DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION | 3 Months Ended |
Mar. 31, 2019shares | |
Document Entity Information [Abstract] | |
Entity registrant name | WISCONSIN ELECTRIC POWER CO |
Entity central index key | 0000107815 |
Current fiscal year end date | --12-31 |
Entity filer category | Non-accelerated Filer |
Document type | 10-Q |
Document period end date | Mar. 31, 2019 |
Document fiscal year focus | 2019 |
Document fiscal period focus | Q1 |
Amendment flag | false |
Entity common stock, shares outstanding | 33,289,327 |
Emerging growth company | false |
Small business | false |
CONDENSED CONSOLIDATED INCOME S
CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Income Statement [Abstract] | ||
Operating revenues | $ 960.8 | $ 941.5 |
Operating expenses | ||
Cost of sales | 357.2 | 357 |
Other operation and maintenance | 258.9 | 335.6 |
Depreciation and amortization | 96 | 85.3 |
Property and revenue taxes | 25.8 | 27.2 |
Total operating expenses | 737.9 | 805.1 |
Operating income | 222.9 | 136.4 |
Other income (expense), net | 5.5 | (4.2) |
Interest expense | 119.9 | 29.7 |
Other expense | (114.4) | (33.9) |
Income before income taxes | 108.5 | 102.5 |
Income tax benefit | (6.5) | (3.6) |
Net income | 115 | 106.1 |
Preferred stock dividend requirements | 0.3 | 0.3 |
Net income attributed to common shareholder | $ 114.7 | $ 105.8 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Current assets | ||
Cash and cash equivalents | $ 4.6 | $ 20.2 |
Accounts receivable and unbilled revenues, net of reserves of $42.4 and $40.9, respectively | 481.6 | 472.3 |
Accounts receivable from related parties | 83.3 | 112.4 |
Materials, supplies, and inventories | 191.8 | 241.4 |
Prepayments | 107.6 | 163.7 |
Other | 4.8 | 6.3 |
Current assets | 873.7 | 1,016.3 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation and amortization of $4,385.2 and $4,505.5, respectively | 9,360.4 | 9,528.9 |
Regulatory assets | 3,100.6 | 2,902.2 |
Other | 108.1 | 90.9 |
Long-term assets | 12,569.1 | 12,522 |
Total assets | 13,442.8 | 13,538.3 |
Current liabilities | ||
Short-term debt | 75.5 | 134.9 |
Current portion of long-term debt | 250 | 250 |
Current portion of finance and capital lease obligations | 52 | 49.9 |
Accounts payable | 181 | 248.9 |
Accounts payable to related parties | 240.5 | 226 |
Accrued payroll and benefits | 37 | 50.4 |
Other | 161.7 | 116.8 |
Current liabilities | 997.7 | 1,076.9 |
Long-term liabilities | ||
Long-term debt | 2,460.1 | 2,459.6 |
Finance and capital lease obligations | 2,813.8 | 2,807.2 |
Deferred income taxes | 1,292.4 | 1,298.3 |
Regulatory liabilities | 2,013.8 | 2,002.3 |
Pension and OPEB obligations | 115.6 | 118.5 |
Other | 293.3 | 284.3 |
Long-term liabilities | 8,989 | 8,970.2 |
Commitments and contingencies (Note 16) | ||
Common shareholder's equity | ||
Common stock – $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding | 332.9 | 332.9 |
Additional paid in capital | 831.5 | 831.3 |
Retained earnings | 2,261.3 | 2,296.6 |
Common shareholder's equity | 3,425.7 | 3,460.8 |
Preferred stock | 30.4 | 30.4 |
Total liabilities and equity | $ 13,442.8 | $ 13,538.3 |
CONDENSED CONSOLIDATED BALANC_2
CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves | $ 42.4 | $ 40.9 |
Property, plant, and equipment, accumulated depreciation | $ 4,385.2 | $ 4,505.5 |
Common stock, par value (in dollars per share) | $ 10 | $ 10 |
Common stock, shares authorized | 65,000,000 | 65,000,000 |
Common stock, shares outstanding | 33,289,327 | 33,289,327 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Operating Activities | ||
Net income | $ 115 | $ 106.1 |
Reconciliation to cash provided by operating activities | ||
Depreciation and amortization | 96 | 85.3 |
Deferred income taxes and investment tax credits, net | (52.6) | (15.4) |
Contributions and payments related to pension and OPEB plans | (1.9) | (2.1) |
Change in – | ||
Accounts receivable and unbilled revenues | 16.5 | (12.5) |
Materials, supplies, and inventories | 49.6 | 36 |
Prepaid taxes | 55.4 | 24.2 |
Other current assets | 0.9 | 6 |
Accounts payable | (54) | 12.3 |
Accrued taxes | 13 | 10.9 |
Amounts refundable to customers | 15.1 | 15.7 |
Other current liabilities | 2.8 | (1.8) |
Other, net | 45.4 | 105.2 |
Net cash provided by operating activities | 301.2 | 369.9 |
Investing Activities | ||
Capital expenditures | (102.4) | (141.9) |
Payments for assets transferred from affiliates | 0 | (48.9) |
Other, net | 1.1 | 2.2 |
Net cash used in investing activities | (101.3) | (188.6) |
Financing Activities | ||
Change in short-term debt | (59.4) | (150.9) |
Payments for finance lease obligations | (5.7) | 0 |
Equity contribution from parent | 0 | 28 |
Payment of dividends to parent | (150) | (60) |
Payment of preferred stock dividends | (0.3) | (0.3) |
Other, net | (0.1) | 0 |
Net cash used in financing activities | (215.5) | (183.2) |
Net change in cash and cash equivalents | (15.6) | (1.9) |
Cash and cash equivalents at beginning of period | 20.2 | 12.3 |
Cash and cash equivalents at end of period | $ 4.6 | $ 10.4 |
CONDENSED CONSOLIDATED STATEM_2
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions | Total | Total Common Shareholders' Equity | Common Stock | Additional Paid In Capital | Retained Earnings | Preferred Stock |
Balance at Dec. 31, 2017 | $ 3,414.3 | $ 3,383.9 | $ 332.9 | $ 802.7 | $ 2,248.3 | $ 30.4 |
Condensed consolidated statements of equity | ||||||
Net income | 106.1 | 106.1 | 0 | 0 | 106.1 | 0 |
Dividends | ||||||
Common stock | (60) | (60) | 0 | 0 | (60) | 0 |
Preferred stock | (0.3) | (0.3) | 0 | 0 | (0.3) | 0 |
Equity contribution from parent | 28 | 28 | 0 | 28 | 0 | 0 |
Stock-based compensation and other | 0.2 | 0.2 | 0 | 0.2 | 0 | 0 |
Balance at Mar. 31, 2018 | 3,488.3 | 3,457.9 | 332.9 | 830.9 | 2,294.1 | 30.4 |
Balance at Dec. 31, 2018 | 3,491.2 | 3,460.8 | 332.9 | 831.3 | 2,296.6 | 30.4 |
Condensed consolidated statements of equity | ||||||
Net income | 115 | 115 | 0 | 0 | 115 | 0 |
Dividends | ||||||
Common stock | (150) | (150) | 0 | 0 | (150) | 0 |
Preferred stock | (0.3) | (0.3) | 0 | 0 | (0.3) | 0 |
Equity contribution from parent | 0 | |||||
Stock-based compensation and other | 0.2 | 0.2 | 0 | 0.2 | 0 | 0 |
Balance at Mar. 31, 2019 | $ 3,456.1 | $ 3,425.7 | $ 332.9 | $ 831.5 | $ 2,261.3 | $ 30.4 |
GENERAL INFORMATION
GENERAL INFORMATION | 3 Months Ended |
Mar. 31, 2019 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL INFORMATION | GENERAL INFORMATION As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary, Bostco, which was dissolved in October 2018. We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2018 . Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31 , 2019 are not necessarily indicative of expected results for 2019 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. |
OPERATING REVENUES
OPERATING REVENUES | 3 Months Ended |
Mar. 31, 2019 | |
Revenue from Contract with Customer [Abstract] | |
OPERATING REVENUES | OPERATING REVENUES For more information about our significant accounting policies related to operating revenues, see Note 1(d), Operating Revenues, in our 2018 Annual Report on Form 10-K. Disaggregation of Operating Revenues The following table presents 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 revenues and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions. Wisconsin Electric Power Company Consolidated Three Months Ended March 31 (in millions) 2019 2018 Electric utility $ 778.8 $ 779.6 Natural gas utility 177.9 160.8 Total revenues from contracts with customers 956.7 940.4 Other operating revenues 4.1 1.1 Total operating revenues $ 960.8 $ 941.5 Revenues from Contracts with Customers Electric Utility Operating Revenues The following table disaggregates electric utility operating revenues into customer class: Electric Utility Operating Revenues Three Months Ended March 31 (in millions) 2019 2018 Residential $ 302.6 $ 281.4 Small commercial and industrial 245.1 237.7 Large commercial and industrial 156.0 148.9 Other 5.6 5.4 Total retail revenues 709.3 673.4 Wholesale 28.9 28.5 Resale 31.3 63.7 Steam 10.1 9.7 Other utility revenues * (0.8 ) 4.3 Total electric utility operating revenues $ 778.8 $ 779.6 * Negative amounts are driven by the reduction in revenues related to tax repairs. In accordance with a settlement agreement with the PSCW in May 2018, we flowed through the tax benefits of our repair-related deferred tax liabilities to maintain certain regulatory assets at their December 31, 2017 levels. Natural Gas Utility Operating Revenues The following table disaggregates natural gas utility operating revenues into customer class: Natural Gas Utility Operating Revenues Three Months Ended March 31 (in millions) 2019 2018 Residential $ 125.6 $ 114.7 Commercial and industrial 60.9 55.6 Total retail revenues 186.5 170.3 Transport 4.2 4.4 Other utility revenues * (12.8 ) (13.9 ) Total natural gas utility operating revenues $ 177.9 $ 160.8 * Includes amounts refunded to customers for purchased gas adjustment costs. Other Operating Revenues Other operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2019 2018 Late payment charges $ 2.7 $ 2.8 Rental revenues 0.7 0.8 Alternative revenues * 0.7 (2.5 ) Total other operating revenues $ 4.1 $ 1.1 * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups. |
REGULATORY ASSETS AND LIABILITI
REGULATORY ASSETS AND LIABILITIES | 3 Months Ended |
Mar. 31, 2019 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets and liabilities were reflected on our balance sheets at March 31, 2019 and December 31, 2018 . For more information on our regulatory assets and liabilities, see Note 5, Regulatory Assets and Liabilities, in our 2018 Annual Report on Form 10-K. (in millions) March 31, 2019 December 31, 2018 Regulatory assets Plant retirements * $ 953.2 $ 754.1 Finance and capital leases 885.1 869.3 Pension and OPEB costs 483.3 490.6 Income tax related items 332.9 317.9 SSR 317.8 316.7 Electric transmission costs 41.4 57.8 We Power generation 36.1 43.0 Asset retirement obligations 30.5 28.7 Other, net 20.3 24.2 Total regulatory assets $ 3,100.6 $ 2,902.3 Balance sheet presentation Other current assets $ — $ 0.1 Regulatory assets 3,100.6 2,902.2 Total regulatory assets $ 3,100.6 $ 2,902.3 * On March 31, 2019, we retired the PIPP generating units. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP units. (in millions) March 31, 2019 December 31, 2018 Regulatory liabilities Income tax related items $ 1,021.1 $ 1,024.8 Removal costs 757.3 748.1 Mines deferral 129.1 120.8 Pension and OPEB costs 74.8 74.7 Uncollectible expense 15.6 16.4 Energy efficiency programs 14.1 13.5 Other, net 28.8 15.9 Total regulatory liabilities $ 2,040.8 $ 2,014.2 Balance sheet presentation Other current liabilities $ 27.0 $ 11.9 Regulatory liabilities 2,013.8 2,002.3 Total regulatory liabilities $ 2,040.8 $ 2,014.2 |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT | 3 Months Ended |
