
Dividend yield (as a percent) | 3.50% | 3.50% | 4.00% |
Expected Volatility (as a percent) | 18.00% | 19.00% | 18.00% |
Expected life (years) | 5 years 10 months | 6 years 11 months | 7 years 6 months |
Restricted stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Percentage to vest each year after the grant date | 33.00% | ||
Performance units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Performance units | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payout ratio (as a percent) | 0.00% | ||
Performance units | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Payout ratio (as a percent) | 175.00% |
SUMMARY OF SIGNIFICANT ACCOU_10
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GUARANTEES (Details) $ in Millions | Dec. 31, 2018USD ($) |
Standby letters of credit | |
Guarantor Obligations | |
Guarantee with expiration over three years | $ 20.6 |
SUMMARY OF SIGNIFICANT ACCOU_11
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CUSTOMER CONCENTRATION OF CREDIT RISK (Details) - Customer concentration risk | 12 Months Ended |
Dec. 31, 2018customer | |
Customer concentrations of credit risk | |
Number of customers that account for more than 10% of revenues | 0 |
Threshold percentage of revenues from major customers | 10.00% |
FORWARD WIND ENERGY ACQUISITION
FORWARD WIND ENERGY ACQUISITION (Details) - Forward Wind Energy Center Acquisition $ in Millions | 1 Months Ended |
Apr. 30, 2018USD ($)wind_turbinesutilityMW | |
Business Acquisition [Line Items] | |
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility | 2 |
Number of wind turbines at Forward Wind Energy Center | wind_turbines | 86 |
Capacity of Foward Wind Energy Center | MW | 138 |
Business Combination, Consideration Transferred | $ 172.9 |
WPS | |
Business Acquisition [Line Items] | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets | $ 0.2 |
WPS's share of Forward Wind Energy Center's purchase price | 44.60% |
Percentage of Forward Wind Energy Center's output purchased by WPS | 44.60% |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment | $ 76.9 |
Business Combination, Consideration Transferred | $ 77.1 |
RELATED PARTIES - OTHER TRANSAC
RELATED PARTIES - OTHER TRANSACTIONS (Details) $ in Millions | Jan. 01, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016 |
WBS | ||||
Related parties | ||||
Number of other significant changes from the non-IBS affiliated interest agreement | 0 | |||
Integrys | ||||
Related parties | ||||
Liability related to income tax allocation | $ 3.5 | $ 4.1 | ||
WPS Investments, LLC | ||||
Related parties | ||||
Equity method investment, ownership interest (as a percent) | 10.37% | |||
ATC | ||||
Related parties | ||||
Equity method investment, ownership interest (as a percent) | 34.00% | |||
Equity method investment transfer to affiliated company | $ 67.2 | |||
Transfer of deferred income tax related to ATC to affiliated company | $ 41.9 | |||
Accounts receivable for services provided to ATC | 1.2 | $ 0.7 | ||
Accounts payable to ATC for network transmission services | $ 8.8 | $ 9 |
RELATED PARTIES (Details)
RELATED PARTIES (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jun. 30, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jan. 01, 2017plan | |
Related parties | |||||
Equity earnings from WPS Investments, LLC | $ 0.8 | $ 1.1 | $ 9.5 | ||
Payments for assets received from Affiliates | 32.9 | 10.1 | 34.1 | ||
Payments for transfer of liabilities to related party | 18.2 | ||||
Proceeds from assets transferred to related party | 0 | 157.8 | 0 | ||
ATC | |||||
Related parties | |||||
Charges to equity method investee for services, construction, and/or operations | 7.9 | 6.2 | 8.6 | ||
Billings from related party for services, pass through costs and other items | 106.1 | 107.8 | 109.4 | ||
Refund from ATC related to a FERC audit | 6.6 | 0 | 0 | ||
Refund from ATC per FERC ROE order | 0 | 8.9 | 0 | ||
WRPC | |||||
Related parties | |||||
Charges to equity method investee for services, construction, and/or operations | 1.2 | 0.9 | 0.7 | ||
Billings from related party for services, pass through costs and other items | 2.4 | 2.2 | 0 | ||
Rental payments to WRPC | 1.3 | 1.3 | 0 | ||
Purchases of energy from WRPC | $ 0 | 0.5 | 3.7 | ||
Rental Agreement with WRPC | 50.00% | ||||
WPS Investments, LLC | |||||
Related parties | |||||
Equity earnings from WPS Investments, LLC | $ 0 | 0 | 8.7 | ||
WE | |||||
Related parties | |||||
Charges to equity method investee for services, construction, and/or operations | 10.9 | 4.5 | 4.2 | ||
Billings from related party for services, pass through costs and other items | 17.8 | 28.2 | 9 | ||
WBS | |||||
Related parties | |||||
Charges to equity method investee for services, construction, and/or operations | 17 | 174.9 | 21.7 | ||
Billings from related party for services, pass through costs and other items | 111 | 132.9 | 171 | ||
Proceeds from assets transferred to related party | 157.8 | 7.3 | |||
Bluewater | |||||
Related parties | |||||
Billings from related party for services, pass through costs and other items | 4.7 | 0.3 | 0 | ||
Acquisition of Bluewater | $ 226 | ||||
Natural gas | WE | |||||
Related parties | |||||
Sales to related party | 1.9 | 1.6 | 1.9 | ||
Natural gas | UMERC | |||||
Related parties | |||||
Sales to related party | 2.7 | 2.5 | 0 | ||
Electric | UMERC | |||||
Related parties | |||||
Sales to related party | $ 15.8 | $ 16.2 | $ 0 | ||
Pension Plan | Integrys Energy Group Retirement Plan Split | |||||
Related parties | |||||
Number of separate pension plans created from split | plan | 6 |
RELATED PARTIES - UMERC (Detail
RELATED PARTIES - UMERC (Details) - UMERC transfer $ in Millions | Jan. 01, 2017USD ($)customermile |
Related parties | |
Miles of electric distribution lines transferred | mile | 600 |
Miles of gas distribution mains transferred | mile | 100 |
Transfer of net assets to affiliate | $ | $ 20.6 |
Electric utility | |
Related parties | |
Number of customers | customer | 9,000 |
Natural gas utility segment | |
Related parties | |
Number of customers | customer | 5,300 |
OPERATING REVENUES - DISAGGREGA
OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENUES BY SEGMENT (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | $ 375.6 | $ 379.2 | $ 350.1 | $ 393.6 | $ 373.5 | $ 380.7 | $ 341.6 | $ 389.6 | $ 1,498.5 | $ 1,485.4 | $ 1,448.2 |
Utility | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 1,498.5 | $ 1,485.4 | $ 1,448.2 | ||||||||
Utility | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 0.8 | ||||||||||
Utility | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 1,497.7 | ||||||||||
Utility | Electric | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | 1,192.2 | ||||||||||
Utility | Natural gas | Transferred over time | Revenues from contracts with customers | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Revenues from contracts with customers | $ 305.5 |
OPERATING REVENUES - DISAGGRE_2
OPERATING REVENUES - DISAGGREGATION OF ELECTRIC UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Utility - Revenues from contracts with customers - Transferred over time $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | $ 1,497.7 |
Electric | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 1,192.2 |
Electric | Total retail revenues | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 1,000.2 |
Electric | Residential | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 381.5 |
Electric | Small commercial and industrial | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 371.4 |
