DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION | 6 Months Ended |
Jun. 30, 2017shares | |
Document and Entity Information [Abstract] | |
Entity Registrant Name | WISCONSIN ELECTRIC POWER CO |
Entity Central Index Key | 107,815 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Document Type | 10-Q |
Document Period End Date | Jun. 30, 2017 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | Q2 |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 33,289,327 |
CONDENSED CONSOLIDATED INCOME S
CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Income Statement [Abstract] | ||||
Operating revenues | $ 855.4 | $ 877.2 | $ 1,827.4 | $ 1,852.7 |
Cost of sales | 273.9 | 284.3 | 622.5 | 620.7 |
Other operation and maintenance | 327.7 | 336.2 | 655.5 | 684.4 |
Depreciation and amortization | 82.7 | 80.8 | 164.8 | 161.2 |
Property and revenue taxes | 28.3 | 29 | 56.7 | 58 |
Total operating expenses | 712.6 | 730.3 | 1,499.5 | 1,524.3 |
Operating income | 142.8 | 146.9 | 327.9 | 328.4 |
Equity in earnings of transmission affiliate | 0 | 11.4 | 0 | 26.1 |
Other income, net | 4.4 | 3.2 | 8.8 | 6.2 |
Interest expense | 29.1 | 29.4 | 58.7 | 58.5 |
Other expense | (24.7) | (14.8) | (49.9) | (26.2) |
Income before income taxes | 118.1 | 132.1 | 278 | 302.2 |
Income tax expense | 42.5 | 49.2 | 100.3 | 111.7 |
Net income | 75.6 | 82.9 | 177.7 | 190.5 |
Preferred stock dividend requirements | 0.3 | 0.3 | 0.6 | 0.6 |
Net income attributed to common shareholder | $ 75.3 | $ 82.6 | $ 177.1 | $ 189.9 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash and cash equivalents | $ 1.6 | $ 15.4 |
Accounts receivable and unbilled revenues, net of reserves of $39.2 and $40.9, respectively | 452.4 | 503.2 |
Accounts and notes receivable from related parties | 82.1 | 58.2 |
Materials, supplies, and inventories | 278.2 | 271 |
Prepayments | 125.5 | 138 |
Other | 9.7 | 24.6 |
Current assets | 949.5 | 1,010.4 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation of $3,651.8 and $3,619.6 respectively | 9,859 | 9,832.3 |
Regulatory assets | 2,114.4 | 2,036.6 |
Equity investment in transmission affiliate | 0 | 402 |
Other | 83.6 | 90.2 |
Long-term assets | 12,057 | 12,361.1 |
Total assets | 13,006.5 | 13,371.5 |
Current liabilities | ||
Short-term debt | 75 | 159 |
Current portion of long-term debt | 250 | 0 |
Current portion of capital lease obligations | 32.2 | 28.5 |
Subsidiary note payable to WEC Energy Group | 0 | 18.5 |
Accounts payable | 282 | 297.9 |
Accounts payable to related parties | 124.7 | 112.9 |
Accrued payroll and benefits | 47.2 | 51.8 |
Accrued taxes | 21.6 | 46 |
Other | 81.9 | 100.1 |
Current liabilities | 914.6 | 814.7 |
Long-term liabilities | ||
Long-term debt | 2,411.2 | 2,661.1 |
Capital lease obligations | 2,839.9 | 2,756.5 |
Deferred income taxes | 2,170.2 | 2,333.3 |
Regulatory liabilities | 861.6 | 853.9 |
Pension and OPEB obligations | 157.4 | 167.6 |
Other | 263.3 | 260.2 |
Long-term liabilities | 8,703.6 | 9,032.6 |
Commitments and contingencies (Note 13) | ||
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 | 815.2 | 1,020.1 |
Retained earnings | 2,209.8 | 2,140.8 |
Common shareholder's equity | 3,357.9 | 3,493.8 |
Preferred stock | 30.4 | 30.4 |
Total liabilities and equity | $ 13,006.5 | $ 13,371.5 |
CONDENSED CONSOLIDATED BALANCE4
CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICALS) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and accrued unbilled revenues, reserves | $ 39.2 | $ 40.9 |
Property, plant, and equipment, accumulated depreciation | $ 3,651.8 | $ 3,619.6 |
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 | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
Operating Activities | ||
Net income | $ 177.7 | $ 190.5 |
Reconciliation to cash provided by operating activities | ||
Depreciation and amortization | 164.8 | 165.1 |
Deferred income taxes and investment tax credits, net | 64.1 | 113.4 |
Contributions and payments related to pension and OPEB plans | (5.6) | (4.6) |
Equity income in transmission affiliate, net of distributions | 0 | (8.1) |
Proceeds from (payments for) liabilities transferred from (to) WBS | 0.9 | (107) |
Change in – | ||
Accounts receivable and unbilled revenues | 26.7 | (8.1) |
Materials, supplies, and inventories | (7.2) | 38.6 |
Other current assets | 10.1 | 24.7 |
Accounts payable | (8.1) | (3.9) |
Accrued taxes | (24.4) | (13.8) |
Other current liabilities | (24.2) | (10.4) |
Other, net | (14.9) | (40.3) |
Net cash provided by operating activities | 359.9 | 336.1 |
Investing Activities | ||
Capital expenditures | (246.9) | (191.9) |
Capital contributions to transmission affiliate | 0 | (4.6) |
Proceeds from the sale of assets | 22 | 31.7 |
Proceeds from assets transferred to WBS | 0 | 13.1 |
Short-term notes receivable from related parties, net | (3.1) | 0 |
Other, net | 2.3 | 1 |
Net cash used in investing activities | (225.7) | (150.7) |
Financing Activities | ||
Change in short-term debt | (84) | 2.5 |
Repayment of subsidiary note to parent | (18.5) | (2.5) |
Equity contribution from parent | 75 | 0 |
Payments of dividends to parent | (120) | (220) |
Payments of preferred stock dividends | (0.6) | (0.6) |
Other, net | 0.1 | 16.6 |
Net cash used in financing activities | (148) | (204) |
Net change in cash and cash equivalents | (13.8) | (18.6) |
Cash and cash equivalents at beginning of period | 15.4 | 27.1 |
Cash and cash equivalents at end of period | $ 1.6 | $ 8.5 |
GENERAL INFORMATION
GENERAL INFORMATION | 6 Months Ended |
Jun. 30, 2017 | |
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, and statements of cash flows, 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. Prior to January 1, 2017, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 12, Related Parties, for more information on the transfer. In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. UMERC holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan. The existing contract between the Tilden Mining Company and us will remain in place until a new power generation solution for the region is commercially operational. See Note 12, Related Parties , and Note 15, Regulatory Environment , for more information on UMERC. 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, 2016 . 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 and six months ended June 30 , 2017 , are not necessarily indicative of expected results for 2017 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. |