Mar. 31, 2019 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT, AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT We have evaluated future plans for our older and less efficient fossil fuel generating units and have retired the PIPP and the Pleasant Prairie power plant. In addition, a severance liability was recorded in other current liabilities on our balance sheets within the utility segment related to these plant retirements. (in millions) Severance liability at December 31, 2018 $ 12.9 Severance payments (0.2 ) Total severance liability at March 31, 2019 $ 12.7 Presque Isle Power Plant Pursuant to MISO's April 2018 approval of the retirement of the PIPP, these units were retired on March 31, 2019. The carrying value of the PIPP units was $172.1 million at March 31, 2019 . This amount included the net book value of $183.1 million , which was classified as a regulatory asset on our balance sheet. In addition, an $11.0 million cost of removal reserve related to the PIPP units remained classified as a regulatory liability at March 31, 2019 . We will amortize this regulatory asset on a straight-line basis using the composite depreciation rates approved by the PSCW before the units were retired. |
COMMON EQUITY
COMMON EQUITY | 3 Months Ended |
Mar. 31, 2019 | |
Equity [Abstract] | |
COMMON EQUITY | COMMON EQUITY Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 8, Common Equity, in our 2018 Annual Report on Form 10-K for additional information on these and other restrictions. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 3 Months Ended |
Mar. 31, 2019 | |
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: (in millions, except percentages) March 31, 2019 December 31, 2018 Commercial paper Amount outstanding $ 75.5 $ 134.9 Weighted-average interest rate on amounts outstanding 2.64 % 2.96 % Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2019 , was $64.4 million with a weighted-average interest rate during the period of 2.80% . The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including available capacity under this facility: (in millions) Maturity March 31, 2019 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 75.5 Available capacity under existing agreement $ 423.3 |
LEASES
LEASES | 3 Months Ended |
Mar. 31, 2019 | |
Leases [Abstract] | |
LEASES | LEASES In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revised the previous guidance (Topic 840) regarding accounting for leases. Revisions include requiring a lessee to recognize a lease asset and a lease liability on its balance sheet for each lease, including operating leases with an initial term greater than 12 months. In addition, required quantitative and qualitative disclosures related to lease agreements were expanded. As required, we adopted Topic 842 effective January 1, 2019. We utilized the following practical expedients, which were available under ASU 2016-02, in our adoption of the new lease guidance. • We did not reassess whether any expired or existing contracts were leases or contained leases. • We did not reassess the lease classification for any expired or existing leases (that is, all leases that were classified as operating leases in accordance with Topic 840 continue to be classified as operating leases, and all leases that were classified as capital leases in accordance with Topic 840 are classified as finance leases). • We did not reassess the accounting for initial direct costs for any existing leases. We did not elect the practical expedient allowing entities to account for the nonlease components in lease contracts as part of the single lease component to which they were related. Instead, in accordance with Accounting Standards Codification 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract. We did not elect the practical expedient to use hindsight in determining the lease term and in assessing impairment of our right of use assets. No impairment losses were included in the measurement of our right of use assets upon our adoption of Topic 842. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which is an amendment to ASU 2016-02. Land easements (also commonly referred to as rights of way) represent the right to use, access or cross another entity's land for a specified purpose. This new guidance permits an entity to elect a transitional practical expedient, to be applied consistently, to not evaluate under Topic 842 land easements that were already in existence or had expired at the time of the entity's adoption of Topic 842. Once Topic 842 is adopted, an entity is required to apply Topic 842 prospectively to all new (or modified) land easements to determine whether the arrangement should be accounted for as a lease. We elected this practical expedient, resulting in none of our land easements being treated as leases upon our adoption of Topic 842. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which amends ASU 2016-02 and allows entities the option to initially apply Topic 842 at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if required. We used the optional transition method to apply the new guidance as of January 1, 2019, rather than as of the earliest period presented. We did not require a cumulative-effect adjustment upon adoption of Topic 842. Both the right of use assets and related lease liabilities related to our operating leases that were recorded upon adoption of Topic 842 were $13.0 million . Regarding our finance leases, while the adoption of Topic 842 changed the classification of expense related to these leases on a prospective basis, it had no impact on the total amount of lease expense recorded, and did not impact the finance lease assets and related liability amounts recorded on our balance sheets. Obligations Under Operating Leases We have recorded right of use assets and lease liabilities associated with the following operating leases. • Land we are leasing related to our Rothschild biomass plant through June 2051. • Rail cars we are leasing to transport coal to various generating facilities through February 2021. • Various office space leases. The operating leases generally require us to pay property taxes, insurance premiums, and operating and maintenance costs associated with the leased property. Many of our leases contain options to renew past the initial term, as set forth in the lease agreement. Obligations Under Finance Leases We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under finance lease accounting, we have recorded the leased plants and corresponding obligations as right of use assets and lease liabilities on our balance sheets. We treat these agreements as operating leases for rate-making purposes. Prior to our adoption of Topic 842 on January 1, 2019, we accounted for these finance leases under Topic 980-840, Regulated Operations – Leases, as follows: • We recorded our minimum lease payments under the power purchase contract as purchased power expense on our income statement. • We recorded our minimum lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements. • We recorded the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. In conjunction with our adoption of Topic 842, while the timing of expense recognition related to our finance leases did not change, the classification of the lease expense changed as follows: • Effective January 1, 2019, the minimum lease payments under the power purchase contract were no longer classified within purchased power expense, but were instead recorded as a component of depreciation and amortization and interest expense in accordance with Topic 980-842, Regulated Operations – Leases. • Similarly, the lease payments related to our leases with We Power were no longer classified as rent expense within other operation and maintenance in our income statements, but were also divided between amortization expense and interest expense in accordance with Topic 980-842. • In order to ensure the timing of lease expense did not change for these finance leases upon adoption of Topic 842, and still resembled the expense recognition pattern of an operating lease, the amortization of the right of use assets was modified from what would typically be recorded for a finance lease under Topic 842. • We continue to record the difference between the minimum lease payments and the sum of imputed interest and unadjusted amortization costs calculated under the finance lease accounting rules as a deferred regulatory asset on our balance sheets. Power Purchase Commitment In 1997, we entered into a 25 -year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022, we may, at our option and with proper notice, renew for another ten years, purchase the generating facility at fair market value, or allow the contract to expire. We originally recorded this leased facility and corresponding obligation on our balance sheets at the estimated fair value of the plant's electric generating facilities. As previously discussed, we treat the long-term power purchase contract as an operating lease for rate-making purposes. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under finance lease accounting rules as a deferred regulatory asset on our balance sheets. Minimum lease payments are a function of the 236 MWs of firm capacity we receive from the plant and the fixed monthly capacity rate published in the lease. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to $78.5 million in 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the finance lease was $22.1 million at March 31, 2019, and will decrease to zero over the remaining life of the contract. Port Washington Generating Station We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units, which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the original 25 -year term of the leases. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.3 million in the year 2021 for PWGS 1 and to approximately $126.0 million in the year 2023 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases for the units was $631.5 million as of March 31, 2019, and will decrease to zero over the remaining lives of the contracts. The only variability associated with the PWGS lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840. When the PWGS 1 and PWGS 2 contracts expire in 2030 and 2033, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire. Elm Road Generating Station We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8 generating units, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30 -year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The lease payments are expected to be recovered through our rates, as supported by Wisconsin's 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $524.1 million in the year 2028 for ER 1 and to approximately $430.6 million in the year 2029 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the finance leases was $2,212.2 million as of March 31, 2019, and will decrease to zero over the remaining lives of the contracts. The only variability associated with the ER lease payments relates to the potential for future changes in We Power's tax or interest rates, as the positive or negative impact of these changes are generally passed along to us, and subsequently to our customers. Because variability in the lease payments is dependent upon a rate (interest rate or tax rate), the lease payments are considered unavoidable under Topic 842, and are included in the measurement of the right of use asset and lease liability, consistent with how they were treated under Topic 840. When the ER 1 and ER 2 contracts expire in 2040 and 2041, respectively, we may, at our option and with proper notice, choose to renew one or both contracts for up to three consecutive renewal terms (each renewal term would approximate 80% of the then remaining economic useful life of the respective generation unit), purchase one or both generating facilities at fair market value, or allow the contracts to expire. Amounts Recognized in the Financial Statements The components of lease expense and supplemental cash flow information related to our leases for the quarters ended March 31 are as follows: (in millions) 2019 2018 Long-term power purchase commitment $ 2.0 $ 1.9 We Power leases 91.8 91.8 Total finance/capital lease expense (1) $ 93.8 $ 93.7 Operating lease expense (2) 0.7 0.7 Total lease expense $ 94.5 $ 94.4 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance/capital leases (3) $ 89.8 $ 94.2 Operating cash flows from operating leases $ 0.7 $ 0.7 Financing cash flows from finance leases (3) $ 5.7 $ — Non-cash activity - right of use assets obtained in exchange for operating lease liabilities $ 13.0 Weighted-average remaining lease term – finance leases 19.3 years Weighted-average remaining lease term – operating leases 22.4 years Weighted-average discount rate – finance leases (4) 13.9 % Weighted average discount rate – operating leases (4) 4.6 % (1) For the quarter ended March 31, 2019, total finance lease expense included amortization of right of use assets in the amount of $5.7 million (included in depreciation and amortization expense) and interest on lease liabilities of $88.1 million (included in interest expense). For the quarter ended March 31, 2018, total finance lease cost related to the long-term power purchase agreement was included in cost of sales and total finance lease cost related to the PWGS and ERGS units was included in other operation and maintenance. (2) Operating lease expense was included as a component of operation and maintenance for the quarters ended March 31, 2019 and 2018. (3) Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to finance leases were recorded as a component of operating cash flows. (4) Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our financing leases, the rate implicit in each lease was readily determinable. The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets: (in millions) March 31, 2019 December 31, 2018 Long-term power purchase commitment Under finance/capital lease $ 140.3 $ 140.3 Accumulated amortization (122.3 ) (120.9 ) Total long-term power purchase commitment $ 18.0 $ 19.4 PWGS Under finance/capital lease $ 739.2 $ 736.9 Accumulated amortization (343.9 ) (335.9 ) Total PWGS $ 395.3 $ 401.0 ERGS Under finance/capital lease $ 2,184.5 $ 2,166.3 Accumulated amortization (617.2 ) (598.8 ) Total ERGS $ 1,567.3 $ 1,567.5 Total finance lease right of use assets/capital lease assets $ 1,980.6 $ 1,987.9 Right of use assets related to operating leases were $12.5 million at March 31, 2019, and were included in other long-term assets on our balance sheets. Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of March 31, 2019 were as follows: (in millions) Total Operating Leases Power Purchase Commitment PWGS ERGS Total Finance Leases Nine months ended December 31, 2019 $ 2.0 $ 6.2 $ 73.5 $ 219.8 $ 299.5 2020 2.7 8.8 98.0 293.1 399.9 2021 0.7 9.4 98.0 293.1 400.5 2022 0.6 4.2 98.0 292.9 395.1 2023 0.5 — 98.0 292.8 390.8 2024 0.5 — 97.9 292.7 390.6 Thereafter 13.5 — 677.8 4,538.5 5,216.3 Total minimum lease payments 20.5 28.6 1,241.2 6,222.9 7,492.7 Less: Interest (8.0 ) (6.5 ) (609.7 ) (4,010.7 ) (4,626.9 ) Present value of minimum lease payments 12.5 22.1 631.5 2,212.2 2,865.8 Less: Short-term lease liabilities (2.2 ) (5.2 ) (23.1 ) (23.7 ) (52.0 ) Long-term lease liabilities $ 10.3 $ 16.9 $ 608.4 $ 2,188.5 $ 2,813.8 Short-term and long-term lease liabilities related to operating leases were included in other current liabilities and other long-term liabilities on the balance sheets, respectively. Significant Judgments and Other Information We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind farms. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets. As of May 3, 2019, we have not entered into any material operating leases that have not yet commenced. |
MATERIALS, SUPPLIES, AND INVENT
MATERIALS, SUPPLIES, AND INVENTORIES | 3 Months Ended |
Mar. 31, 2019 | |
Inventory Disclosure [Abstract] | |
MATERIALS, SUPPLIES, AND INVENTORIES | MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) March 31, 2019 December 31, 2018 Materials and supplies $ 143.7 $ 146.1 Fossil fuel 41.2 58.7 Natural gas in storage 6.9 36.6 Total $ 191.8 $ 241.4 Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
INCOME TAXES
INCOME TAXES | 3 Months Ended |
Mar. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 22.7 21.0 % $ 21.5 21.0 % State income taxes net of federal tax benefit 7.1 6.6 % 6.7 6.5 % Tax repairs (29.6 ) (27.3 )% (25.5 ) (24.9 )% Federal excess deferred tax amortization (6.2 ) (5.7 )% (5.4 ) (5.2 )% Wind production tax credits (2.8 ) (2.6 )% (3.2 ) (3.1 )% Other 2.3 2.0 % 2.3 2.2 % Total income tax benefit $ (6.5 ) (6.0 )% $ (3.6 ) (3.5 )% The effective tax rates of (6.0)% and (3.5)% for the first quarter of 2019 and 2018, respectively, differ from the United States statutory federal income tax rate of 21% , primarily due to the flow through of tax repairs in connection with the Wisconsin rate settlement, the impact of the Tax Legislation, and wind production tax credits, partially offset by state income taxes. The Tax Legislation, signed into law in December 2017, required our regulated utilities to remeasure their deferred income taxes and we began to amortize the resulting excess deferred income taxes beginning in 2018 in accordance with normalization requirements (see federal excess deferred tax amortization line above). See Note 18, Regulatory Environment, for more information about the Wisconsin rate settlement. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 3 Months Ended |
Mar. 31, 2019 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | 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 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. 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: March 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.3 $ — $ — $ 1.3 FTRs — — 2.0 2.0 Coal contracts — 0.5 — 0.5 Total derivative assets $ 1.3 $ 0.5 $ 2.0 $ 3.8 Derivative liabilities Coal contracts $ — $ 0.1 $ — $ 0.1 December 31, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.7 $ — $ — $ 0.7 FTRs — — 4.4 4.4 Total derivative assets $ 0.7 $ — $ 4.4 $ 5.1 Derivative liabilities Natural gas contracts $ 1.2 $ — $ — $ 1.2 Coal contracts — 0.1 — 0.1 Total derivative liabilities $ 1.2 $ 0.1 $ — $ 1.3 The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy and Operating Reserves Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31 (in millions) 2019 2018 Balance at the beginning of the period $ 4.4 $ 2.4 Settlements (2.4 ) (1.6 ) Balance at the end of the period $ 2.0 $ 0.8 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that were not recorded at fair value: March 31, 2019 December 31, 2018 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.3 $ 30.4 $ 28.3 Long-term debt, including current portion 2,710.1 2,981.2 2,709.6 2,881.6 The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 3 Months Ended |
Mar. 31, 2019 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. The following table shows our derivative assets and derivative liabilities, none of which are designated as hedging instruments. March 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 1.1 $ — $ 0.7 $ 1.2 FTRs 2.0 — 4.4 — Coal contracts 0.5 0.1 — 0.1 Total other current * $ 3.6 $ 0.1 $ 5.1 $ 1.3 Other long-term * Natural gas contracts $ 0.2 $ — $ — $ — Total $ 3.8 $ 0.1 $ 5.1 $ 1.3 * On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts. Realized gains (losses) on derivative instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 18.1 Dth $ (1.4 ) 11.7 Dth $ (1.8 ) Petroleum products contracts — gallons — 1.4 gallons 0.4 FTRs 5.5 MWh 1.6 5.8 MWh 0.8 Total $ 0.2 $ (0.6 ) On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At both March 31, 2019 and December 31, 2018 , we had posted cash collateral of $1.1 million in our margin accounts. These amounts were recorded on our balance sheets in other current assets. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: March 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 3.8 $ 0.1 $ 5.1 $ 1.3 Gross amount not offset on the balance sheet — — (0.6 ) (1.3 ) * Net amount $ 3.8 $ 0.1 $ 4.5 $ — * Includes cash collateral posted of $0.7 million . |
GUARANTEES
GUARANTEES | 3 Months Ended |
Mar. 31, 2019 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEES As of March 31, 2019 , we had $26.2 million of standby letters of credit issued by financial institutions for the benefit of third parties that extended credit to us which automatically renew each year unless proper termination notice is given. These amounts are not reflected on our balance sheets. |
EMPLOYEE BENEFITS
EMPLOYEE BENEFITS | 3 Months Ended |
Mar. 31, 2019 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS The following tables show the components of net periodic pension and OPEB costs for our benefit plans: Pension Costs Three Months Ended March 31 (in millions) 2019 2018 Service cost $ 3.8 $ 3.3 Interest cost 11.5 10.6 Expected return on plan assets (18.2 ) (19.0 ) Amortization of prior service cost 0.1 0.2 Amortization of net actuarial loss 7.2 9.4 Net periodic benefit cost $ 4.4 $ 4.5 OPEB Costs Three Months Ended March 31 (in millions) 2019 2018 Service cost $ 1.2 $ 1.8 Interest cost 2.4 2.8 Expected return on plan assets (3.5 ) (3.9 ) Amortization of prior service credit (0.5 ) (0.6 ) Amortization of net actuarial gain (0.4 ) — Net periodic benefit (credit) cost $ (0.8 ) $ 0.1 During the three months ended March 31, 2019 , we made contributions and payments of $1.7 million related to our pension plans and $0.2 million related to our OPEB plans. We expect to make contributions and payments of $2.1 million related to our pension plans and $3.5 million related to our OPEB plans during the remainder of 2019 , dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation. |
SEGMENT INFORMATION
SEGMENT INFORMATION | 3 Months Ended |