Electric | Large commercial and industrial | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 238.8 |
Electric | Other | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 8.5 |
Electric | Wholesale | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 142.3 |
Electric | Resale | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 38.5 |
Electric | Other utility revenues | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | $ 11.2 |
OPERATING REVENUES - DISAGGRE_3
OPERATING REVENUES - DISAGGREGATION OF NATURAL GAS UTILITY OPERATING REVENUES BY CUSTOMER CLASS (Details) - Utility - Revenues from contracts with customers - Transferred over time $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | $ 1,497.7 |
Natural gas | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 305.5 |
Natural gas | Total retail revenues | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 285.3 |
Natural gas | Residential | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 177.7 |
Natural gas | Commercial and industrial | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 107.6 |
Natural gas | Transport | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | 19.7 |
Natural gas | Other utility revenues | |
Disaggregation of Operating Revenues | |
Revenues from contracts with customers | $ 0.5 |
OPERATING REVENUES - OTHER OPER
OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | $ 375.6 | $ 379.2 | $ 350.1 | $ 393.6 | $ 373.5 | $ 380.7 | $ 341.6 | $ 389.6 | $ 1,498.5 | $ 1,485.4 | $ 1,448.2 |
Utility | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 1,498.5 | $ 1,485.4 | $ 1,448.2 | ||||||||
Utility | Other operating revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 0.8 | ||||||||||
Utility | Other operating revenues | Late payment charges | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 2.9 | ||||||||||
Utility | Other operating revenues | Leases | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | 0.2 | ||||||||||
Utility | Other operating revenues | Alternative revenues | |||||||||||
Disaggregation of Operating Revenues | |||||||||||
Operating revenues | $ (2.3) |
REGULATORY ASSETS AND LIABILI_3
REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Regulatory assets | ||
Current assets | $ 0.3 | $ 0 |
Regulatory assets | 485.6 | 382.8 |
Total regulatory assets | 485.9 | 382.8 |
Allowance for return on equity capitalized for regulatory purposes | 14.7 | 14.4 |
Regulatory assets not earning a return | 31.9 | |
Regulatory assets earning a return based on short-term interest rates | 5.3 | |
Estimated future cash expenditures for environmental remediation | 90.3 | 99.6 |
Pension and OPEB costs | ||
Regulatory assets | ||
Total regulatory assets | 189.8 | 161.3 |
Environmental remediation costs | ||
Regulatory assets | ||
Total regulatory assets | 108.3 | 116 |
Cash expenditures for environmental remediation costs | 18 | |
Estimated future cash expenditures for environmental remediation | 90.3 | |
Plant retirements | ||
Regulatory assets | ||
Total regulatory assets | 78.1 | 8.3 |
Income tax related items | ||
Regulatory assets | ||
Total regulatory assets | 38.1 | 8.2 |
Termination of a tolling agreement with Fox Energy Company LLC | ||
Regulatory assets | ||
Total regulatory assets | $ 21.7 | 27.2 |
Authorized recovery period | 9 years | |
Asset retirement obligations (AROs) | ||
Regulatory assets | ||
Total regulatory assets | $ 11.5 | 9.7 |
De Pere Energy Center | ||
Regulatory assets | ||
Total regulatory assets | 10.1 | 14 |
Crane Creek wind project production tax credits | ||
Regulatory assets | ||
Total regulatory assets | 0.4 | 22.8 |
Other, net | ||
Regulatory assets | ||
Total regulatory assets | $ 27.9 | $ 15.3 |
REGULATORY ASSETS AND LIABILI_4
REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Regulatory liabilities | ||
Current liabilities | $ 7.2 | $ 7.9 |
Regulatory liabilities | 785.7 | 689.3 |
Total regulatory liabilities | 792.9 | 697.2 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 418.8 | 393.8 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 241.8 | 238.9 |
Pension and OPEB costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 72.6 | 30.2 |
Earnings sharing mechanisms | ||
Regulatory liabilities | ||
Total regulatory liabilities | 21.2 | 0 |
Energy costs refundable through rate adjustments | ||
Regulatory liabilities | ||
Total regulatory liabilities | 14.3 | 8.2 |
Electric transmission costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 9.7 | 6 |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 14.5 | $ 20.1 |
PROPERTY, PLANT, AND EQUIPMEN_2
PROPERTY, PLANT, AND EQUIPMENT - Balances (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Property, plant, and equipment | ||
Accumulated depreciation | $ 1,620.5 | $ 1,633.3 |
Net property, plant, and equipment | 4,150.1 | 3,823 |
Utility operations | ||
Property, plant, and equipment | ||
Accumulated depreciation | 1,620.1 | 1,479.1 |
Net | 3,983.6 | 3,699.6 |
Construction in Progress, Gross | 166 | 121.4 |
Net property, plant, and equipment | 4,149.6 | 3,821 |
Utility operations | Electric - generation | ||
Property, plant, and equipment | ||
Property, Plant And Equipment, Gross, Excluding Construction Work In Progress | 2,831.2 | 2,624.9 |
Utility operations | Electric - distribution | ||
Property, plant, and equipment | ||
Property, Plant And Equipment, Gross, Excluding Construction Work In Progress | 1,510 | 1,361.9 |
Utility operations | Natural gas - distribution, storage, and transmission | ||
Property, plant, and equipment | ||
Property, Plant And Equipment, Gross, Excluding Construction Work In Progress | 910.6 | 846.4 |
Utility operations | Property, plant, and equipment to be retired, net | ||
Property, plant, and equipment | ||
Long-lived Assets To Be Abandoned, Net | 0 | 57.9 |
Utility operations | Other | ||
Property, plant, and equipment | ||
Property, Plant And Equipment, Gross, Excluding Construction Work In Progress | 351.9 | 287.6 |
Non-utility operations | ||
Property, plant, and equipment | ||
Accumulated depreciation | 0.4 | 0.4 |
Net | 0.5 | 1.9 |
Construction in Progress, Gross | 0 | 0.1 |
Net property, plant, and equipment | 0.5 | 2 |
Non-utility operations | Other | ||
Property, plant, and equipment | ||
Property, Plant And Equipment, Gross, Excluding Construction Work In Progress | $ 0.9 | $ 2.3 |
PROPERTY, PLANT, AND EQUIPMEN_3
PROPERTY, PLANT, AND EQUIPMENT - Plant Retirements (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Property, Plant and Equipment Impairment or Disposal [Abstract] | ||
Accumulated depreciation | $ 1,620.5 | $ 1,633.3 |
Net property, plant, and equipment | 4,150.1 | 3,823 |
Regulatory Assets | 485.9 | 382.8 |
Regulatory Liabilities | 792.9 | 697.2 |
Pulliam power plant | ||
Property, Plant and Equipment Impairment or Disposal [Abstract] | ||
Property, plant, and equipment, at carrying value | 33.8 | |
Regulatory Assets | 57.2 | |
Regulatory Liabilities | 23.4 | |
Edgewater Unit 4 | ||
Property, Plant and Equipment Impairment or Disposal [Abstract] | ||
Property, plant, and equipment, at carrying value | 8.1 | |
Regulatory Assets | 10 | |
Regulatory Liabilities | 1.9 | |
Utility operations | ||
Restructuring Reserve [Roll Forward] | ||
Restructuring Reserve Beginning of Period | 3.6 | |
Payments for Restructuring | (0.8) | |
Restructuring Reserve End of Period | 2.8 | |
Property, Plant and Equipment Impairment or Disposal [Abstract] | ||
Accumulated depreciation | 1,620.1 | 1,479.1 |
Net | 3,983.6 | 3,699.6 |