DISPOSITIONS
DISPOSITIONS | 6 Months Ended |
Jun. 30, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
DISPOSITIONS | DISPOSITIONS Utility Segment Sale of Milwaukee County Power Plant In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ( $6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. Other Segment Sale of Bostco Real Estate Holdings In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. |
COMMON EQUITY
COMMON EQUITY | 6 Months Ended |
Jun. 30, 2017 | |
Equity [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the six months ended June 30, 2017 : (in millions) Retained Earnings Balance at December 31, 2016 $ 2,140.8 Net income 177.7 Common stock dividends (120.0 ) Preferred stock dividends (0.6 ) Cumulative effect of adoption of ASU 2016-09 11.9 Balance at June 30, 2017 $ 2,209.8 ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating expected forfeitures and recording them over the vesting period. As we did not record any excess tax benefits in 2017, adoption of this ASU had no impact on our financial statements other than the cumulative-effect adjustment discussed above. Restrictions Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. See Note 9, Common Equity, in our 2016 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 | 6 Months Ended |
Jun. 30, 2017 | |
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) June 30, 2017 December 31, 2016 Commercial paper Amount outstanding $ 75.0 $ 159.0 Weighted-average interest rate on amounts outstanding 1.33 % 0.87 % Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2017 , was $36.4 million with a weighted-average interest rate during the period of 0.97% . In April 2017, our consolidated subsidiary, Bostco, paid off a note payable to our parent, WEC Energy Group. 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 June 30, 2017 Revolving credit facility December 2020 $ 500.0 Less: Letters of credit issued inside credit facility $ 26.2 Commercial paper outstanding 75.0 Available capacity under existing agreement $ 398.8 |
MATERIALS, SUPPLIES, AND INVENT
MATERIALS, SUPPLIES, AND INVENTORIES | 6 Months Ended |
Jun. 30, 2017 | |
Inventory Disclosure [Abstract] | |
MATERIALS, SUPPLIES, AND INVENTORIES | MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) June 30, 2017 December 31, 2016 Materials and supplies $ 153.2 $ 148.1 Fossil fuel 100.1 91.1 Natural gas in storage 24.9 31.8 Total $ 278.2 $ 271.0 Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 6 Months Ended |
Jun. 30, 2017 | |
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 price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period. 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: June 30, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.3 $ 0.2 $ — $ 0.5 Petroleum products contracts 0.2 — — 0.2 FTRs — — 6.0 6.0 Coal contracts — 0.7 — 0.7 Total derivative assets $ 0.5 $ 0.9 $ 6.0 $ 7.4 Derivative liabilities Natural gas contracts $ 0.7 $ — $ — $ 0.7 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 2.3 — — 2.3 Total derivative liabilities $ 0.8 $ 2.3 $ — $ 3.1 December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.0 $ 0.8 $ — $ 6.8 Petroleum products contracts 0.2 — — 0.2 FTRs — — 3.1 3.1 Coal contracts — 1.9 — 1.9 Total derivative assets $ 6.2 $ 2.7 $ 3.1 $ 12.0 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 0.2 $ 0.5 $ — $ 0.7 The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Balance at the beginning of the period $ 1.1 $ 0.6 $ 3.1 $ 1.6 Purchases 6.9 8.1 6.9 8.1 Settlements (2.0 ) (1.2 ) (4.0 ) (2.2 ) Balance at the end of the period $ 6.0 $ 7.5 $ 6.0 $ 7.5 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: June 30, 2017 December 31, 2016 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 30.5 $ 30.4 $ 28.8 Long-term debt, including current portion 2,661.2 2,939.2 2,661.1 2,923.4 Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, short-term notes receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based on the quoted market prices for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 6 Months Ended |
Jun. 30, 2017 | |
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: June 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.5 $ 0.6 $ 6.3 $ 0.1 Petroleum products contracts 0.2 0.1 0.2 0.1 FTRs 6.0 — 3.1 — Coal contracts 0.7 1.5 1.5 0.5 Total other current * $ 7.4 $ 2.2 $ 11.1 $ 0.7 Other long-term Natural gas contracts $ — $ 0.1 $ 0.5 $ — Coal contracts — 0.8 0.4 — Total other long-term * — 0.9 0.9 — Total $ 7.4 $ 3.1 $ 12.0 $ 0.7 * 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 June 30, 2017 Three Months Ended June 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 5.0 Dth $ 0.2 9.6 Dth $ (4.8 ) Petroleum products contracts 4.9 gallons (0.4 ) 2.6 gallons (0.8 ) FTRs 7.3 MWh 2.0 5.7 MWh 0.5 Total $ 1.8 $ (5.1 ) Six Months Ended June 30, 2017 Six Months Ended June 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 13.2 Dth $ 0.7 20.2 Dth $ (12.0 ) Petroleum products contracts 9.8 gallons (0.9 ) 4.2 gallons (1.5 ) FTRs 14.3 MWh 4.5 10.9 MWh 2.3 Total $ 4.3 $ (11.2 ) 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 June 30, 2017 , we had posted cash collateral of $2.3 million in our margin accounts, and at December 31, 2016, we had received cash collateral of $3.4 million in our margin accounts. On our balance sheets, cash collateral provided to others is reflected in other current assets and cash collateral received is reflected in other current liabilities. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: June 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 7.4 $ 3.1 $ 12.0 $ 0.7 Gross amount not offset on the balance sheet (0.5 ) (0.7 ) (1) (3.6 ) (2) (0.2 ) Net amount $ 6.9 $ 2.4 $ 8.4 $ 0.5 (1) Includes cash collateral posted of $0.2 million . (2) Includes cash collateral received of $3.4 million . |