Mar. 31, 2019 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At March 31, 2019 , we reported two segments, which are described below. Our utility segment includes both our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity to customers in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, and northern Wisconsin. Prior to April 1, 2019, we also provided electric service to an iron ore mine in the Upper Peninsula of Michigan. This customer was transferred to UMERC on April 1, 2019 as UMERC's new generation in the Upper Peninsula of Michigan is now operational. In addition, our electric utility operations include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin. Prior to October 2018, our other segment included Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco, and, in October 2018, Bostco was dissolved. No significant items were reported in the other segment during the three months ended March 31, 2019 and 2018 . |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 3 Months Ended |
Mar. 31, 2019 | |
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. Power Purchase Agreement We have a power purchase agreement that represents a variable interest. This agreement is for 236 MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a finance lease. The agreement includes no minimum energy requirements over the remaining term of approximately three years . We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the power purchase agreement. We have $28.6 million of required capacity payments over the remaining term of this agreement. We believe that the required capacity payments under this contract will continue to be recoverable in rates, and our maximum exposure to loss is limited to these capacity payments. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 3 Months Ended |
Mar. 31, 2019 | |
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, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of March 31, 2019 , were $10,016.7 million . 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 sulfur dioxide, nitrogen oxide, 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. 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 National Ambient Air Quality Standards. The EPA issued final nonattainment area designations on May 1, 2018. The following counties within our service area were designated as partial nonattainment: Kenosha, Manitowoc, Northern Milwaukee/Ozaukee, 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 United States Supreme Court to review both costs and benefits of complying with the MATS rule. After its review of costs, the EPA determined that it is not appropriate and necessary to regulate hazardous air pollutant emissions from 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 August 2018, the EPA issued a proposed replacement rule for the Clean Power Plan, the Affordable Clean Energy (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 previous rule, which identified BSER as partial carbon capture and storage. In April 2019, WEC Energy Group issued a climate report, which analyzes its GHG reduction goals with respect to international efforts to limit future global temperature increases to less than two degrees Celsius. WEC Energy Group will continue to update this analysis as climate-change policies and relevant technologies evolve over time with a focus on preserving fuel diversity, lowering costs for customers, and reducing long-term GHG emissions. WEC Energy Group's plan, which includes us, is to work with its industry peers, environmental groups, public policy makers, and customers, with goals of reducing CO 2 emissions by approximately 40% and 80% below 2005 levels by 2030 and 2050, respectively. As a result of WEC Energy Group's generation reshaping plan, we have retired approximately 1,500 MW of coal generation since the beginning of 2018, consisting of the PIPP, which we retired on March 31, 2019, and the Pleasant Prairie power plant, which was retired in April 2018. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2018, we reported CO 2 equivalent emissions of 20.0 million metric tonnes to the EPA. We are also required to report CO 2 equivalent emissions related to the natural gas that our natural gas operations distribute and sell. For 2018, we reported CO 2 equivalent emissions of 4.1 million metric tonnes to the EPA. 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, except for the ERGS units, which were permitted under the rules governing new facilities. 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 operating facilities satisfy the BTA requirements. We have received a BTA determination by the WDNR, with EPA concurrence, for our intake modification at the Valley Power Plant. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the BTA requirements, final determinations will not be made until discharge permits are renewed for these units. Until that time, we cannot determine what, if any, intake structure or operational modifications will be required to meet the new BTA requirements for these units. We also have provided information to the WDNR and the MDEQ about planned unit retirements. Following discussions with the MDEQ, in January 2019, we submitted a signed certification stating that the PIPP would be retired no later than June 1, 2019. The PIPP was retired on March 31, 2019. 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 two new requirements that affect us relate to discharge limits for bottom ash transport water (BATW) and wet flue gas desulfurization (FGD) wastewater. This rule is being litigated and various petitions challenging it were consolidated in the United States Court of Appeals for the Fifth Circuit (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 and wet FGD wastewater requirements. The latest ELG rule compliance date remains December 31, 2023 for any new wastewater treatment requirements contained in power plant discharge permits. As a result of past capital investments completed to address ELG compliance, we believe our fleet overall is well positioned to meet the regulations. 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, we believe the only facilities that will require bottom ash system modifications are Oak Creek Units 7 and 8. One wastewater treatment system modification may be required for the wet FGD discharges from the six units that make up the OCPP and ERGS. Based on preliminary engineering, the estimated rule compliance cost is approximately $50 million . The Fifth Circuit issued a ruling in April 2019, striking down several portions of the ELG rule. The Fifth Circuit held that the legacy wastewater and combustion residual leachate provisions in the rule failed to meet the requirements of the Clean Water Act and the Administrative Procedure Act. Land Quality Manufactured Gas Plant Remediation We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves related to manufactured gas plant sites: (in millions) March 31, 2019 December 31, 2018 Regulatory assets $ 24.0 $ 24.2 Reserves for future remediation * 13.2 13.2 * Recorded within other long-term liabilities on our balance sheets. Enforcement and Litigation Matters We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 3 Months Ended |
Mar. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Three Months Ended March 31 (in millions) 2019 2018 Cash (paid) for interest, net of amount capitalized * $ (94.9 ) $ (4.7 ) Significant non-cash transactions: Accounts payable related to construction costs 14.7 7.3 * On January 1, 2019, we adopted ASU 2016-02, Leases (Topic 842). This ASU required us to prospectively change the classification of our finance lease payments on the income statement. As a result, during the first quarter of 2019, we classified the interest component of our finance lease payments as cash paid for interest since it was included in interest expense on the income statement. However, prior to our adoption of Topic 842, the interest component was not considered cash paid for interest since it was not included in interest expense on the income statement. See Note 7, Leases, for more information on Topic 842 and our finance leases. |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 3 Months Ended |
Mar. 31, 2019 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT 2020 and 2021 Rates In March 2019, we filed an application with the PSCW to increase our retail electric, natural gas, and steam rates, effective January 1, 2020. Our proposal is targeting an effective electric rate increase of approximately $83 million ( 2.9% ) in 2020 and an additional increase of $83 million ( 2.9% ) in 2021. For our natural gas and steam customers, our proposal is targeting effective rate increases of approximately $15 million ( 3.9% ) and $1 million ( 4.5% ), respectively, in 2020, with no additional increases in 2021. Our proposal reflects a ROE of 10.35% and a common equity component average of 52.0% on a financial basis. We also proposed to continue having an earnings sharing mechanism through 2021. Our proposed increase in electric rates was driven by higher transmission charges, recovery of SSR revenues that were assumed in our 2015 rate order but were not received, and an increase in costs associated with a purchased power agreement previously approved by the PSCW. Our proposed electric rates reflect our request to partially offset these increases with approximately $111 million of previously deferred tax benefits from the Tax Legislation. Our proposal also includes our request for approval to continue collecting the carrying value of the Pleasant Prairie power plant and the PIPP using the current approved composite depreciation rates, in addition to a return on the remaining carrying value of the plants. The proposed increase at our natural gas utility was driven by continued investment in our natural gas distribution system. A final order is expected from the PSCW by the end of 2019, with rates effective January 1, 2020. 2018 and 2019 Rates During April 2017, we, along with WG and Wisconsin Public Service Corporation, 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, natural gas, and steam customers. Based on the PSCW order, our authorized ROE remains at 10.2% , 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 and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. We will flow through the tax benefit of our repair-related deferred tax liabilities in 2018 and 2019, to maintain certain regulatory asset balances at their December 31, 2017 levels. While we would typically follow the normalization accounting method and utilize the tax benefits of the deferred tax liabilities in rate making as an offset to rate base, benefiting customers over time, the federal tax code does allow for passing these tax repair-related benefits to ratepayers much sooner using the flow through accounting method. The flow through treatment of the repair-related deferred tax liabilities offsets the negative income statement impact of holding the regulatory assets level, resulting in no change to net income. Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we 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. |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 3 Months Ended |