Construction in Progress, Gross | 166 | 121.4 |
Net property, plant, and equipment | $ 4,149.6 | $ 3,821 |
JOINTLY OWNED UTILITY FACILIT_3
JOINTLY OWNED UTILITY FACILITIES (Details) $ in Millions | Dec. 31, 2018USD ($)MW |
Weston 4 | |
Share of significant jointly owned electric generating facilities | |
Ownership (as a percent) | 70.00% |
Our share of rated capacity (MW) | MW | 384.9 |
Property, plant, and equipment | $ 615.4 |
Accumulated depreciation | (205.2) |
Construction work in progress | $ 1.9 |
Columbia Energy Center Units 1 and 2 | |
Share of significant jointly owned electric generating facilities | |
Ownership (as a percent) | 28.10% |
Our share of rated capacity (MW) | MW | 314.8 |
Property, plant, and equipment | $ 438.8 |
Accumulated depreciation | (132.2) |
Construction work in progress | $ 0.3 |
Forward Wind Energy Center | |
Share of significant jointly owned electric generating facilities | |
Ownership (as a percent) | 44.60% |
Our share of rated capacity (MW) | MW | 8.7 |
Property, plant, and equipment | $ 123.7 |
Accumulated depreciation | (43.7) |
Construction work in progress | $ 0.1 |
WPS | Columbia Energy Center Units 1 and 2 | |
Share of significant jointly owned electric generating facilities | |
Future Ownership Interest of Columbia | 27.50% |
ASSET RETIREMENT OBLIGATIONS (D
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Changes to asset retirement obligations | |||
Balance as of January 1 | $ 34.1 | $ 32.6 | $ 32.7 |
Accretion | 1.8 | 1.6 | 1.5 |
Additions and revisions to estimated cash flows | 16.6 | 0.4 | (1.6) |
Liabilities settled | (1.7) | (0.5) | 0 |
Balance as of December 31 | 50.8 | $ 34.1 | $ 32.6 |
Pulliam power plant | |||
Changes to asset retirement obligations | |||
ARO revision of estimate | 10.7 | ||
Forward Wind Energy Center | |||
Changes to asset retirement obligations | |||
AROs additions | $ 5.6 |
GOODWILL AND OTHER INTANGIBLE_3
GOODWILL AND OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Goodwill and other intangible assets | ||
Changes to the carrying amount of goodwill | $ 0 | $ 0 |
Goodwill impairment loss | 0 | |
Intangible assets other than goodwill | ||
Amortized intangible assets, accumulated amortization | (6.8) | (5.6) |
Unamortized intangible assets, carrying amount | 0.4 | 0.4 |
Total intangible assets, gross carrying amount | 8.7 | 8.7 |
Total intangible assets, net carrying amount | 1.9 | 3.1 |
Contractual service agreements | ||
Intangible assets other than goodwill | ||
Amortized intangible assets, gross carrying amount | 8.3 | 8.3 |
Amortized intangible assets, accumulated amortization | (6.8) | (5.6) |
Amortized intangible assets, net carrying amount | $ 1.5 | $ 2.7 |
Remaining amortization period | 1 year |
COMMON EQUITY - STOCK-BASED COM
COMMON EQUITY - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 6.2 | $ 4.6 | $ 3.4 |
Related tax benefit | 1.7 | 1.8 | 1.4 |
Stock options | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 0.9 | 0.6 | 0.5 |
Restricted stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 1.7 | 0.7 | 1.4 |
Performance units | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 3.6 | $ 3.3 | $ 1.5 |
COMMON EQUITY - STOCK OPTIONS (
COMMON EQUITY - STOCK OPTIONS (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Options Activity | ||||
Outstanding, shares, beginning balance | 71,015 | 47,785 | ||
Granted, shares | 21,265 | 23,300 | 24,485 | |
Transferred, shares | 1,965 | |||
Outstanding, shares, ending balance | 71,015 | 47,785 | ||
Options - Weighted Average Exercise Price | ||||
Outstanding, Weighted-Average Exercise Price, Beginning | $ 59.70 | $ 56.80 | ||
Granted, Weighted-Average Exercise Price | 66.02 | |||
Transferred, Weighted-Average Exercise Price | 62.01 | |||
Outstanding, Weighted-Average Exercise Price, Ending | $ 59.70 | $ 56.80 | ||
Options - Additional Disclosures | ||||
Outstanding, Weighted-Average Remaining Contractual Life (Years) | 8 years | |||
Outstanding, Aggregate Intrinsic Value | $ 0.7 | |||
Exercisable, shares | 7,410 | |||
Exercisable, Weighted-Average Exercise Price | $ 58.26 | |||
Exercisable, Weighted-Average Remaining Contractual Life (Years) | 7 years 8 months | |||
Exercisable, Aggregate Intrinsic Value | $ 0.1 | |||
Compensation cost not yet recognized | $ 0.6 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 7 months | |||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 7.68 | $ 7.53 | $ 5.63 | |
Subsequent event | ||||
Options Activity | ||||
Granted, shares | 21,638 | |||
Options - Weighted Average Exercise Price | ||||
Granted, Weighted-Average Exercise Price | $ 68.18 | |||
Options - Additional Disclosures | ||||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 8.60 |
COMMON EQUITY - RESTRICTED SHAR
COMMON EQUITY - RESTRICTED SHARES (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Restricted Stock Activity | ||||
Outstanding, shares, beginning of period | 7,425 | 11,202 | ||
Granted, shares | 1,953 | |||
Released, shares | (5,394) | 0 | ||
Transferred, shares | 457 | |||
Forfeited, shares | (793) | |||
Outstanding, shares, end of period | 7,425 | 11,202 | ||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Outstanding, weighted-average grant date fair value, beginning of period | $ 58.45 | $ 56.01 | ||
Granted, weighted-average grant date fair value | 64.99 | |||
Released, weighted-average grant date fair value | 55.86 | |||
Transferred, weighted-average grant date fair value | 57.88 | |||
Forfeited, weighted-average grant date fair value | 57.38 | |||
Outstanding, weighted-average grant date fair value, end of period | $ 58.45 | $ 56.01 | ||
Restricted Stock - Additional Disclosures | ||||
Intrinsic value of released restricted shares | $ 0.3 | $ 0.3 | ||
Tax benefit from released restricted shares | 0.1 | $ 0.1 | ||
Compensation cost not yet recognized | $ 0.6 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 6 months | |||
Subsequent event | ||||
Restricted Stock Activity | ||||
Granted, shares | 1,889 | |||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Granted, weighted-average grant date fair value | $ 68.18 |
COMMON EQUITY - PERFORMANCE UNI
COMMON EQUITY - PERFORMANCE UNITS (Details) - Performance units - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||
Mar. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance units granted | 8,500 | 10,025 | 9,235 | |
Performance units outstanding | 26,454 | |||
Liability recorded on balance sheet | $ 1.7 | |||
Compensation cost not yet recognized | $ 3.4 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 4 months | |||
Subsequent event | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Performance units granted | 8,178 | |||
Intrinsic value of settled performance units | $ 0.8 | |||
Tax benefit from distribution of performance units | $ 0.2 |
COMMON EQUITY - DIVIDEND RESTRI
COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Dividend Payment Restrictions [Line Items] | |
Restricted retained earnings | $ 531 |
Public Service Commission of Wisconsin | Minimum | |
Dividend Payment Restrictions [Line Items] | |
Common equity ratio required to be maintained (as a percent) | 51.00% |
PREFERRED STOCK (Details)
PREFERRED STOCK (Details) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | ||
Authorized shares | 1,000,000 | 1,000,000 |
Par value (in dollars per share) | $ 100 | $ 100 |
Shares outstanding | 0 | 0 |
SHORT-TERM DEBT AND LINES OF _3
SHORT-TERM DEBT AND LINES OF CREDIT OUTSTANDING (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Short-term borrowings | ||