EMPLOYEE BENEFITS
EMPLOYEE BENEFITS | 6 Months Ended |
Jun. 30, 2017 | |
Compensation and Retirement Disclosure [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 June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Service cost $ 3.1 $ 2.5 $ 6.1 $ 5.2 Interest cost 11.6 12.3 23.5 24.9 Expected return on plan assets (19.1 ) (19.4 ) (38.3 ) (38.8 ) Loss on plan settlement 2.8 — 2.8 — Amortization of prior service cost 0.3 0.4 0.6 0.8 Amortization of net actuarial loss 8.9 8.2 17.7 16.2 Net periodic benefit cost $ 7.6 $ 4.0 $ 12.4 $ 8.3 OPEB Costs Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Service cost $ 1.5 $ 3.5 $ 3.4 $ 3.6 Interest cost 3.1 4.7 6.2 6.6 Expected return on plan assets (3.6 ) (5.8 ) (7.2 ) (7.0 ) Amortization of prior service credit (0.3 ) (0.2 ) (0.6 ) (0.5 ) Amortization of net actuarial (gain) loss (0.3 ) 0.3 — 0.5 Net periodic benefit cost $ 0.4 $ 2.5 $ 1.8 $ 3.2 During the six months ended June 30, 2017 , we made payments of $4.3 million related to our pension plans and $1.3 million to our OPEB plans. We expect to make payments of $0.9 million related to our pension plans and $3.2 million related to our OPEB plans during the remainder of 2017 , dependent upon various factors affecting us, including our liquidity position and possible tax law changes. |
INVESTMENT IN AMERICAN TRANSMIS
INVESTMENT IN AMERICAN TRANSMISSION COMPANY | 6 Months Ended |
Jun. 30, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
INVESTMENT IN AMERICAN TRANSMISSION COMPANY | INVESTMENT IN AMERICAN TRANSMISSION COMPANY At December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. On January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in the recognition of a gain or loss. The following table shows changes to our investment in ATC: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Balance at beginning of period $ — $ 394.3 $ 402.0 $ 382.2 Less: Transfer of ownership interest — — 402.0 — Add: Earnings from equity method investment — 11.4 — 26.1 Add: Capital contributions — 1.1 — 4.6 Less: Distributions — 12.0 — 18.0 Less: Other — — — 0.1 Balance at end of period $ — $ 394.8 $ — $ 394.8 See Note 12, Related Parties, for more information on transactions with ATC. |
SEGMENT INFORMATION
SEGMENT INFORMATION | 6 Months Ended |
Jun. 30, 2017 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At June 30, 2017 , we reported two segments, which are described below. Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, northern Wisconsin, and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of the Tilden Mining Company. See Note 12, Related Parties , and Note 15, Regulatory Environment , for additional information. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. 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. Our other segment includes Bostco, our non-utility subsidiary that developed and invested in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 2, Dispositions, for more information . Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 9, Investment in American Transmission Company, for more information . The following tables show summarized financial information related to our reportable segments for the three and six months ended June 30 , 2017 and 2016 : (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended June 30, 2017 Operating revenues $ 855.4 $ — $ 855.4 Other operation and maintenance 327.7 — 327.7 Depreciation and amortization 82.7 — 82.7 Operating income 142.8 — 142.8 Interest expense 29.1 — 29.1 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended June 30, 2016 Operating revenues $ 877.2 $ — $ 877.2 Other operation and maintenance 336.2 — 336.2 Depreciation and amortization 80.8 — 80.8 Operating income 146.9 — 146.9 Equity in earnings of transmission affiliate — 11.4 11.4 Interest expense 29.1 0.3 29.4 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Six Months Ended June 30, 2017 Operating revenues $ 1,827.4 $ — $ 1,827.4 Other operation and maintenance 655.5 — 655.5 Depreciation and amortization 164.8 — 164.8 Operating income 327.9 — 327.9 Interest expense 58.4 0.3 58.7 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Six Months Ended June 30, 2016 Operating revenues $ 1,852.7 $ — $ 1,852.7 Other operation and maintenance 684.4 — 684.4 Depreciation and amortization 161.2 — 161.2 Operating income 328.4 — 328.4 Equity in earnings of transmission affiliate — 26.1 26.1 Interest expense 58.0 0.5 58.5 |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 6 Months Ended |
Jun. 30, 2017 | |
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. American Transmission Company As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 9, Investment in American Transmission Company, for more information . The significant assets and liabilities related to ATC recorded on our balance sheet at December 31, 2016 included our equity investment, distributions receivable, and accounts payable. At December 31, 2016 , our equity investment was $402.0 million , which approximated our maximum exposure to loss as a result of our involvement with ATC. In addition, we had a receivable of $13.4 million recorded at December 31, 2016 for distributions from ATC. We also had $20.0 million of accounts payable due to ATC at December 31, 2016 for network transmission services. Purchased Power Agreement We have identified a purchased power 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 capital lease. The agreement includes no minimum energy requirements over the remaining term of approximately five 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 purchased power agreement. We have approximately $78.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the six months ended June 30, 2017 and 2016 were $9.0 million and $26.9 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract. |
RELATED PARTIES
RELATED PARTIES | 6 Months Ended |
Jun. 30, 2017 | |
Related Party Transactions [Abstract] | |