Mar. 31, 2019 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS 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 financial statements. |
GENERAL INFORMATION (Policies)
GENERAL INFORMATION (Policies) | 3 Months Ended |
Mar. 31, 2019 | |
Accounting policies | |
Consolidation | As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, and statements of equity, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to Wisconsin Electric Power Company and its subsidiary, Bostco, which was dissolved in October 2018. |
Basis of accounting | We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2018 . Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31 , 2019 are not necessarily indicative of expected results for 2019 due to seasonal variations and other factors. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. |
Leases | Instead, in accordance with Accounting Standards Codification 842-10-15-31, our policy is to account for each lease component separately from the nonlease components of the contract. We are currently party to several easement agreements that allow us access to land we do not own for the purpose of constructing and maintaining certain electric power and natural gas equipment. The majority of payments we make related to easements relate to our wind farms. We have not classified our easements as leases because we view the entire parcel of land specified in our easement agreements to be the identified asset, not just that portion of the parcel that contains our easement. As such, we have concluded that we do not control the use of an identified asset related to our easement agreements, nor do we obtain substantially all of the economic benefits associated with these shared-use assets. |
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 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 an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. |
New Accounting Pronouncements | 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 financial statements. |
OPERATING REVENUES (Tables)
OPERATING REVENUES (Tables) - Utility segment | 3 Months Ended |
Mar. 31, 2019 | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | The following table presents 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 revenues and cash flows are affected by economic factors. For our utility segment, revenues are further disaggregated by electric and natural gas operations and then by customer class. Each customer class within our electric and natural gas operations have different expectations of service, energy and demand requirements, and are impacted by regulatory activities within their jurisdictions. Wisconsin Electric Power Company Consolidated Three Months Ended March 31 (in millions) 2019 2018 Electric utility $ 778.8 $ 779.6 Natural gas utility 177.9 160.8 Total revenues from contracts with customers 956.7 940.4 Other operating revenues 4.1 1.1 Total operating revenues $ 960.8 $ 941.5 |
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 Three Months Ended March 31 (in millions) 2019 2018 Residential $ 302.6 $ 281.4 Small commercial and industrial 245.1 237.7 Large commercial and industrial 156.0 148.9 Other 5.6 5.4 Total retail revenues 709.3 673.4 Wholesale 28.9 28.5 Resale 31.3 63.7 Steam 10.1 9.7 Other utility revenues * (0.8 ) 4.3 Total electric utility operating revenues $ 778.8 $ 779.6 * Negative amounts are driven by the reduction in revenues related to tax repairs. In accordance with a settlement agreement with the PSCW in May 2018, we flowed through the tax benefits of our repair-related deferred tax liabilities to maintain certain regulatory assets at their December 31, 2017 levels. |
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 Three Months Ended March 31 (in millions) 2019 2018 Residential $ 125.6 $ 114.7 Commercial and industrial 60.9 55.6 Total retail revenues 186.5 170.3 Transport 4.2 4.4 Other utility revenues * (12.8 ) (13.9 ) Total natural gas utility operating revenues $ 177.9 $ 160.8 * Includes amounts refunded to customers for purchased gas adjustment costs. |
Other operating revenues | |
Disaggregation of Operating Revenues | |
Operating revenues disaggregated by revenue source | Other operating revenues consist primarily of the following: Three Months Ended March 31 (in millions) 2019 2018 Late payment charges $ 2.7 $ 2.8 Rental revenues 0.7 0.8 Alternative revenues * 0.7 (2.5 ) Total other operating revenues $ 4.1 $ 1.1 * Negative amounts can result from alternative revenues being reversed to revenues from contracts with customers as the customer is billed for these alternative revenues. Negative amounts can also result from revenues to be refunded to customers subject to wholesale true-ups |
REGULATORY ASSETS AND LIABILI_2
REGULATORY ASSETS AND LIABILITIES (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | (in millions) March 31, 2019 December 31, 2018 Regulatory assets Plant retirements * $ 953.2 $ 754.1 Finance and capital leases 885.1 869.3 Pension and OPEB costs 483.3 490.6 Income tax related items 332.9 317.9 SSR 317.8 316.7 Electric transmission costs 41.4 57.8 We Power generation 36.1 43.0 Asset retirement obligations 30.5 28.7 Other, net 20.3 24.2 Total regulatory assets $ 3,100.6 $ 2,902.3 Balance sheet presentation Other current assets $ — $ 0.1 Regulatory assets 3,100.6 2,902.2 Total regulatory assets $ 3,100.6 $ 2,902.3 * On March 31, 2019, we retired the PIPP generating units. See Note 4, Property, Plant, and Equipment, for more information on the retirement of the PIPP units |
Schedule of regulatory liabilities | (in millions) March 31, 2019 December 31, 2018 Regulatory liabilities Income tax related items $ 1,021.1 $ 1,024.8 Removal costs 757.3 748.1 Mines deferral 129.1 120.8 Pension and OPEB costs 74.8 74.7 Uncollectible expense 15.6 16.4 Energy efficiency programs 14.1 13.5 Other, net 28.8 15.9 Total regulatory liabilities $ 2,040.8 $ 2,014.2 Balance sheet presentation Other current liabilities $ 27.0 $ 11.9 Regulatory liabilities 2,013.8 2,002.3 Total regulatory liabilities $ 2,040.8 $ 2,014.2 |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Restructuring cost and reserve | |
Schedule of changes to our severance liability | In addition, a severance liability was recorded in other current liabilities on our balance sheets within the utility segment related to these plant retirements. (in millions) Severance liability at December 31, 2018 $ 12.9 Severance payments (0.2 ) Total severance liability at March 31, 2019 $ 12.7 |
SHORT-TERM DEBT AND LINES OF _2
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Short-term Debt [Abstract] | |
Schedule of short-term borrowings and weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) March 31, 2019 December 31, 2018 Commercial paper Amount outstanding $ 75.5 $ 134.9 Weighted-average interest rate on amounts outstanding 2.64 % 2.96 % |
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 available capacity under this facility: (in millions) Maturity March 31, 2019 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 75.5 Available capacity under existing agreement $ 423.3 |
LEASES (Tables)
LEASES (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Leases [Abstract] | |
Schedule of lease expense and supplemental cash flow information for leases | The components of lease expense and supplemental cash flow information related to our leases for the quarters ended March 31 are as follows: (in millions) 2019 2018 Long-term power purchase commitment $ 2.0 $ 1.9 We Power leases 91.8 91.8 Total finance/capital lease expense (1) $ 93.8 $ 93.7 Operating lease expense (2) 0.7 0.7 Total lease expense $ 94.5 $ 94.4 Other information Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance/capital leases (3) $ 89.8 $ 94.2 Operating cash flows from operating leases $ 0.7 $ 0.7 Financing cash flows from finance leases (3) $ 5.7 $ — Non-cash activity - right of use assets obtained in exchange for operating lease liabilities $ 13.0 Weighted-average remaining lease term – finance leases 19.3 years Weighted-average remaining lease term – operating leases 22.4 years Weighted-average discount rate – finance leases (4) 13.9 % Weighted average discount rate – operating leases (4) 4.6 % (1) For the quarter ended March 31, 2019, total finance lease expense included amortization of right of use assets in the amount of $5.7 million (included in depreciation and amortization expense) and interest on lease liabilities of $88.1 million (included in interest expense). For the quarter ended March 31, 2018, total finance lease cost related to the long-term power purchase agreement was included in cost of sales and total finance lease cost related to the PWGS and ERGS units was included in other operation and maintenance. (2) Operating lease expense was included as a component of operation and maintenance for the quarters ended March 31, 2019 and 2018. (3) Prior to our adoption of Topic 842 on January 1, 2019, all cash flows related to finance leases were recorded as a component of operating cash flows. (4) Because our operating leases do not provide an implicit rate of return, we used the fully collateralized incremental borrowing rates based upon information available for similarly rated companies in determining the present value of lease payments for our operating leases. For our financing leases, the rate implicit in each lease was readily determinable. |
Schedule of finance lease right of use assets | The following table summarizes our finance lease right of use assets, which were included in property, plant and equipment on our balance sheets: (in millions) March 31, 2019 December 31, 2018 Long-term power purchase commitment Under finance/capital lease $ 140.3 $ 140.3 Accumulated amortization (122.3 ) (120.9 ) Total long-term power purchase commitment $ 18.0 $ 19.4 PWGS Under finance/capital lease $ 739.2 $ 736.9 Accumulated amortization (343.9 ) (335.9 ) Total PWGS $ 395.3 $ 401.0 ERGS Under finance/capital lease $ 2,184.5 $ 2,166.3 Accumulated amortization (617.2 ) (598.8 ) Total ERGS $ 1,567.3 $ 1,567.5 Total finance lease right of use assets/capital lease assets $ 1,980.6 $ 1,987.9 |
Schedule of future minimum lease payments for operating and finance leases | Future minimum lease payments under our finance and operating leases and the present value of our net minimum lease payments as of March 31, 2019 were as follows: (in millions) Total Operating Leases Power Purchase Commitment PWGS ERGS Total Finance Leases Nine months ended December 31, 2019 $ 2.0 $ 6.2 $ 73.5 $ 219.8 $ 299.5 2020 2.7 8.8 98.0 293.1 399.9 2021 0.7 9.4 98.0 293.1 400.5 2022 0.6 4.2 98.0 292.9 395.1 2023 0.5 — 98.0 292.8 390.8 2024 0.5 — 97.9 292.7 390.6 Thereafter 13.5 — 677.8 4,538.5 5,216.3 Total minimum lease payments 20.5 28.6 1,241.2 6,222.9 7,492.7 Less: Interest (8.0 ) (6.5 ) (609.7 ) (4,010.7 ) (4,626.9 ) Present value of minimum lease payments 12.5 22.1 631.5 2,212.2 2,865.8 Less: Short-term lease liabilities (2.2 ) (5.2 ) (23.1 ) (23.7 ) (52.0 ) Long-term lease liabilities $ 10.3 $ 16.9 $ 608.4 $ 2,188.5 $ 2,813.8 |