Maximum Debt to Capitalization Ratio | 65.00% | |
Commercial paper | ||
Short-term borrowings | ||
Short-term borrowings outstanding | $ 284.4 | $ 293.1 |
Average interest rate on amounts outstanding (as a percent) | 2.85% | 1.72% |
Average amount of short-term borrowings outstanding during the year | $ 285.5 | |
Weighted average interest rate | 2.25% |
SHORT-TERM DEBT AND LINES OF _4
SHORT-TERM DEBT AND LINES OF CREDIT - CREDIT FACILITIES (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2018USD ($)extension | Dec. 31, 2017USD ($) | |
Short-term borrowings | ||
Available capacity under existing agreements | $ 114.3 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
Credit facility maturing October 2022 [Member] | ||
Short-term borrowings | ||
Total short-term credit capacity | $ 400 | |
Commercial paper | ||
Short-term borrowings | ||
Short-term borrowings outstanding | 284.4 | $ 293.1 |
Letters of credit | ||
Short-term borrowings | ||
Letters of credit issued inside credit facility | $ 1.3 |
LONG-TERM DEBT (Details)
LONG-TERM DEBT (Details) - USD ($) $ in Millions | 1 Months Ended | ||
Dec. 31, 2018 | Nov. 30, 2018 | Dec. 31, 2017 | |
Long-term Debt, Fiscal Year Maturity | |||
2,019 | $ 0 | ||
2,020 | 0 | ||
2,021 | 400 | ||
2,022 | 0 | ||
2,023 | 0 | ||
Thereafter | 925 | ||
Total | $ 1,325 | $ 1,175 | |
WPS 3.35% Senior Notes due November 21, 2021 | |||
Debt Instrument [Line Items] | |||
Proceeds from Issuance of Debt | $ 400 | ||
Interest rate, (as a percent) | 3.35% | 3.35% | |
Senior Notes (unsecured),1.65% due 2018 | |||
Debt Instrument [Line Items] | |||
Extinguishment of debt | $ 250 | ||
Interest rate, (as a percent) | 1.65% |
INCOME TAXES - SUMMARY OF INCOM
INCOME TAXES - SUMMARY OF INCOME TAX EXPENSE (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Provision for income taxes | |||
Current tax expense (benefit) | $ 56.7 | $ 22 | $ (52.5) |
Deferred income taxes, net | 20.9 | 78 | 143.3 |
Investment tax credit, net | (0.3) | (0.3) | (0.3) |
Total income tax expense | $ 77.3 | $ 99.7 | $ 90.5 |
INCOME TAXES - STATUTORY RATE R
INCOME TAXES - STATUTORY RATE RECONCILIATION (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement | ||||
Expected tax at statutory federal tax rates | $ 52.5 | $ 89.1 | $ 86.2 | |
State income taxes net of federal tax benefit | 15.4 | 12.7 | 11.6 | |
Federal excess amortization, amount | 11.6 | 0 | 0 | |
AFUDC-Equity | (1) | (1.4) | (6.8) | |
Other, net | (1.2) | (0.7) | (0.5) | |
Total income tax expense | $ 77.3 | $ 99.7 | $ 90.5 | |
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement (as a percent) | ||||
Expected tax at statutory federal tax rates | 21.00% | 21.00% | 35.00% | 35.00% |
State income taxes net of federal tax benefit | 6.20% | 5.00% | 4.70% | |
Federal excess amortization, effective tax rate | 4.60% | 0.00% | 0.00% | |
AFUDC-Equity | (0.40%) | (0.50%) | (2.70%) | |
Other, net | (0.50%) | (0.30%) | (0.20%) | |
Effective income tax rate | 30.90% | 39.20% | 36.80% |
INCOME TAXES - COMPONENTS OF DE
INCOME TAXES - COMPONENTS OF DEFERRED TAX ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Income Tax Disclosure [Abstract] | |||||
Expected tax at statutory federal tax rates | 21.00% | 21.00% | 35.00% | 35.00% | |
Estimated tax benefit related to the remeasurement of deferred taxes from tax legislation | $ 444.7 | ||||
Deferred tax assets | |||||
Tax gross up - regulatory items | 99.3 | $ 105.5 | $ 99.3 | ||
Other | 7.9 | 23.9 | 7.9 | ||
Total deferred tax assets | 107.2 | 129.4 | 107.2 | ||
Deferred income tax liabilities | |||||
Property-related | 563.5 | 588.1 | 563.5 | ||
Employee benefits and compensation | 37.7 | 40.9 | 37.7 | ||
Other | 18.7 | 21.2 | 18.7 | ||
Total deferred tax liabilities | 619.9 | 650.2 | 619.9 | ||
Deferred tax liability, net | $ 512.7 | $ 520.8 | $ 512.7 |
INCOME TAXES - COMPONENTS OF NE
INCOME TAXES - COMPONENTS OF NET DEFERRED TAX ASSETS (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Domestic tax authority | ||
Income taxes | ||
Federal tax credit carryforward | $ 1.3 | $ 6.3 |
Deferred tax assets, tax credit carryforwards federal | 1.3 | 6.3 |
Charitable contribution | 1.4 | |
Deferred tax assets, charitable contribution carryforwards | 0.3 | |
State and local jurisdiction | ||
Income taxes | ||
Charitable contribution | 1.4 | |
Deferred tax assets, charitable contribution carryforwards | 0.1 | |
Net operating loss carryforwards | 1.1 | 6.7 |
Deferred tax assets, state operating loss carryforwards | $ 0.4 | $ 0.4 |
INCOME TAXES - UNRECOGNIZED TAX
INCOME TAXES - UNRECOGNIZED TAX BENEFITS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |||
Unrecognized tax benefits | $ 0 | $ 0 | |
Unrecognized Tax Benefits, Interest on Income Taxes Expense | 0 | 0 | $ 0 |
Unrecognized Tax Benefits, Income Tax Penalties Expense | 0 | 0 | $ 0 |
Accrued interest related to unrecognized tax benefits | 0 | 0 | |
Accrued penalties related to unrecognized tax benefits | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Derivative Asset | $ 4.2 | $ 3.5 |
Liabilities | ||
Derivative Liability | 1.1 | 2.8 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative Asset | 4.2 | 3.5 |
Liabilities | ||
Derivative Liability | 2.8 | |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative Asset | 0.8 | 1.1 |
Liabilities | ||
Derivative Liability | 2.3 | |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative Asset | 0.4 | 0.4 |
Liabilities | ||
Derivative Liability | 0.5 | |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative Asset | 3 | 2 |
Liabilities | ||
Derivative Liability | 0 | |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative Asset | 0.8 | 0.8 |
Liabilities | ||
Derivative Liability | 1.1 | 2.3 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative Asset | 0.8 | 0.8 |
Liabilities | ||
Derivative Liability | 1.1 | 2.3 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Liabilities | ||
Derivative Liability | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Liabilities | ||
Derivative Liability | 0 | 0 |
Fair value measurements on a recurring basis | Petroleum product contracts | ||
Assets | ||
Derivative Asset | 0.3 | |
Fair value measurements on a recurring basis | Petroleum product contracts | Level 1 | ||
Assets | ||
Derivative Asset | 0.3 | |
Fair value measurements on a recurring basis | Petroleum product contracts | Level 2 | ||
Assets | ||
Derivative Asset | 0 | |
Fair value measurements on a recurring basis | Petroleum product contracts | Level 3 | ||
Assets | ||
Derivative Asset | 0 | |
Fair value measurements on a recurring basis | FTRs | ||
Assets | ||
Derivative Asset | 3 | 2 |
Fair value measurements on a recurring basis | FTRs | Level 1 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | Level 2 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | Level 3 | ||
Assets | ||
Derivative Asset | 3 | 2 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative Asset | 0.4 | 0.4 |
Liabilities | ||
Derivative Liability | 0.5 | |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Liabilities | ||
Derivative Liability | 0 | |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative Asset | 0.4 | 0.4 |
Liabilities | ||
Derivative Liability | 0.5 | |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative Asset | $ 0 | 0 |
Liabilities | ||
Derivative Liability | $ 0 |
FAIR VALUE MEASUREMENTS - LEVEL
FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Level 3 Rollforward | |||
Balance at the beginning of period | $ 2 | $ 2 | $ 2 |
Realized and unrealized losses | 0 | 0 | (0.2) |