RELATED PARTIES | RELATED PARTIES We and our consolidated subsidiary, Bostco, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, ATC, and other affiliated entities. We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. A new AIA took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. In June 2017, the PSCW approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater, which is discussed in more detail below. The proposal to incorporate Bluewater into the AIA is pending before the Minnesota Public Utilities Commission. Bostco, our consolidated subsidiary, had a note payable to our parent company, WEC Energy Group. The balance of this note payable was $18.5 million at December 31, 2016 . This note payable was paid off in the first half of 2017. In connection with the sale of Bostco’s remaining real estate holdings, Wispark LLC, a subsidiary of WEC Energy Group, provided $7.0 million of financing to the buyer and established a corresponding note receivable. Bostco had a $7.0 million related party receivable from Wispark LLC that was paid in April 2017. See Note 2, Dispositions, for more information on the real estate sale. On January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016, to another subsidiary of WEC Energy Group. In addition, we transferred $195.1 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs. Our balance sheets included the following receivables and payables related to transactions entered into with ATC: (in millions) June 30, 2017 December 31, 2016 Accounts receivable Services provided to ATC $ 0.9 $ 1.1 Accounts payable Services received from ATC 20.1 20.0 The following table shows activity associated with our related party transactions: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Lease agreements Lease payments to We Power (1) $ 106.7 $ 110.0 $ 211.1 $ 217.4 Construction work in progress billed to We Power 8.9 16.4 25.2 17.7 Transactions with WBS (2) Billings to WBS (3) 60.5 53.1 117.0 109.8 Billings from WBS (4) 52.9 62.2 102.7 225.6 Transactions with WPS (2) Billings to WPS 5.2 1.9 7.7 2.9 Billings from WPS 1.1 0.6 2.2 1.0 Transactions with WG Natural gas purchases from WG 1.3 1.3 2.6 2.7 Services received from WG 5.8 5.6 11.3 10.5 Services provided to WG 16.1 15.8 31.9 29.9 Transactions with UMERC (5) Electric sales to UMERC 6.4 — 14.1 — Billings to UMERC (2) 29.3 — 33.9 — Billings from UMERC (2) 16.1 — 30.5 — Transactions with ATC Charges to ATC for services and construction 2.4 2.4 5.2 4.5 Charges from ATC for network transmission services 60.4 63.3 120.7 126.6 Refund from ATC per FERC ROE order — — (19.4 ) — (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. (2) Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs. (3) Includes $0.9 million , for the transfer of certain benefit-related liabilities from WBS for the six months ended June 30, 2017 . There were no transfers of assets to WBS or liabilities transferred from WBS for the three months ended June 30, 2017 . For the three and six months ended June 30 , 2016, includes $3.2 million and $13.1 million , respectively, for the transfer of certain software assets to WBS. (4) Includes $107.0 million , for the transfer of certain benefit-related liabilities to WBS for the six months ended June 30, 2016 . There were no benefit-related liabilities transferred to WBS for the three and six months ended June 30 , 2017, or for the three months ended June 30, 2016 . (5) UMERC became operational effective January 1, 2017. See below for more information. Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets (including the related deferred income tax liabilities) transferred to UMERC from us was $60.0 million . This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. The Tilden Mining Company will remain a customer of ours until UMERC's proposed generation solution for the Upper Peninsula of Michigan begins commercial operation. UMERC obtains its energy through the MISO Energy Markets and meets its market obligations through power purchase agreements with us and WPS. Parent Company's Acquisition of Natural Gas Storage Facilities in Michigan On June 30, 2017, our parent company completed the acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that will provide for some of our current storage needs for our natural gas utility operations. We plan to enter into a long-term service agreement with Bluewater to take the allocated storage. See Note 15, Regulatory Environment, for more information . |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 6 Months Ended |
Jun. 30, 2017 | |
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 June 30, 2017 , were $9,926.0 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 SO 2 , NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. Air Quality Cross-State Air Pollution Rule In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO 2 that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond. The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015, and issued the final rule in September 2016. We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule. Sulfur Dioxide National Ambient Air Quality Standards The EPA issued a revised 1-Hour SO 2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. We believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant costs to comply with this regulation. 8-Hour Ozone National Ambient Air Quality Standards Sheboygan County and the eastern portion of Kenosha County are currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has updated the 2008 ozone NAAQS attainment plan for Kenosha County and submitted it to the EPA for approval. The plan concluded that Wisconsin will not need to implement any new regulatory measures or programs. The area is forecasted to meet the standard by the 2018 compliance date due to emission control measures already in place. Wisconsin has prepared a draft attainment plan for Sheboygan County, which is out for public comment and is expected to submit a final plan to the EPA for approval this summer. A final EPA action regarding Wisconsin's attainment plan is expected later in 2017. After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan. Although we are still in the process of reviewing and determining potential impacts resulting from this rule, we believe we are well positioned to meet the ozone standard and do not expect to incur significant costs to comply. Climate Change In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan (CPP), a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking. The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39% , respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. The EPA announced that it has initiated this review. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO 2 emissions by approximately 40% below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO 2 reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. 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, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). 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. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for PWGS, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8. During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these plants. With the exception of Pleasant Prairie Power Plant (which has existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. 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 guidelines (ELG) rule took effect in January 2016. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In June 2017, the EPA issued a proposed rule to codify this stay. This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023. After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years . 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. The final rule would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie facilities. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7, OC 8, and the Pleasant Prairie units. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $55 million to $75 million for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See the UMERC discussion in Note 15, Regulatory Environment , regarding the potential retirement of PIPP. 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) June 30, 2017 December 31, 2016 Regulatory assets $ 29.7 $ 29.9 Reserves for future remediation 19.0 19.0 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 | 6 Months Ended |
Jun. 30, 2017 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Six Months Ended June 30 (in millions) 2017 2016 Cash (paid) for interest, net of amount capitalized $ (57.6 ) $ (58.1 ) Cash (paid) received for income taxes, net (63.4 ) 0.6 Significant noncash transactions: Accounts payable related to construction costs 13.0 12.4 Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) 415.4 — Transfer of net assets to UMERC (1) 60.0 — (1) See Note 12, Related Parties, for more information on these transactions. (2) The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 6 Months Ended |
Jun. 30, 2017 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT 2018 and 2019 Rates During April 2017, we, along with WG and WPS, 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 this proposed settlement agreement, we agreed to keep electric and natural gas base rates frozen for our customers through 2019. In addition, we agreed to extend and expand the electric real-time pricing options for large commercial and industrial customers, and we agreed to prevent the continued growth of certain escrowed costs. Deferral of the revenue requirement impacts of any federal corporate tax reform enacted in 2017, or during the rate freeze period, was included in the agreement as well. Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism, which applies only to earnings above our authorized ROE, in place through 2019. In July 2017, the PSCW staff issued a commission memorandum in response to the settlement agreement, and we expect the PSCW to issue a final order on the agreement during the third quarter of 2017. If the PSCW rejects the proposed settlement agreement, we expect we will file a traditional rate proceeding. Natural Gas Storage Facilities in Michigan In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide some of the current storage needs for our natural gas distribution service customers. As a result of this agreement, we, along with WG and WPS, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facilities. We also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. See Note 12, Related Parties, for more information . Formation of Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand - alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan. In August 2016, WEC Energy Group entered into an agreement with the Tilden Mining Company (Tilden), under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years . The agreement also calls for UMERC to construct and operate approximately 180 MWs of natural gas-fired generation located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation. We expect the MPSC to issue final orders on the Tilden agreement and the proposed generation during the fourth quarter of 2017. |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 6 Months Ended |
Jun. 30, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Revenue Recognition In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers. We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods. We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition. Recognition and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We do not believe the adoption of this guidance will have a significant impact on our financial statements. Leases In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements. 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. Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We do not believe the adoption of this guidance will have a significant impact on our financial statements. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. We are currently assessing the effects this guidance may have on our financial statements. |
GENERAL INFORMATION (Policies)