MATERIALS, SUPPLIES, AND INVE_2
MATERIALS, SUPPLIES, AND INVENTORIES (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Inventory Disclosure [Abstract] | |
Schedule of inventory | Our inventory consisted of: (in millions) March 31, 2019 December 31, 2018 Materials and supplies $ 143.7 $ 146.1 Fossil fuel 41.2 58.7 Natural gas in storage 6.9 36.6 Total $ 191.8 $ 241.4 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation | The provision for income taxes differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes as a result of the following: Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Statutory federal income tax $ 22.7 21.0 % $ 21.5 21.0 % State income taxes net of federal tax benefit 7.1 6.6 % 6.7 6.5 % Tax repairs (29.6 ) (27.3 )% (25.5 ) (24.9 )% Federal excess deferred tax amortization (6.2 ) (5.7 )% (5.4 ) (5.2 )% Wind production tax credits (2.8 ) (2.6 )% (3.2 ) (3.1 )% Other 2.3 2.0 % 2.3 2.2 % Total income tax benefit $ (6.5 ) (6.0 )% $ (3.6 ) (3.5 )% |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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: March 31, 2019 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 1.3 $ — $ — $ 1.3 FTRs — — 2.0 2.0 Coal contracts — 0.5 — 0.5 Total derivative assets $ 1.3 $ 0.5 $ 2.0 $ 3.8 Derivative liabilities Coal contracts $ — $ 0.1 $ — $ 0.1 December 31, 2018 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.7 $ — $ — $ 0.7 FTRs — — 4.4 4.4 Total derivative assets $ 0.7 $ — $ 4.4 $ 5.1 Derivative liabilities Natural gas contracts $ 1.2 $ — $ — $ 1.2 Coal contracts — 0.1 — 0.1 Total derivative liabilities $ 1.2 $ 0.1 $ — $ 1.3 |
Reconciliation of changes in 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: Three Months Ended March 31 (in millions) 2019 2018 Balance at the beginning of the period $ 4.4 $ 2.4 Settlements (2.4 ) (1.6 ) Balance at the end of the period $ 2.0 $ 0.8 |
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 were not recorded at fair value: March 31, 2019 December 31, 2018 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.3 $ 30.4 $ 28.3 Long-term debt, including current portion 2,710.1 2,981.2 2,709.6 2,881.6 |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
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. March 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 1.1 $ — $ 0.7 $ 1.2 FTRs 2.0 — 4.4 — Coal contracts 0.5 0.1 — 0.1 Total other current * $ 3.6 $ 0.1 $ 5.1 $ 1.3 Other long-term * Natural gas contracts $ 0.2 $ — $ — $ — Total $ 3.8 $ 0.1 $ 5.1 $ 1.3 * On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts. |
Estimated notional volumes and realized gains(losses) | Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended March 31, 2019 Three Months Ended March 31, 2018 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 18.1 Dth $ (1.4 ) 11.7 Dth $ (1.8 ) Petroleum products contracts — gallons — 1.4 gallons 0.4 FTRs 5.5 MWh 1.6 5.8 MWh 0.8 Total $ 0.2 $ (0.6 ) |
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: March 31, 2019 December 31, 2018 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 3.8 $ 0.1 $ 5.1 $ 1.3 Gross amount not offset on the balance sheet — — (0.6 ) (1.3 ) * Net amount $ 3.8 $ 0.1 $ 4.5 $ — * Includes cash collateral posted of $0.7 million . |
EMPLOYEE BENEFITS (Tables)
EMPLOYEE BENEFITS (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Retirement Benefits [Abstract] | |
Schedule of net benefit costs | The following tables show the components of net periodic pension and OPEB costs for our benefit plans: Pension Costs Three Months Ended March 31 (in millions) 2019 2018 Service cost $ 3.8 $ 3.3 Interest cost 11.5 10.6 Expected return on plan assets (18.2 ) (19.0 ) Amortization of prior service cost 0.1 0.2 Amortization of net actuarial loss 7.2 9.4 Net periodic benefit cost $ 4.4 $ 4.5 OPEB Costs Three Months Ended March 31 (in millions) 2019 2018 Service cost $ 1.2 $ 1.8 Interest cost 2.4 2.8 Expected return on plan assets (3.5 ) (3.9 ) Amortization of prior service credit (0.5 ) (0.6 ) Amortization of net actuarial gain (0.4 ) — Net periodic benefit (credit) cost $ (0.8 ) $ 0.1 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Commitments and Contingencies Disclosure [Abstract] | |
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: (in millions) March 31, 2019 December 31, 2018 Regulatory assets $ 24.0 $ 24.2 Reserves for future remediation * 13.2 13.2 * Recorded within other long-term liabilities on our balance sheets. |
SUPPLEMENTAL CASH FLOW INFORM_2
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 3 Months Ended |
Mar. 31, 2019 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Three Months Ended March 31 (in millions) 2019 2018 Cash (paid) for interest, net of amount capitalized * $ (94.9 ) $ (4.7 ) Significant non-cash transactions: Accounts payable related to construction costs 14.7 7.3 * On January 1, 2019, we adopted ASU 2016-02, Leases (Topic 842). This ASU required us to prospectively change the classification of our finance lease payments on the income statement. As a result, during the first quarter of 2019, we classified the interest component of our finance lease payments as cash paid for interest since it was included in interest expense on the income statement. However, prior to our adoption of Topic 842, the interest component was not considered cash paid for interest since it was not included in interest expense on the income statement. See Note 7, Leases, for more information on Topic 842 and our finance leases. |
OPERATING REVENUES - DISAGGREGA
OPERATING REVENUES - DISAGGREGATION OF OPERATING REVENES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Disaggregation of Operating Revenues | ||
Operating revenues | $ 960.8 | $ 941.5 |
Utility segment | ||
Disaggregation of Operating Revenues | ||
Operating revenues | 960.8 | 941.5 |
Utility segment | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Operating revenues | 4.1 | 1.1 |
Utility segment | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 956.7 | 940.4 |
Utility segment | Electric | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 778.8 | 779.6 |
Utility segment | Natural gas | Transferred over time | Revenues from contracts with customers | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 177.9 | $ 160.8 |
OPERATING REVENUES ELECTRIC UTI
OPERATING REVENUES ELECTRIC UTILITY OPERATING REVENUES (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 956.7 | $ 940.4 |
Electric | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 778.8 | 779.6 |
Electric | Total retail | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 709.3 | 673.4 |
Electric | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 302.6 | 281.4 |
Electric | Small commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 245.1 | 237.7 |
Electric | Large commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 156 | 148.9 |
Electric | Other | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 5.6 | 5.4 |
Electric | Wholesale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 28.9 | 28.5 |
Electric | Resale | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 31.3 | 63.7 |
Electric | Steam | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 10.1 | 9.7 |
Electric | Other utility | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ (0.8) | $ 4.3 |
OPERATING REVENUES NATURAL GAS
OPERATING REVENUES NATURAL GAS UTILITY OPERATING REVENUES (Details) - Revenues from contracts with customers - Utility segment - Transferred over time - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ 956.7 | $ 940.4 |
Natural gas | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 177.9 | 160.8 |
Natural gas | Total retail | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 186.5 | 170.3 |
Natural gas | Residential | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 125.6 | 114.7 |
Natural gas | Commercial and industrial | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 60.9 | 55.6 |
Natural gas | Transport | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | 4.2 | 4.4 |
Natural gas | Other utility | ||
Disaggregation of Operating Revenues | ||
Revenues from contracts with customers | $ (12.8) | $ (13.9) |
OPERATING REVENUES - OTHER OPER
OPERATING REVENUES - OTHER OPERATING REVENUES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Disaggregation of Operating Revenues | ||
Operating revenues | $ 960.8 | $ 941.5 |
Utility segment | ||
Disaggregation of Operating Revenues | ||
Operating revenues | 960.8 | 941.5 |
Utility segment | Other operating revenues | ||
Disaggregation of Operating Revenues | ||
Operating revenues | 4.1 | 1.1 |
Utility segment | Other operating revenues | Late payment charges | ||
Disaggregation of Operating Revenues | ||
Operating revenues | 2.7 | 2.8 |
Utility segment | Other operating revenues | Rental revenues | ||
Disaggregation of Operating Revenues | ||
Operating revenues | 0.7 | 0.8 |
Utility segment | Other operating revenues | Alternative revenues | ||
Disaggregation of Operating Revenues | ||
Operating revenues | $ 0.7 | $ (2.5) |
REGULATORY ASSETS AND LIABILI_3
REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Regulatory assets | ||
Current assets | $ 0 | $ 0.1 |
Regulatory assets | 3,100.6 | 2,902.2 |
Total regulatory assets | 3,100.6 | 2,902.3 |
Plant retirements | ||
Regulatory assets | ||
Total regulatory assets | 953.2 | 754.1 |
Finance and capital leases | ||
Regulatory assets | ||
Total regulatory assets | 885.1 | 869.3 |
Pension and OPEB costs | ||
Regulatory assets | ||
Total regulatory assets | 483.3 | 490.6 |
Income tax related items | ||
Regulatory assets | ||
Total regulatory assets | 332.9 | 317.9 |
System support resource | ||
Regulatory assets | ||
Total regulatory assets | 317.8 | 316.7 |
Electric transmission costs | ||
Regulatory assets | ||
Total regulatory assets | 41.4 | 57.8 |
We Power generation | ||
Regulatory assets | ||
Total regulatory assets | 36.1 | 43 |
Asset retirement obligations | ||
Regulatory assets | ||
Total regulatory assets | 30.5 | 28.7 |
Other, net | ||
Regulatory assets | ||
Total regulatory assets | $ 20.3 | $ 24.2 |
REGULATORY ASSETS AND LIABILI_4
REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Regulatory liabilities | ||
Current liabilities | $ 27 | $ 11.9 |
Regulatory liabilities | 2,013.8 | 2,002.3 |
Total regulatory liabilities | 2,040.8 | 2,014.2 |
Income tax related items | ||
Regulatory liabilities | ||
Total regulatory liabilities | 1,021.1 | 1,024.8 |
Removal costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 757.3 | 748.1 |
Mines deferral | ||
Regulatory liabilities | ||
Total regulatory liabilities | 129.1 | 120.8 |
Pension and OPEB costs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 74.8 | 74.7 |
Uncollectible expense | ||
Regulatory liabilities | ||
Total regulatory liabilities | 15.6 | 16.4 |