Purchases | 9 | 6.9 | 7.1 |
Sales | 0 | 0 | (0.2) |
Settlements | (8) | (6.9) | (6.7) |
Balance at the end of the period | 3 | 2 | 2 |
Unrealized gains and losses on level 3 derivatives included in earnings | $ 0 | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Total long-term debt, including current portion | $ 1,314.7 | $ 916.2 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Total long-term debt, including current portion | 1,314.7 | 1,166.2 |
Fair Value | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Total long-term debt, including current portion | $ 1,372.9 | $ 1,302.4 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Derivative Asset | ||
Other current derivative assets | $ 4 | $ 3.1 |
Other long-term derivative assets | 0.2 | 0.4 |
Derivative Asset | 4.2 | 3.5 |
Derivative Liability | ||
Other current derivative liabilities | 1 | 2.4 |
Other long-term derivative liabilities | 0.1 | 0.4 |
Derivative Liability | 1.1 | 2.8 |
Natural gas contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.8 | 0.8 |
Other long-term derivative assets | 0 | 0 |
Derivative Liability | ||
Other current derivative liabilities | 1 | 1.9 |
Other long-term derivative liabilities | 0.1 | 0.4 |
Petroleum product contracts | ||
Derivative Asset | ||
Other current derivative assets | 0 | 0.3 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0 |
FTRs | ||
Derivative Asset | ||
Other current derivative assets | 3 | 2 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.2 | 0 |
Other long-term derivative assets | 0.2 | 0.4 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0.5 |
Other long-term derivative liabilities | $ 0 | $ 0 |
DERIVATIVE INSTRUMENTS - GAINS
DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)MWhMMBTUgal | Dec. 31, 2017USD ($)MWhMMBTUgal | Dec. 31, 2016USD ($)MWhMMBTUgal | |
Realized Gain (Loss) | |||
Gains (Losses) | $ 18 | $ 4.1 | $ 4 |
Natural gas contracts | |||
Realized Gain (Loss) | |||
Gains (Losses) | $ 5.1 | $ (2.4) | $ (1.4) |
Notional Sales Volumes | |||
Notional sales volumes (Dth or MWh) | MMBTU | 38.4 | 18.6 | 28.6 |
Petroleum product contracts | |||
Realized Gain (Loss) | |||
Gains (Losses) | $ 0.4 | $ 0.1 | $ (0.6) |
Notional Sales Volumes | |||
Notional sales volumes (gallons) | gal | 1.8 | 1.3 | 4.4 |
FTRs | |||
Realized Gain (Loss) | |||
Gains (Losses) | $ 12.5 | $ 6.4 | $ 6 |
Notional Sales Volumes | |||
Notional sales volumes (Dth or MWh) | MWh | 9.3 | 9.1 | 8.4 |
DERIVATIVE INSTRUMENTS - BALANC
DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Cash collateral | ||
Cash collateral in margin accounts | $ 0.5 | $ 4.9 |
Offsetting Derivative Assets | ||
Gross amount recognized on the balance sheet | 4.2 | 3.5 |
Gross amount not offset on the balance sheet | (0.8) | (1.1) |
Net amount | 3.4 | 2.4 |
Offsetting Derivative Liabilities | ||
Gross amount recognized on balance sheet | 1.1 | 2.8 |
Gross amount not offset on balance sheet | (1.1) | (2.3) |
Net amount | 0 | 0.5 |
Collateral posted | $ 0.3 | $ 1.2 |
EMPLOYEE BENEFITS - CHANGE IN B
EMPLOYEE BENEFITS - CHANGE IN BENEFIT OBLIGATION AND PLAN ASSETS (Details) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jan. 01, 2017plan | |
Pension Costs | ||||
Change in benefit obligation | ||||
Obligation at January 1 | $ 704.7 | $ 655.2 | ||
Service cost | 10.4 | 9 | $ 9.9 | |
Interest cost | 26 | 26.7 | 27 | |
Plan amendments | 0 | 0 | ||
Net transfer to/from affiliates | 0 | 0 | ||
Actuarial (gain) loss | (42.7) | 45.1 | ||
Participant contributions | 0 | 0 | ||
Benefit payments | (34.3) | (31.3) | ||
Transfer | 0 | 0 | ||
Obligation at December 31 | 664.1 | 704.7 | 655.2 | |
Change in fair value of plan assets | ||||
Beginning balance at January 1 | 712.4 | 736.6 | ||
Actual return on plan assets | (39.4) | 99.2 | ||
Employer contributions | 0.6 | 65.7 | ||
Participant contributions | 0 | 0 | ||
Benefit payments | (34.3) | (31.3) | ||
Net transfer to/from affiliates | 0 | (157.8) | ||
Ending balance at December 31 | 639.3 | 712.4 | 736.6 | |
Funded status at December 31 | (24.8) | 7.7 | ||
Pension Costs | Integrys Energy Group Retirement Plan Split | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Number of separate pension plans created from split | plan | 6 | |||
OPEB Costs | ||||
Change in benefit obligation | ||||
Obligation at January 1 | 220.2 | 223.1 | ||
Service cost | 6.1 | 6.2 | 7.3 | |
Interest cost | 8.2 | 9.1 | 10.6 | |
Plan amendments | (1.5) | (21.7) | ||
Net transfer to/from affiliates | (0.1) | 0 | ||
Actuarial (gain) loss | (70.7) | 12.2 | ||
Participant contributions | 1.2 | 1 | ||
Benefit payments | (9.9) | (9.7) | ||
Transfer | (2.1) | 0 | ||
Obligation at December 31 | 151.4 | 220.2 | 223.1 | |
Change in fair value of plan assets | ||||
Beginning balance at January 1 | 250.5 | 231.1 | ||
Actual return on plan assets | (10.3) | 27.1 | ||
Employer contributions | 0.1 | 1 | ||
Participant contributions | 1.2 | 1 | ||
Benefit payments | (9.9) | (9.7) | ||
Net transfer to/from affiliates | 0.1 | 0 | ||
Ending balance at December 31 | 231.7 | 250.5 | $ 231.1 | |
Funded status at December 31 | $ 80.3 | $ 30.3 |
EMPLOYEE BENEFITS - AMOUNTS REC
EMPLOYEE BENEFITS - AMOUNTS RECOGNIZED ON THE BALANCE SHEETS (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | $ 92.8 | $ 62 |
Pension and OPEB obligations | 37.3 | 24 |
Pension Costs | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | 0 | 15.6 |
Pension and OPEB obligations | 24.8 | 7.9 |
Total net (liabilities) assets | (24.8) | 7.7 |
OPEB Costs | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB assets | 92.8 | 46.4 |
Pension and OPEB obligations | 12.5 | 16.1 |
Total net (liabilities) assets | $ 80.3 | $ 30.3 |
EMPLOYEE BENEFITS - ACCUMULATED
EMPLOYEE BENEFITS - ACCUMULATED BENEFIT OBLIGATIONS (Details) - Pension Plan - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | $ 594.1 | $ 652 |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | ||
Projected benefit obligation | 7.3 | 7.9 |
Accumulated benefit obligation | 7.3 | 7.9 |
Fair value of plan assets | $ 0 | $ 0 |
EMPLOYEE BENEFITS - AMOUNTS NOT
EMPLOYEE BENEFITS - AMOUNTS NOT YET RECOGNIZED IN NET PERIODIC BENEFIT COST (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 |
Pension Costs | ||
Net regulatory assets | ||
Net actuarial loss (gain) | $ 220.4 | $ 196.5 |
Prior service credits | 0 | 0 |
Total | 220.4 | 196.5 |
Estimated amounts that will be amortized into net periodic benefit cost next year | ||
Net actuarial loss | 17.8 | |
Prior service credits | 0 | |
Total 2019 – estimated amortization | 17.8 | |
OPEB Costs | ||
Net regulatory assets | ||
Net actuarial loss (gain) | (17.9) | 27.2 |
Prior service credits | (82.8) | (92.6) |
Total | (100.7) | $ (65.4) |
Estimated amounts that will be amortized into net periodic benefit cost next year | ||
Net actuarial loss | 1.6 | |
Prior service credits | (11.4) | |
Total 2019 – estimated amortization | $ (9.8) |
EMPLOYEE BENEFITS - NET PERIODI
EMPLOYEE BENEFITS - NET PERIODIC BENEFIT COST (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Costs | |||
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | |||
Service cost | $ 10.4 | $ 9 | $ 9.9 |
Interest cost | 26 | 26.7 | 27 |
Expected return on plan assets | (48.3) | (46.4) | (52.6) |
Loss on plan settlement | 0 | 0 | 3.4 |
Amortization of prior service credit | 0 | 0 | 0 |
Amortization of net actuarial loss | 21.1 | 17.3 | 18 |
Net periodic benefit cost (credit) | 9.2 | 6.6 | 5.7 |
OPEB Costs | |||
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | |||