GENERAL INFORMATION (Policies) | 6 Months Ended |
Jun. 30, 2017 | |
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, and statements of cash flows, 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. |
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, 2016 . 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 and six months ended June 30 , 2017 , are not necessarily indicative of expected results for 2017 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. |
Fair Value Measurements | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally developed inputs. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period. |
Derivative Instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as 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 | Revenue Recognition In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers. We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods. We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider our tariff sales, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition. Recognition and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We do not believe the adoption of this guidance will have a significant impact on our financial statements. Leases In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements. 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. Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We do not believe the adoption of this guidance will have a significant impact on our financial statements. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. We are currently assessing the effects this guidance may have on our financial statements. |
COMMON EQUITY (Tables)
COMMON EQUITY (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Retained Earnings | |
Schedule of changes to retained earnings [Line Items] | |
Schedule of changes in retained earnings | The following table shows the changes to our retained earnings for the six months ended June 30, 2017 : (in millions) Retained Earnings Balance at December 31, 2016 $ 2,140.8 Net income 177.7 Common stock dividends (120.0 ) Preferred stock dividends (0.6 ) Cumulative effect of adoption of ASU 2016-09 11.9 Balance at June 30, 2017 $ 2,209.8 |
SHORT-TERM DEBT AND LINES OF 24
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Short-term Debt [Abstract] | |
Short-term borrowings and their corresponding weighted average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) June 30, 2017 December 31, 2016 Commercial paper Amount outstanding $ 75.0 $ 159.0 Weighted-average interest rate on amounts outstanding 1.33 % 0.87 % |
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 June 30, 2017 Revolving credit facility December 2020 $ 500.0 Less: Letters of credit issued inside credit facility $ 26.2 Commercial paper outstanding 75.0 Available capacity under existing agreement $ 398.8 |
MATERIALS, SUPPLIES, AND INVE25
MATERIALS, SUPPLIES, AND INVENTORIES (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Inventory Disclosure [Abstract] | |
Schedule of inventory | Our inventory consisted of: (in millions) June 30, 2017 December 31, 2016 Materials and supplies $ 153.2 $ 148.1 Fossil fuel 100.1 91.1 Natural gas in storage 24.9 31.8 Total $ 278.2 $ 271.0 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
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: June 30, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.3 $ 0.2 $ — $ 0.5 Petroleum products contracts 0.2 — — 0.2 FTRs — — 6.0 6.0 Coal contracts — 0.7 — 0.7 Total derivative assets $ 0.5 $ 0.9 $ 6.0 $ 7.4 Derivative liabilities Natural gas contracts $ 0.7 $ — $ — $ 0.7 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 2.3 — — 2.3 Total derivative liabilities $ 0.8 $ 2.3 $ — $ 3.1 December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.0 $ 0.8 $ — $ 6.8 Petroleum products contracts 0.2 — — 0.2 FTRs — — 3.1 3.1 Coal contracts — 1.9 — 1.9 Total derivative assets $ 6.2 $ 2.7 $ 3.1 $ 12.0 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 0.2 $ 0.5 $ — $ 0.7 |
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 June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Balance at the beginning of the period $ 1.1 $ 0.6 $ 3.1 $ 1.6 Purchases 6.9 8.1 6.9 8.1 Settlements (2.0 ) (1.2 ) (4.0 ) (2.2 ) Balance at the end of the period $ 6.0 $ 7.5 $ 6.0 $ 7.5 |
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: June 30, 2017 December 31, 2016 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 30.5 $ 30.4 $ 28.8 Long-term debt, including current portion 2,661.2 2,939.2 2,661.1 2,923.4 |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative assets and derivative liabilities | The following table shows our derivative assets and derivative liabilities: June 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.5 $ 0.6 $ 6.3 $ 0.1 Petroleum products contracts 0.2 0.1 0.2 0.1 FTRs 6.0 — 3.1 — Coal contracts 0.7 1.5 1.5 0.5 Total other current * $ 7.4 $ 2.2 $ 11.1 $ 0.7 Other long-term Natural gas contracts $ — $ 0.1 $ 0.5 $ — Coal contracts — 0.8 0.4 — Total other long-term * — 0.9 0.9 — Total $ 7.4 $ 3.1 $ 12.0 $ 0.7 * 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 June 30, 2017 Three Months Ended June 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 5.0 Dth $ 0.2 9.6 Dth $ (4.8 ) Petroleum products contracts 4.9 gallons (0.4 ) 2.6 gallons (0.8 ) FTRs 7.3 MWh 2.0 5.7 MWh 0.5 Total $ 1.8 $ (5.1 ) Six Months Ended June 30, 2017 Six Months Ended June 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 13.2 Dth $ 0.7 20.2 Dth $ (12.0 ) Petroleum products contracts 9.8 gallons (0.9 ) 4.2 gallons (1.5 ) FTRs 14.3 MWh 4.5 10.9 MWh 2.3 Total $ 4.3 $ (11.2 ) |
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: June 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 7.4 $ 3.1 $ 12.0 $ 0.7 Gross amount not offset on the balance sheet (0.5 ) (0.7 ) (1) (3.6 ) (2) (0.2 ) Net amount $ 6.9 $ 2.4 $ 8.4 $ 0.5 (1) Includes cash collateral posted of $0.2 million . (2) Includes cash collateral received of $3.4 million . |
EMPLOYEE BENEFITS (Tables)