Energy efficiency programs | ||
Regulatory liabilities | ||
Total regulatory liabilities | 14.1 | 13.5 |
Other, net | ||
Regulatory liabilities | ||
Total regulatory liabilities | $ 28.8 | $ 15.9 |
PROPERTY, PLANT, AND EQUIPMEN_2
PROPERTY, PLANT, AND EQUIPMENT (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Dec. 31, 2018 | |
Property, plant, and equipment | ||
Cost of removal reserve classified as a regulatory liability | $ 2,040.8 | $ 2,014.2 |
Net book value of plant classified as a regulatory asset | 3,100.6 | $ 2,902.3 |
Presque Isle power plant | ||
Property, plant, and equipment | ||
Plant to be retired, at carrying value | 172.1 | |
Cost of removal reserve classified as a regulatory liability | 11 | |
Net book value of plant classified as a regulatory asset | 183.1 | |
Utility segment | ||
Changes to severance liability | ||
Severance liability, balance at beginning of period | 12.9 | |
Severance payments | (0.2) | |
Severance liability, balance at end of the period | $ 12.7 |
SHORT-TERM DEBT AND LINES OF _3
SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Dec. 31, 2018 | |
Short-term borrowings | ||
Commercial paper outstanding | $ 75.5 | $ 134.9 |
Commercial paper | ||
Short-term borrowings | ||
Commercial paper outstanding | $ 75.5 | $ 134.9 |
Weighted-average interest rate on amounts outstanding | 2.64% | 2.96% |
Average amount outstanding during the period | $ 64.4 | |
Weighted-average interest rate during the period | 2.80% |
SHORT-TERM DEBT AND LINES OF _4
SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Revolving credit facility | ||
Letters of credit issued inside credit facility | $ 1.2 | |
Commercial paper outstanding | 75.5 | $ 134.9 |
Available capacity under existing agreement | 423.3 | |
Credit facility maturing during October 2022 | ||
Revolving credit facility | ||
Revolving credit facility | 500 | |
Commercial paper | ||
Revolving credit facility | ||
Commercial paper outstanding | $ 75.5 | $ 134.9 |
LEASES - ADOPTION OF ASU 2016-0
LEASES - ADOPTION OF ASU 2016-02 (Details) $ in Millions | 1 Months Ended | ||
Jan. 31, 2019USD ($) | Mar. 31, 2019USD ($) | Jan. 01, 2019USD ($)land_easement | |
Leases [Abstract] | |||
Impairment losses recorded upon adoption of ASU 2016-02 | $ 0 | ||
Number of land easements treated as leases upon adoption of ASU 2016-02 | land_easement | 0 | ||
Operating lease right of use assets | $ 12.5 | $ 13 | |
Operating lease liabilities | $ 12.5 | $ 13 | |
Finance lease expense impact of adoption of ASU 2016-02 | $ 0 |
LEASES - POWER PURCHASE COMMITM
LEASES - POWER PURCHASE COMMITMENT (Details) $ in Millions | 3 Months Ended | |
Mar. 31, 2019USD ($)MW | Dec. 31, 2009USD ($) | |
Leases | ||
Finance lease obligation | $ 2,865.8 | |
Power purchase commitment | ||
Leases | ||
Power purchase contract period | 25 years | |
Firm capacity from power purchase contract (in megawatts) | MW | 236 | |
Minimum energy requirements over remaining term of power purchase contract (in megawatts) | MW | 0 | |
Power purchase contract renewal period | 10 years | |
Maximum regulatory asset for power purchase contract | $ 78.5 | |
Regulatory asset at end of life of power purchase contract | $ 0 | |
Finance lease obligation | 22.1 | |
Finance lease obligation at end of life of power purchase contract | $ 0 |
LEASES - PORT WASHINGTON GENERA
LEASES - PORT WASHINGTON GENERATING STATION (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2019USD ($)renewal_termsgenerating_unitscontractMW | |
Leases | |
Finance lease obligation | $ 2,865.8 |
Port Washington Generating Station | |
Leases | |
Number of generation units at the Port Washington Generating Station | generating_units | 2 |
Capacity of generation unit (in megawatts) | MW | 545 |
Power purchase contract period | 25 years |
Regulatory asset at end of life of power purchase contract | $ 0 |
Finance lease obligation | 631.5 |
Finance lease obligation at end of life of power purchase contract | $ 0 |
Minimum number of power purchase contracts that can be renewed | contract | 1 |
Maximum number of consecutive renewal terms | renewal_terms | 3 |
Increase to contract term if renewal selected (as percent of remaining economic life of generation unit) | 80.00% |
Minimum number of generation units that can be purchased | generating_units | 1 |
Port Washington Generating Station unit 1 (PWGS 1) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 129.3 |
Port Washington Generating Station unit 2 (PWGS 2) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 126 |
LEASES - ELM ROAD GENERATING ST
LEASES - ELM ROAD GENERATING STATION (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2019USD ($)renewal_termsgenerating_unitscontract | |
Leases | |
Finance lease obligation | $ 2,865.8 |
Elm Road Generating Station | |
Leases | |
Power purchase contract period | 30 years |
Regulatory asset at end of life of power purchase contract | $ 0 |
Finance lease obligation | 2,212.2 |
Finance lease obligation at end of life of power purchase contract | $ 0 |
Minimum number of power purchase contracts that can be renewed | contract | 1 |
Maximum number of consecutive renewal terms | renewal_terms | 3 |
Increase to contract term if renewal selected (as percent of remaining economic life of generation unit) | 80.00% |
Minimum number of generation units that can be purchased | generating_units | 1 |
Elm Road Generating Station unit 1 (ER 1) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 524.1 |
Elm Road Generating Station unit 2 (ER 2) | |
Leases | |
Maximum regulatory asset for power purchase contract | $ 430.6 |
LEASES - LEASE EXPENSE AND SUPP
LEASES - LEASE EXPENSE AND SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Lease expense | ||
Operating lease expense | $ 0.7 | $ 0.7 |
Lease expense | 94.5 | 94.4 |
Amortization of finance lease right of use assets | 5.7 | |
Interest on finance lease liabilities | 88.1 | |
Other information | ||
Operating cash flows from finance / capital leases | 89.8 | 94.2 |
Operating cash flows from operating leases | 0.7 | 0.7 |
Financing cash flows from finance leases | 5.7 | 0 |
Noncash activity - right of use assets obtained in exchange for new operating lease liabilities | $ 13 | |
Weighted average remaining lease term - finance lease | 19 years 4 months | |
Weighted average remaining lease term - operating leases | 22 years 5 months | |
Weighted average discount rate - finance lease | 13.90% | |
Weighted average discount rate - operating leases | 4.60% | |
Finance and capital leases | ||
Lease expense | ||
Lease expense | $ 93.8 | 93.7 |
Power purchase commitment | ||
Lease expense | ||
Lease expense | 2 | 1.9 |
We Power leases | ||
Lease expense | ||
Lease expense | $ 91.8 | $ 91.8 |
LEASES - RIGHT OF USE ASSETS (D
LEASES - RIGHT OF USE ASSETS (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Right of use assets and future minimum lease payments | |||
Operating lease right of use assets | $ 12.5 | $ 13 | |
Finance and capital leases | |||
Right of use assets and future minimum lease payments | |||
Total finance lease right of use assets / capital lease assets | 1,980.6 | $ 1,987.9 | |
Power purchase commitment | |||
Right of use assets and future minimum lease payments | |||
Under finance / capital lease | 140.3 | 140.3 | |
Accumulated amortization | (122.3) | (120.9) | |
Total finance lease right of use assets / capital lease assets | 18 | 19.4 | |
Port Washington Generating Station | |||
Right of use assets and future minimum lease payments | |||
Under finance / capital lease | 739.2 | 736.9 | |
Accumulated amortization | (343.9) | (335.9) | |
Total finance lease right of use assets / capital lease assets | 395.3 | 401 | |
Elm Road Generating Station | |||
Right of use assets and future minimum lease payments | |||
Under finance / capital lease | 2,184.5 | 2,166.3 | |
Accumulated amortization | (617.2) | (598.8) | |
Total finance lease right of use assets / capital lease assets | $ 1,567.3 | $ 1,567.5 |
LEASES - FUTURE MINIMUM LEASE P
LEASES - FUTURE MINIMUM LEASE PAYMENTS (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Jan. 01, 2019 | Dec. 31, 2018 |
Total operating leases | |||
Nine months ended December 31, 2019 | $ 2 | ||
2020 | 2.7 | ||
2021 | 0.7 | ||
2022 | 0.6 | ||
2023 | 0.5 | ||
2024 | 0.5 | ||
Thereafter | 13.5 | ||
Total minimum lease payments | 20.5 | ||
Less: interest | (8) | ||
Present value of minimum lease payments | 12.5 | $ 13 | |
Less: short-term lease liabilities | (2.2) | ||
Long-term lease liabilities | 10.3 | ||
Total finance leases | |||
Nine months ended December 31, 2019 | 299.5 | ||
2020 | 399.9 | ||
2021 | 400.5 | ||
2022 | 395.1 | ||
2023 | 390.8 | ||
2024 | 390.6 | ||
Thereafter | 5,216.3 | ||
Total minimum lease payments | 7,492.7 | ||
Less: interest | (4,626.9) | ||
Present value of minimum lease payments | 2,865.8 | ||
Less: short-term lease liabilities | (52) | $ (49.9) | |
Long-term lease liabilities | 2,813.8 | $ 2,807.2 | |
Power purchase commitment | |||
Total finance leases | |||
Nine months ended December 31, 2019 | 6.2 | ||
2020 | 8.8 | ||
2021 | 9.4 | ||
2022 | 4.2 | ||
2023 | 0 | ||
2024 | 0 | ||
Thereafter | 0 | ||
Total minimum lease payments | 28.6 | ||
Less: interest | (6.5) | ||
Present value of minimum lease payments | 22.1 | ||
Less: short-term lease liabilities | (5.2) | ||
Long-term lease liabilities | 16.9 | ||
Port Washington Generating Station | |||
Total finance leases | |||
Nine months ended December 31, 2019 | 73.5 | ||
2020 | 98 | ||
2021 | 98 | ||
2022 | 98 | ||
2023 | 98 | ||
2024 | 97.9 | ||
Thereafter | 677.8 | ||
Total minimum lease payments | 1,241.2 | ||
Less: interest | (609.7) | ||
Present value of minimum lease payments | 631.5 | ||
Less: short-term lease liabilities | (23.1) | ||
Long-term lease liabilities | 608.4 | ||
Elm Road Generating Station | |||
Total finance leases | |||
Nine months ended December 31, 2019 | 219.8 | ||
2020 | 293.1 | ||
2021 | 293.1 | ||
2022 | 292.9 | ||
2023 | 292.8 | ||
2024 | 292.7 | ||
Thereafter | 4,538.5 | ||
Total minimum lease payments | 6,222.9 | ||
Less: interest | (4,010.7) | ||
Present value of minimum lease payments | 2,212.2 | ||
Less: short-term lease liabilities | (23.7) | ||
Long-term lease liabilities | $ 2,188.5 |
MATERIALS, SUPPLIES, AND INVE_3
MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Inventory Disclosure [Abstract] | ||
Materials and supplies | $ 143.7 | $ 146.1 |
Fossil fuel | 41.2 | 58.7 |
Natural gas in storage | 6.9 | 36.6 |
Total | $ 191.8 | $ 241.4 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Effective Income Tax Rate Reconciliation, Amount | ||
Statutory federal income tax, amount | $ 22.7 | $ 21.5 |
State income taxes net of federal tax benefit, amount | 7.1 | 6.7 |
Tax repairs, amount | (29.6) | (25.5) |
Federal excess deferred tax amortization, amount | (6.2) | (5.4) |
Wind production tax credits, amount | (2.8) | (3.2) |
Other, amount | 2.3 | 2.3 |
Total income tax expense | $ (6.5) | $ (3.6) |
Effective Income Tax Rate Reconciliation, Percent | ||