Service cost | 6.1 | 6.2 | 7.3 |
Interest cost | 8.2 | 9.1 | 10.6 |
Expected return on plan assets | (17.8) | (16.7) | (15.9) |
Loss on plan settlement | 0 | 0 | 0 |
Amortization of prior service credit | (11.3) | (9.8) | (7.4) |
Amortization of net actuarial loss | 2.5 | 2.5 | 2.5 |
Net periodic benefit cost (credit) | $ (12.3) | $ (8.7) | $ (2.9) |
EMPLOYEE BENEFITS - ADOPTION OF
EMPLOYEE BENEFITS - ADOPTION OF ASU 2017-07 (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Other operation and maintenance | $ 448 | $ 447.6 | $ 503.7 |
Other income, net | 37.6 | 23.7 | 41.3 |
Non-service credit components of net periodic benefit costs | $ 16.7 | 11.8 | 10.5 |
2017 Form 10-K Income Statement | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Other operation and maintenance | 435.8 | 493.2 | |
Other income, net | 11.9 | 30.8 | |
Impact of ASU 2017-07 | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Non-service credit components of net periodic benefit costs | $ 11.8 | $ 10.5 |
EMPLOYEE BENEFITS - ASSUMPTIONS
EMPLOYEE BENEFITS - ASSUMPTIONS (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 4.30% | 3.70% | ||
Rate of compensation increase | 4.00% | 4.00% | ||
Pension Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 3.70% | 4.19% | 4.25% | |
Expected return on plan assets | 7.25% | 7.25% | 7.25% | |
Rate of compensation increase | 4.00% | 4.00% | 4.00% | |
Pension Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 7.25% | |||
OPEB Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 4.29% | 3.67% | ||
Effects of a one-percentage-point change in assumed health care cost trend rates | ||||
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation | $ 15.2 | |||
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation | $ (12.1) | |||
OPEB Plan | Benefit obligation assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.25% | 6.50% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2,024 | 2,024 | ||
OPEB Plan | Benefit obligation assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 5.90% | 6.00% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2,028 | 2,028 | ||
OPEB Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 3.67% | 4.11% | 4.46% | |
Expected return on plan assets | 7.25% | 7.25% | 7.25% | |
Effects of a one-percentage-point change in assumed health care cost trend rates | ||||
Effect of one-percentage-point increase on total of service and interest cost components of net periodic postretirement health care benefit cost | $ 2.5 | |||
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost | $ (1.9) | |||
OPEB Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 7.25% | |||
OPEB Plan | Net periodic benefit cost assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.50% | 7.00% | 7.50% | |
Ultimate trend rate | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2,024 | 2,021 | 2,021 | |
OPEB Plan | Net periodic benefit cost assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.00% | 7.00% | 7.50% | |
Ultimate trend rate | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2,028 | 2,021 | 2,021 |
EMPLOYEE BENEFITS - TARGET ASSE
EMPLOYEE BENEFITS - TARGET ASSET ALLOCATIONS (Details) | Dec. 31, 2018 |
Pension Plan | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45.00% |
Pension Plan | Fixed Income Securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45.00% |
Pension Plan | Private equity and real estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10.00% |
OPEB Plan | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 45.00% |
OPEB Plan | Fixed Income Securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55.00% |
EMPLOYEE BENEFITS - PLAN ASSETS
EMPLOYEE BENEFITS - PLAN ASSETS (Details) - USD ($) $ in Millions | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 639.3 | $ 712.4 | $ 736.6 |
Pension Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 318.1 | 464.6 | |
Pension Plan | Level 1, 2, and 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 22.2 | ||
Pension Plan | Level 1, 2, and 3 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 79 | 97.9 | |
Pension Plan | Level 1, 2, and 3 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 80.4 | 98.6 | |
Pension Plan | Level 1, 2, and 3 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 135.4 | 147 | |
Pension Plan | Level 1, 2, and 3 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 23.3 | 23.5 | |
Pension Plan | Level 1, 2, and 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 75.4 | ||
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 177.7 | 216.2 | |
Pension Plan | Level 1 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | ||
Pension Plan | Level 1 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 79 | 97.9 | |
Pension Plan | Level 1 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 80.1 | 98.2 | |
Pension Plan | Level 1 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 16.3 | 17.8 | |
Pension Plan | Level 1 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 2.3 | 2.3 | |
Pension Plan | Level 1 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | ||
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 140.4 | 235.5 | |
Pension Plan | Level 2 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 22.2 | ||
Pension Plan | Level 2 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.3 | 0 | |
Pension Plan | Level 2 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 119.1 | 129.2 | |
Pension Plan | Level 2 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 21 | 21.2 | |
Pension Plan | Level 2 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 62.9 | ||
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 12.9 | |
Pension Plan | Level 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | ||
Pension Plan | Level 3 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0.4 | 0 |
Pension Plan | Level 3 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | 0.5 |
Pension Plan | Level 3 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 12.5 | 0 |
Pension Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 321.2 | 247.8 | |
OPEB Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 231.7 | 250.5 | 231.1 |
OPEB Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 139.2 | 155.8 | |
OPEB Plan | Level 1, 2, and 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 9.5 | ||
OPEB Plan | Level 1, 2, and 3 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 24 | 26.5 | |
OPEB Plan | Level 1, 2, and 3 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 27.2 | 32 | |
OPEB Plan | Level 1, 2, and 3 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 83.9 | 82.7 | |
OPEB Plan | Level 1, 2, and 3 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 4.1 | 4.3 | |
OPEB Plan | Level 1, 2, and 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.8 | ||
OPEB Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 100.4 | 117 | |
OPEB Plan | Level 1 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 9.2 | ||
OPEB Plan | Level 1 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 24 | 26.5 | |
OPEB Plan | Level 1 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 27 | 31.8 | |
OPEB Plan | Level 1 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 46.9 | 47 | |
OPEB Plan | Level 1 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 2.5 | 2.5 | |
OPEB Plan | Level 1 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | ||
OPEB Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 38.8 | 38.5 | |
OPEB Plan | Level 2 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.3 | ||