EMPLOYEE BENEFITS (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of the components of net periodic benefit cost | The following tables show the components of net periodic pension and OPEB costs for our benefit plans: Pension Costs Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Service cost $ 3.1 $ 2.5 $ 6.1 $ 5.2 Interest cost 11.6 12.3 23.5 24.9 Expected return on plan assets (19.1 ) (19.4 ) (38.3 ) (38.8 ) Loss on plan settlement 2.8 — 2.8 — Amortization of prior service cost 0.3 0.4 0.6 0.8 Amortization of net actuarial loss 8.9 8.2 17.7 16.2 Net periodic benefit cost $ 7.6 $ 4.0 $ 12.4 $ 8.3 OPEB Costs Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Service cost $ 1.5 $ 3.5 $ 3.4 $ 3.6 Interest cost 3.1 4.7 6.2 6.6 Expected return on plan assets (3.6 ) (5.8 ) (7.2 ) (7.0 ) Amortization of prior service credit (0.3 ) (0.2 ) (0.6 ) (0.5 ) Amortization of net actuarial (gain) loss (0.3 ) 0.3 — 0.5 Net periodic benefit cost $ 0.4 $ 2.5 $ 1.8 $ 3.2 |
INVESTMENT IN AMERICAN TRANSM29
INVESTMENT IN AMERICAN TRANSMISSION COMPANY (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
ATC | |
Investment in ATC | |
Schedule of changes to our investment in ATC | The following table shows changes to our investment in ATC: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Balance at beginning of period $ — $ 394.3 $ 402.0 $ 382.2 Less: Transfer of ownership interest — — 402.0 — Add: Earnings from equity method investment — 11.4 — 26.1 Add: Capital contributions — 1.1 — 4.6 Less: Distributions — 12.0 — 18.0 Less: Other — — — 0.1 Balance at end of period $ — $ 394.8 $ — $ 394.8 |
SEGMENT INFORMATION (Tables)
SEGMENT INFORMATION (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Segment Reporting [Abstract] | |
Schedule of information related to our reportable segments | The following tables show summarized financial information related to our reportable segments for the three and six months ended June 30 , 2017 and 2016 : (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended June 30, 2017 Operating revenues $ 855.4 $ — $ 855.4 Other operation and maintenance 327.7 — 327.7 Depreciation and amortization 82.7 — 82.7 Operating income 142.8 — 142.8 Interest expense 29.1 — 29.1 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Three Months Ended June 30, 2016 Operating revenues $ 877.2 $ — $ 877.2 Other operation and maintenance 336.2 — 336.2 Depreciation and amortization 80.8 — 80.8 Operating income 146.9 — 146.9 Equity in earnings of transmission affiliate — 11.4 11.4 Interest expense 29.1 0.3 29.4 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Six Months Ended June 30, 2017 Operating revenues $ 1,827.4 $ — $ 1,827.4 Other operation and maintenance 655.5 — 655.5 Depreciation and amortization 164.8 — 164.8 Operating income 327.9 — 327.9 Interest expense 58.4 0.3 58.7 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Six Months Ended June 30, 2016 Operating revenues $ 1,852.7 $ — $ 1,852.7 Other operation and maintenance 684.4 — 684.4 Depreciation and amortization 161.2 — 161.2 Operating income 328.4 — 328.4 Equity in earnings of transmission affiliate — 26.1 26.1 Interest expense 58.0 0.5 58.5 |
RELATED PARTIES (Tables)
RELATED PARTIES (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Related Party Transactions [Abstract] | |
Schedule of related party transactions balance sheet information | Our balance sheets included the following receivables and payables related to transactions entered into with ATC: (in millions) June 30, 2017 December 31, 2016 Accounts receivable Services provided to ATC $ 0.9 $ 1.1 Accounts payable Services received from ATC 20.1 20.0 |
Schedule of activity associated with related party transactions | The following table shows activity associated with our related party transactions: Three Months Ended June 30 Six Months Ended June 30 (in millions) 2017 2016 2017 2016 Lease agreements Lease payments to We Power (1) $ 106.7 $ 110.0 $ 211.1 $ 217.4 Construction work in progress billed to We Power 8.9 16.4 25.2 17.7 Transactions with WBS (2) Billings to WBS (3) 60.5 53.1 117.0 109.8 Billings from WBS (4) 52.9 62.2 102.7 225.6 Transactions with WPS (2) Billings to WPS 5.2 1.9 7.7 2.9 Billings from WPS 1.1 0.6 2.2 1.0 Transactions with WG Natural gas purchases from WG 1.3 1.3 2.6 2.7 Services received from WG 5.8 5.6 11.3 10.5 Services provided to WG 16.1 15.8 31.9 29.9 Transactions with UMERC (5) Electric sales to UMERC 6.4 — 14.1 — Billings to UMERC (2) 29.3 — 33.9 — Billings from UMERC (2) 16.1 — 30.5 — Transactions with ATC Charges to ATC for services and construction 2.4 2.4 5.2 4.5 Charges from ATC for network transmission services 60.4 63.3 120.7 126.6 Refund from ATC per FERC ROE order — — (19.4 ) — (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. (2) Includes amounts billed for services, pass through costs, and other items in accordance with approved AIAs. (3) Includes $0.9 million , for the transfer of certain benefit-related liabilities from WBS for the six months ended June 30, 2017 . There were no transfers of assets to WBS or liabilities transferred from WBS for the three months ended June 30, 2017 . For the three and six months ended June 30 , 2016, includes $3.2 million and $13.1 million , respectively, for the transfer of certain software assets to WBS. (4) Includes $107.0 million , for the transfer of certain benefit-related liabilities to WBS for the six months ended June 30, 2016 . There were no benefit-related liabilities transferred to WBS for the three and six months ended June 30 , 2017, or for the three months ended June 30, 2016 . (5) UMERC became operational effective January 1, 2017. See below for more information. |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
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) June 30, 2017 December 31, 2016 Regulatory assets $ 29.7 $ 29.9 Reserves for future remediation 19.0 19.0 |
SUPPLEMENTAL CASH FLOW INFORM33