Statutory federal income tax, percent | 21.00% | 21.00% |
State income taxes net of federal tax benefit, percent | 6.60% | 6.50% |
Tax repairs, percentage | (27.30%) | (24.90%) |
Federal excess deferred tax amortization, percent | (5.70%) | (5.20%) |
Wind production tax credits, percent | (2.60%) | (3.10%) |
Other, percent | 2.00% | 2.20% |
Total income tax expense, percent | (6.00%) | (3.50%) |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Assets | ||
Derivative asset | $ 3.8 | $ 5.1 |
Liabilities | ||
Derivative liability | 0.1 | 1.3 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative asset | 3.8 | 5.1 |
Liabilities | ||
Derivative liability | 1.3 | |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 1.3 | 0.7 |
Liabilities | ||
Derivative liability | 1.2 | |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 0.5 | 0 |
Liabilities | ||
Derivative liability | 0.1 | |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 2 | 4.4 |
Liabilities | ||
Derivative liability | 0 | |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative asset | 1.3 | 0.7 |
Liabilities | ||
Derivative liability | 1.2 | |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative asset | 1.3 | 0.7 |
Liabilities | ||
Derivative liability | 1.2 | |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | |
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | |
Fair value measurements on a recurring basis | FTRs | ||
Assets | ||
Derivative asset | 2 | 4.4 |
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 | 2 | 4.4 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative asset | 0.5 | |
Liabilities | ||
Derivative liability | 0.1 | 0.1 |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative asset | 0 | |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative asset | 0.5 | |
Liabilities | ||
Derivative liability | 0.1 | 0.1 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | |
Liabilities | ||
Derivative liability | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - LEVEL
FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Level 3 rollforward | ||
Balance at the beginning of the period | $ 4.4 | $ 2.4 |
Settlements | (2.4) | (1.6) |
Balance at the end of the period | $ 2 | $ 0.8 |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Carrying value and estimated fair value of financial instruments | ||
Preferred stock | $ 30.4 | $ 30.4 |
Carrying Amount | ||
Carrying value and estimated fair value of financial instruments | ||
Preferred stock | 30.4 | 30.4 |
Long-term debt, including current portion | 2,710.1 | 2,709.6 |
Fair Value | ||
Carrying value and estimated fair value of financial instruments | ||
Preferred stock | 28.3 | 28.3 |
Long-term debt, including current portion | $ 2,981.2 | $ 2,881.6 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND DERIVATIVE LIABILITIES (Details) $ in Millions | Mar. 31, 2019USD ($)Instruments | Dec. 31, 2018USD ($) |
Derivative Asset | ||
Other current derivative assets | $ 3.6 | $ 5.1 |
Derivative asset | 3.8 | 5.1 |
Derivative Liability | ||
Other current derivative liabilities | 0.1 | 1.3 |
Derivative liability | 0.1 | 1.3 |
Natural gas contracts | ||
Derivative Asset | ||
Other current derivative assets | 1.1 | 0.7 |
Other long-term derivative assets | 0.2 | 0 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 1.2 |
Other long-term derivative liabilities | 0 | 0 |
FTRs | ||
Derivative Asset | ||
Other current derivative assets | 2 | 4.4 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.5 | 0 |
Derivative Liability | ||
Other current derivative liabilities | $ 0.1 | $ 0.1 |
Designated as hedging instrument | ||
Derivative assets and liabilities | ||
Number of derivative instruments held | Instruments | 0 |
DERIVATIVE INSTRUMENTS - GAINS
DERIVATIVE INSTRUMENTS - GAINS (LOSSES) AND NOTIONAL VOLUMES (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2019USD ($)MMBTUMWhgal | Mar. 31, 2018USD ($)MMBTUMWhgal | |
Realized Gain (Loss) on Derivatives | ||
Gains (Losses) | $ 0.2 | $ (0.6) |
Natural gas contracts | ||
Realized Gain (Loss) on Derivatives | ||
Gains (Losses) | $ (1.4) | $ (1.8) |
Notional Sales Volumes | ||
Notional sales volumes | MMBTU | 18.1 | 11.7 |
Petroleum products contracts | ||
Realized Gain (Loss) on Derivatives | ||
Gains (Losses) | $ 0 | $ 0.4 |
Notional Sales Volumes | ||
Notional sales volumes (gallons) | gal | 0 | 1.4 |
FTRs | ||
Realized Gain (Loss) on Derivatives | ||
Gains (Losses) | $ 1.6 | $ 0.8 |
Notional Sales Volumes | ||
Notional sales volumes | MWh | 5.5 | 5.8 |
DERIVATIVE INSTRUMENTS - OFFSET
DERIVATIVE INSTRUMENTS - OFFSETTING TABLE (Details) - USD ($) $ in Millions | Mar. 31, 2019 | Dec. 31, 2018 |
Cash collateral | ||
Collateral in margin account | $ 1.1 | $ 1.1 |
Offsetting Derivative Assets | ||
Gross amount recognized on the balance sheet | 3.8 | 5.1 |
Gross amount not offset on the balance sheet | 0 | (0.6) |
Net amount | 3.8 | 4.5 |
Offsetting Derivative Liabilities | ||
Gross amount recognized on the balance sheet | 0.1 | 1.3 |
Gross amount not offset on the balance sheet | 0 | (1.3) |
Net amount | $ 0.1 | 0 |
Collateral posted | $ 0.7 |
GUARANTEES (Details)
GUARANTEES (Details) $ in Millions | Mar. 31, 2019USD ($) |
Standby letters of credit | |
Guarantees | |
Guarantees with expiration over 3 years | $ 26.2 |
EMPLOYEE BENEFITS-COSTS AND CON
EMPLOYEE BENEFITS-COSTS AND CONTRIBUTIONS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Components of net periodic benefit costs | ||
Contributions and payments related to pension and OPEB plans | $ 1.9 | $ 2.1 |
Pension costs | ||
Components of net periodic benefit costs | ||
Service cost | 3.8 | 3.3 |
Interest cost | 11.5 | 10.6 |
Expected return on plan assets | (18.2) | (19) |
Amortization of prior service (credit) cost | 0.1 | 0.2 |
Amortization of net actuarial (gain) loss | 7.2 | 9.4 |
Net periodic benefit (credit) cost | 4.4 | 4.5 |
Contributions and payments related to pension and OPEB plans | 1.7 | |
Estimated future employer contributions for the remainder of the year | 2.1 | |
Other Postretirement Benefit Costs | ||
Components of net periodic benefit costs | ||
Service cost | 1.2 | 1.8 |
Interest cost | 2.4 | 2.8 |
Expected return on plan assets | (3.5) | (3.9) |
Amortization of prior service (credit) cost | (0.5) | (0.6) |
Amortization of net actuarial (gain) loss | (0.4) | 0 |
Net periodic benefit (credit) cost | (0.8) | $ 0.1 |
Contributions and payments related to pension and OPEB plans | 0.2 | |
Estimated future employer contributions for the remainder of the year | $ 3.5 |
SEGMENT INFORMATION (Details)
SEGMENT INFORMATION (Details) | 3 Months Ended | |
Mar. 31, 2019USD ($)areasegment | Mar. 31, 2018USD ($) | |
Segment Reporting [Abstract] | ||
Number of reportable segments | segment | 2 | |
Number of service areas | area | 3 | |
Significant items reported in the other segment | $ | $ 0 | $ 0 |
VARIABLE INTEREST ENTITIES (Det
VARIABLE INTEREST ENTITIES (Details) - Purchased power agreement | 3 Months Ended |
Mar. 31, 2019USD ($)MW | |
Variable interest entities | |
Firm capacity from purchased power agreement (in megawatts) | MW | 236 |
Minimum energy requirements over remaining term of purchased power agreement (in megawatts) | MW | 0 |
Remaining term of purchased power agreement (in years) | 3 years |
Residual guarantee associated with purchased power agreement | $ | $ 0 |
Required payments over remaining term of purchased power agreement | $ | $ 28,600,000 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Mar. 31, 2019USD ($) |
Minimum future commitments for purchase obligations | |
Purchase obligations | $ 10,016.7 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions | 3 Months Ended | 12 Months Ended |
Mar. 31, 2019USD ($)changedegreecelsiusgenerating_unitsMW | Dec. 31, 2018USD ($)T | |
Manufactured gas plant remediation | ||
Regulatory assets | $ 3,100.6 | $ 2,902.3 |
Mercury and air toxics standards | ||
Air quality | ||
Revisions to Mercury and Air Toxics Standards | change | 0 | |
Climate Change | Electric | ||
Air quality | ||
Company goal for percentage of carbon dioxide emissions reduction by 2030 | 40.00% | |
Long-term company goal for percentage of carbon dioxide emissions reduction by 2050 | 80.00% | |
Coal generation retired since the beginning of 2018 | MW | 1,500 | |
Carbon Dioxide emissions | T | 20 | |
Climate Change | Electric | Maximum | ||
Air quality | ||
Global temperature increases limit | degreecelsius | 2 | |
Climate Change | Natural gas | ||
Air quality | ||
Carbon Dioxide emissions | T | 4.1 | |
Steam Electric Effluent Limitation Guidelines | Electric | ||
Water quality | ||
Total units of OCPP and ERGS | generating_units | 6 | |
Expected costs to achieve required emissions reduction | $ 50 | |
Manufactured Gas Plant Remediation | Natural gas | ||
Manufactured gas plant remediation | ||
Reserves for future remediation | 13.2 | $ 13.2 |
Environmental remediation costs | Manufactured Gas Plant Remediation | Natural gas | ||
Manufactured gas plant remediation | ||
Regulatory assets | $ 24 | $ 24.2 |
SUPPLEMENTAL CASH FLOW INFORM_3
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2019 | Mar. 31, 2018 | |
Supplemental Cash Flow Information [Abstract] | ||
Cash (paid) for interest, net of amount capitalized | $ (94.9) | $ (4.7) |
Significant non-cash transactions | ||
Accounts payable related to construction costs | $ 14.7 | $ 7.3 |
REGULATORY ENVIRONMENT (Details
REGULATORY ENVIRONMENT (Details) - Public Service Commission of Wisconsin (PSCW) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | |
Mar. 31, 2019 | Sep. 30, 2017 | Mar. 31, 2019 | |
2020 rates | Electric rates | |||
Regulatory environment | |||
Requested rate increase | $ 83 | ||
Requested rate increase (as a percent) | 2.90% | ||
2020 rates | Natural gas rates | |||
Regulatory environment | |||
Requested rate increase | $ 15 | ||
Requested rate increase (as a percent) | 3.90% | ||
2020 rates | Steam rates | |||
Regulatory environment | |||
Requested rate increase | $ 1 | ||
Requested rate increase (as a percent) | 4.50% | ||
2021 rates | Electric rates | |||
Regulatory environment | |||
Requested rate increase | $ 83 | ||
Requested rate increase (as a percent) | 2.90% | ||
2021 rates | Natural gas rates | |||
Regulatory environment | |||
Requested rate increase | $ 0 | ||
2021 rates | Steam rates | |||
Regulatory environment | |||
Requested rate increase | $ 0 | ||
2020 and 2021 rates | |||
Regulatory environment | |||
Requested return on equity | 10.35% | ||
Requested common equity component average (as a percent) | 52.00% | ||
2020 and 2021 rates | Electric rates | Tax Cuts and Jobs Act of 2017 | |||
Regulatory environment | |||
Change in regulatory liabilities from tax legislation | $ 111 | ||
2018 and 2019 rates | |||
Regulatory environment | |||
Approved return on equity (as a percent) | 10.20% | ||
Income statement impact of flow through of repair related deferred tax liabilities | $ 0 | ||
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% |