OPEB Plan | Level 2 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.2 | 0 | |
OPEB Plan | Level 2 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 37 | 35.7 | |
OPEB Plan | Level 2 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 1.6 | 1.8 | |
OPEB Plan | Level 2 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.7 | ||
OPEB Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0.3 | |
OPEB Plan | Level 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | ||
OPEB Plan | Level 3 | United States Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International Equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0.2 | 0 |
OPEB Plan | Level 3 | United States Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International Bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0.1 | $ 0 |
OPEB Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 92.5 | $ 94.7 |
EMPLOYEE BENEFITS - CHANGES IN
EMPLOYEE BENEFITS - CHANGES IN THE FAIR VALUE OF PLAN ASSETS CATEGORIZED AS LEVEL 3 (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Pension Plan | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | $ 712.4 | $ 736.6 |
Realized and unrealized losses | (39.4) | 99.2 |
Ending balance at December 31 | 639.3 | 712.4 |
Pension Plan | Level 3 | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 12.9 | |
Ending balance at December 31 | 0 | 12.9 |
Pension Plan | Level 3 | Private equity and real estate | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 12.5 | 0 |
Realized and unrealized losses | 0.7 | 0 |
Purchases | 2.4 | 12.5 |
Transferred into (out of) Level 3 | (15.6) | |
Ending balance at December 31 | 0 | 12.5 |
Pension Plan | Level 3 | International Equity | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0.4 | 0 |
Realized and unrealized losses | (0.1) | (0.1) |
Purchases | 0 | 0.5 |
Transferred into (out of) Level 3 | (0.3) | |
Ending balance at December 31 | 0 | 0.4 |
Pension Plan | Level 3 | United States Bonds | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 0.5 |
Realized and unrealized losses | (0.5) | |
Purchases | 0 | |
Ending balance at December 31 | 0 | 0 |
OPEB Plan | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 250.5 | 231.1 |
Realized and unrealized losses | (10.3) | 27.1 |
Ending balance at December 31 | 231.7 | 250.5 |
OPEB Plan | Level 3 | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0.3 | |
Ending balance at December 31 | 0 | 0.3 |
OPEB Plan | Level 3 | Private equity and real estate | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0.1 | 0 |
Realized and unrealized losses | 0 | 0 |
Purchases | 0 | 0.1 |
Transferred into (out of) Level 3 | (0.1) | |
Ending balance at December 31 | 0 | 0.1 |
OPEB Plan | Level 3 | International Equity | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0.2 | 0 |
Realized and unrealized losses | 0 | 0 |
Purchases | 0 | 0.2 |
Transferred into (out of) Level 3 | (0.2) | |
Ending balance at December 31 | 0 | 0.2 |
OPEB Plan | Level 3 | United States Bonds | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | |
Ending balance at December 31 | $ 0 | $ 0 |
EMPLOYEE BENEFITS - CASH FLOWS
EMPLOYEE BENEFITS - CASH FLOWS (Details) $ in Millions | Dec. 31, 2018USD ($) |
Pension Costs | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | $ 0.7 |
2,019 | 34.7 |
2,020 | 35.5 |
2,021 | 36.5 |
2,022 | 37 |
2,023 | 36.3 |
2024 through 2028 | 185.7 |
OPEB Costs | |
Defined Benefit Plan Disclosure [Line Items] | |
2,019 | 7.8 |
2,020 | 8.9 |
2,021 | 9.2 |
2,022 | 8.7 |
2,023 | 8.9 |
2024 through 2028 | $ 46.9 |
EMPLOYEE BENEFITS - DEFINED CON
EMPLOYEE BENEFITS - DEFINED CONTRIBUTION BENEFIT PLANS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Contribution Benefit Plans | |||
Total costs incurred for defined contribution benefit plans | $ 9.9 | $ 9.6 | $ 9 |
SEGMENTS INFORMATION (Details)
SEGMENTS INFORMATION (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2018USD ($)segment | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Segment reporting information | |||||||||||
Number of reportable segments | segment | 2 | ||||||||||
External revenues | $ 375.6 | $ 379.2 | $ 350.1 | $ 393.6 | $ 373.5 | $ 380.7 | $ 341.6 | $ 389.6 | $ 1,498.5 | $ 1,485.4 | $ 1,448.2 |
Other operation and maintenance | 448 | 447.6 | 503.7 | ||||||||
Depreciation and amortization | 141.9 | 139.3 | 124.1 | ||||||||
Operating income (loss) | 38.4 | $ 86.4 | $ 72.4 | $ 69.2 | 45.8 | $ 108.2 | $ 58.1 | $ 73 | 266.4 | 285.1 | 253 |
Other income, net | 37.6 | 23.7 | 41.3 | ||||||||
Interest expense | 53.9 | 54.2 | 48.1 | ||||||||
Capital expenditures | 521.4 | 335.8 | 311.1 | ||||||||
Total assets | 5,217.7 | 4,748.7 | 5,217.7 | 4,748.7 | 4,808.2 | ||||||
Utility | |||||||||||
Segment reporting information | |||||||||||
External revenues | 1,498.5 | 1,485.4 | 1,448.2 | ||||||||
Other operation and maintenance | 447.5 | 446.1 | 503 | ||||||||
Depreciation and amortization | 141.9 | 139.3 | 124 | ||||||||
Operating income (loss) | 267.1 | 286.7 | 253.9 | ||||||||
Other income, net | 35.2 | 21 | 33.8 | ||||||||
Interest expense | 53.9 | 54.2 | 48 | ||||||||
Capital expenditures | 521.4 | 335.8 | 311.1 | ||||||||
Total assets | 5,151.5 | 4,678.1 | 5,151.5 | 4,678.1 | 4,686.4 | ||||||
Other | |||||||||||
Segment reporting information | |||||||||||
External revenues | 0 | 0 | 0 | ||||||||
Other operation and maintenance | 0.5 | 1.5 | 1 | ||||||||
Depreciation and amortization | 0 | 0 | 0.1 | ||||||||
Operating income (loss) | (0.7) | (1.6) | (0.9) | ||||||||
Other income, net | 2.4 | 2.7 | 7.5 | ||||||||
Interest expense | 0 | 0 | 0.1 | ||||||||
Capital expenditures | 0 | 0 | 0 | ||||||||
Total assets | 66.2 | 70.6 | 66.2 | 70.6 | 121.8 | ||||||
Reconciling Eliminations | |||||||||||
Segment reporting information | |||||||||||
External revenues | 0 | 0 | 0 | ||||||||
Other operation and maintenance | 0 | 0 | (0.3) | ||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||
Operating income (loss) | 0 | 0 | 0 | ||||||||
Other income, net | 0 | 0 | 0 | ||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Capital expenditures | 0 | 0 | 0 | ||||||||
Total assets | $ 0 | $ 0 | $ 0 | $ 0 | 0 | ||||||
WPS Investments, LLC | |||||||||||
Segment reporting information | |||||||||||
Equity method investment, ownership interest (as a percent) | 10.37% | 10.37% | |||||||||
Intersegment revenues | |||||||||||
Segment reporting information | |||||||||||
External revenues | 0 | ||||||||||
Intersegment revenues | Utility | |||||||||||
Segment reporting information | |||||||||||
External revenues | 0 | ||||||||||
Intersegment revenues | Other | |||||||||||
Segment reporting information | |||||||||||
External revenues | 0.3 | ||||||||||
Intersegment revenues | Reconciling Eliminations | |||||||||||
Segment reporting information | |||||||||||
External revenues | $ (0.3) |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Dec. 31, 2018USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 1,186.1 |
2,019 | 241.8 |
2,020 | 161.6 |
2,021 | 141.4 |
2,022 | 132.4 |
2,023 | 117.4 |
Later Years | 391.5 |
Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 410.8 |
2,019 | 75.1 |
2,020 | 48.2 |
2,021 | 46.8 |
2,022 | 41.8 |
2,023 | 39.7 |
Later Years | 159.2 |
Coal supply and transportation | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 325.4 |
2,019 | 115 |
2,020 | 63.1 |
2,021 | 48.2 |
2,022 | 47.6 |
2,023 | 50.8 |
Later Years | 0.7 |
Natural gas utility supply and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 449.9 |
2,019 | 51.7 |
2,020 | 50.3 |
2,021 | 46.4 |
2,022 | 43 |
2,023 | 26.9 |
Later Years | $ 231.6 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jun. 30, 2013USD ($) | Mar. 31, 2013USD ($) | Dec. 31, 2018USD ($)degreecelsiusTMW | Dec. 31, 2017USD ($)T | Jun. 01, 2015USD ($) | |
Climate Change | Electric | |||||
Air Quality | |||||
Company goal for percentage of carbon dioxide emissions reduction by 2030 | 40.00% | ||||
Company goal for percentage of carbon dioxide emissions reduction by 2050 | 80.00% | ||||
Capacity of coal generation retired in 2018 | MW | 300 | ||||
Carbon dioxide emissions | T | 6.4 | 5.7 | |||
Climate Change | Natural gas | |||||
Air Quality | |||||
Carbon dioxide emissions | T | 3.8 | 3.5 | |||
Steam Electric Effluent Guidelines | Electric | |||||
Water Quality | |||||
Expected cost to achieve required emissions reduction | $ 20 | ||||
Manufactured Gas Plant Remediation | Natural gas | |||||
Manufactured Gas Plant Remediation | |||||
Regulatory assets recorded for remediation of manufactured gas plant sites | 108.3 | $ 116 | |||
Reserves recorded for remediation of manufactured gas plant sites | $ 90.3 | $ 99.6 | |||
Renewables, Efficiency, and Conservation | Wisconsin | Electric | |||||
Renewables, Efficiency, and Conservation | |||||
Renewable portfolio requirement for Wisconsin, as a percent | 10.00% | ||||
Renewable energy percent | 9.74% | ||||
Percent of annual operating revenues used to fund renewable program | 1.20% | ||||
Consent Decree - Weston and Pulliam Power Plants | Electric | |||||
Consent Decrees | |||||
Beneficial environmental projects amount | $ 6 | ||||
Civil penalty | $ 1.2 | ||||
Regulatory asset for undepreciated book value of retired plants | $ 11.5 | ||||
Joint Ownership Power Plants Consent Decree - Columbia and Edgewater | Electric | |||||
Consent Decrees | |||||
Beneficial environmental projects amount | $ 1.3 | ||||
Civil penalty | $ 0.4 | ||||
Maximum | Climate Change | Electric | |||||
Environmental matters | |||||
Global temperature increases limit | degreecelsius | 2 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental cash flow information | |||
Cash (paid) for interest, net of amount capitalized | $ (52.9) | $ (55.5) | $ (54.6) |
Cash (paid) received for income taxes, net | (36.6) | (18.1) | 39.9 |
Accounts payable related to construction costs | 8.1 | 46.4 | 67.2 |
Receivable related to corporate-owned life insurance proceeds | 6.4 | 0 | 0 |
WPSI | |||
Supplemental cash flow information | |||
Transfer of ownership in WPSI to another subsidiary of Integrys | 67.2 | 0 | |
UMERC | |||
Supplemental cash flow information | |||
Transfer of net assets to UMERC | $ 0.4 | $ 20.6 | $ 0 |
REGULATORY ENVIRONMENT (Details
REGULATORY ENVIRONMENT (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |||||||
May 31, 2018USD ($)MWsolar_projectsMegawatt | Dec. 31, 2017USD ($) | Oct. 31, 2017wind_turbinesutilityMW | Sep. 30, 2017USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Regulatory environment | |||||||||
AFUDC | $ 1.9 | $ 1.6 | $ 8.1 | ||||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | ||||||||
Forward Wind Energy Center | |||||||||
Regulatory environment | |||||||||
Number of utilities, along with WPS, that entered into an agreement to purchase Forward Wind Energy Center | utility | 2 | ||||||||
Number of wind turbines at Forward Wind Energy Center | wind_turbines | 86 | ||||||||
Capacity of Forward Wind Energy Center | MW | 138 | ||||||||
Public Service Commission of Wisconsin (PSCW) | Two Creeks Solar Farm [Member] | |||||||||
Regulatory environment | |||||||||
WPS individual ownership interest | Megawatt | 100 | ||||||||
Public Service Commission of Wisconsin (PSCW) | Badger Hollow Solar Farm [Member] | |||||||||
Regulatory environment | |||||||||
WPS individual ownership interest | MW | 100 | ||||||||
Public Service Commission of Wisconsin (PSCW) | Badger Hollow and Two Creeks Solar Farms [Member] | |||||||||
Regulatory environment | |||||||||
Number of Solar Projects in WI that WPS Filed with the PSCW to Acquire an Interest In | solar_projects | 2 | ||||||||
WPS Total Ownership Capacity in Badger Hollow and Two Creeks | MW | 200 | ||||||||
WPS Total Share of Cost of Badger Hollow and Two Creeks | $ 260 | ||||||||
Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 Rates | |||||||||
Regulatory environment | |||||||||
Approved return on equity (as a percent) | 10.00% | ||||||||
Authorized revenue requirement for the ReACT project | $ 275 | ||||||||
AFUDC | $ 51 | ||||||||
Estimated cost of the ReACT project, excluding AFUDC | $ 342 | ||||||||
Percentage of first 50 basis points of additional utility earnings shared with customers | 50.00% | ||||||||
Return on equity in excess of authorized amount (as a percent) | 0.50% | ||||||||
Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits | 100.00% | ||||||||
Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Percentage of current tax benefit from Tax Cuts and Jobs Act of 2017 to be used to reduce regulatory assets | 40.00% | ||||||||
Percent of current tax benefit from Tax Cuts and Jobs Act of 2017 to be returned to customers via bill credits | 60.00% | ||||||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | |||||||||
Regulatory environment | |||||||||
Approved return on equity (as a percent) | 10.00% | ||||||||
Approved common equity component average (as a percent) | 51.00% | ||||||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved rate increase (decrease) | $ (6.2) | ||||||||
Approved rate increase (decrease), percentage | (2.10%) | ||||||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Authorized revenue requirement for the ReACT project | $ 275 | $ 275 | |||||||
Approved rate increase (decrease) | $ (7.9) | ||||||||
Approved rate increase (decrease), percentage | (0.80%) | ||||||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | ||||||||
Utility operations | Tax Cuts and Jobs Act of 2017 | |||||||||
Regulatory environment | |||||||||
Change in deferred income taxes from tax legislation | $ 444.7 |
OTHER INCOME, NET (Details)
OTHER INCOME, NET (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Other Income and Expenses [Abstract] | |||
AFUDC - Equity | $ 4.6 | $ 4.1 | $ 19.5 |
Non-service credit components of net periodic benefit costs | 16.7 | 11.8 | 10.5 |
Earnings from equity method investments | 0.8 | 1.1 | 9.5 |
Other, net | 15.5 | 6.7 | 1.8 |
Other income, net | $ 37.6 | $ 23.7 | $ 41.3 |
QUARTERLY FINANCIAL INFORMATI_3
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 375.6 | $ 379.2 | $ 350.1 | $ 393.6 | $ 373.5 | $ 380.7 | $ 341.6 | $ 389.6 | $ 1,498.5 | $ 1,485.4 | $ 1,448.2 |
Operating income | 38.4 | 86.4 | 72.4 | 69.2 | 45.8 | 108.2 | 58.1 | 73 | 266.4 | 285.1 | $ 253 |
Net income attributed to common shareholder | $ 23.3 | $ 57 | $ 42.7 | $ 49.8 | $ 24 | $ 60.9 | $ 30.7 | $ 39.3 | $ 172.8 | $ 154.9 |
NEW ACCOUNTING PRONOUNCEMENTS (
NEW ACCOUNTING PRONOUNCEMENTS (Details) $ in Millions | Jan. 01, 2019USD ($)capitalleaseslandeasements |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Impairment Losses Recorded Upon Adoption of Topic 842 | $ | $ 0 |
Number of Land Easements Treated As Leases | landeasements | 0 |
Number of capital leases | capitalleases | 0 |
SCHEDULE II - VALUATION AND Q_2
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Valuation and qualifying accounts | |||
Balance at beginning of period | $ 4 | $ 3 | $ 2.5 |
Expense | 6 | 5 | 7.7 |
Net write-offs | (5.8) | (4) | (7.2) |
Balance at end of period | $ 4.2 | $ 4 | $ 3 |