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Six Months Ended June 30 (in millions) 2017 2016 Cash (paid) for interest, net of amount capitalized $ (57.6 ) $ (58.1 ) Cash (paid) received for income taxes, net (63.4 ) 0.6 Significant noncash transactions: Accounts payable related to construction costs 13.0 12.4 Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) 415.4 — Transfer of net assets to UMERC (1) 60.0 — (1) See Note 12, Related Parties, for more information on these transactions. (2) The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. |
GENERAL INFORMATION (Details)
GENERAL INFORMATION (Details) | Dec. 31, 2016 |
ATC | |
Investment in ATC | |
Ownership interest in ATC (as a percent) | 23.00% |
DISPOSITIONS (Details)
DISPOSITIONS (Details) - Utility $ in Millions | 3 Months Ended |
Jun. 30, 2016USD ($) | |
Dispositions | |
After-tax gain on sale | $ 6.5 |
Other operation and maintenance | |
Dispositions | |
Pre-tax gain on sale | $ 10.9 |
COMMON EQUITY (Details)
COMMON EQUITY (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Changes in retained earnings [Roll Forward] | ||||
Balance at December 31, 2016 | $ 2,140.8 | |||
Net income | $ 75.6 | $ 82.9 | 177.7 | $ 190.5 |
Common stock dividends | (120) | |||
Preferred stock dividends | (0.3) | $ (0.3) | (0.6) | $ (0.6) |
Cumulative effect of adoption of ASU 2016-09 | 11.9 | 11.9 | ||
Balance at June 30, 2017 | $ 2,209.8 | 2,209.8 | ||
Other impacts from adoption of ASU 2016-09 | $ 0 |
SHORT-TERM DEBT AND LINES OF 37
SHORT-TERM DEBT AND LINES OF CREDIT (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Short-term borrowings | ||
Commercial paper | $ 75 | $ 159 |
Commercial paper | ||
Short-term borrowings | ||
Weighted-average interest rate on amounts outstanding | 1.33% | 0.87% |
Average amounts outstanding during the period | $ 36.4 | |
Weighted-average interest rate during the period | 0.97% |
SHORT-TERM DEBT AND LINES OF 38
SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Line of Credit Facility | ||
Letters of credit issued inside credit facility | $ 26.2 | |
Commercial paper | 75 | $ 159 |
Available capacity under existing agreement | 398.8 | |
Credit facility maturing December 2020 | ||
Line of Credit Facility | ||
Revolving credit facility | $ 500 |
MATERIALS, SUPPLIES, AND INVE39
MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Inventory Disclosure [Abstract] | ||
Materials and supplies | $ 153.2 | $ 148.1 |
Fossil fuel | 100.1 | 91.1 |
Natural gas in storage | 24.9 | 31.8 |
Total | $ 278.2 | $ 271 |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Assets | ||
Derivative asset | $ 7.4 | $ 12 |
Liabilities | ||
Derivative liability | 3.1 | 0.7 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative asset | 7.4 | 12 |
Liabilities | ||
Derivative liability | 3.1 | 0.7 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 0.5 | 6.2 |
Liabilities | ||
Derivative liability | 0.8 | 0.2 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 0.9 | 2.7 |
Liabilities | ||
Derivative liability | 2.3 | 0.5 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 6 | 3.1 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative asset | 0.5 | 6.8 |
Liabilities | ||
Derivative liability | 0.7 | 0.1 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative asset | 0.3 | 6 |
Liabilities | ||
Derivative liability | 0.7 | 0.1 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative asset | 0.2 | 0.8 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Petroleum products contracts | ||
Assets | ||
Derivative asset | 0.2 | 0.2 |
Liabilities | ||
Derivative liability | 0.1 | 0.1 |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1 | ||
Assets | ||
Derivative asset | 0.2 | 0.2 |
Liabilities | ||
Derivative liability | 0.1 | 0.1 |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | ||
Assets | ||
Derivative asset | 6 | 3.1 |
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 | 6 | 3.1 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative asset | 0.7 | 1.9 |
Liabilities | ||
Derivative liability | 2.3 | 0.5 |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative asset | 0.7 | 1.9 |
Liabilities | ||
Derivative liability | 2.3 | 0.5 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - LEVEL
FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Level 3 rollforward | ||||
Balance at the beginning of the period | $ 1.1 | $ 0.6 | $ 3.1 | $ 1.6 |
Purchases | 6.9 | 8.1 | 6.9 | 8.1 |
Settlements | (2) | (1.2) | (4) | (2.2) |
Balance at the end of the period | $ 6 | $ 7.5 | $ 6 | $ 7.5 |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
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 | 2,661.2 | 2,661.1 |
Fair Value | ||
Carrying value and estimated fair value of financial instruments | ||
Preferred stock | 30.5 | 28.8 |
Long-term debt | $ 2,939.2 | $ 2,923.4 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND DERIVATIVE LIABILITIES (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Derivative Asset | ||
Other current derivative assets | $ 7.4 | $ 11.1 |
Other long-term derivative assets | 0 | 0.9 |
Derivative asset | 7.4 | 12 |
Derivative Liability | ||
Other current derivative liabilities | 2.2 | 0.7 |
Other long-term derivative liabilities | 0.9 | 0 |
Derivative liability | 3.1 | 0.7 |
Natural gas contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.5 | 6.3 |
Other long-term derivative assets | 0 | 0.5 |
Derivative Liability | ||
Other current derivative liabilities | 0.6 | 0.1 |
Other long-term derivative liabilities | 0.1 | 0 |
Petroleum products contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.2 | 0.2 |
Derivative Liability | ||
Other current derivative liabilities | 0.1 | 0.1 |
FTRs | ||
Derivative Asset | ||
Other current derivative assets | 6 | 3.1 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.7 | 1.5 |
Other long-term derivative assets | 0 | 0.4 |
Derivative Liability | ||
Other current derivative liabilities | 1.5 | 0.5 |
Other long-term derivative liabilities | $ 0.8 | $ 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 | 6 Months Ended | ||
Jun. 30, 2017USD ($)MMBTUMWhgal | Jun. 30, 2016USD ($)MMBTUMWhgal | Jun. 30, 2017USD ($)MMBTUMWhgal | Jun. 30, 2016USD ($)MMBTUMWhgal | |
Realized Gain (Loss) on Derivatives | ||||
Gains (Losses) | $ 1.8 | $ (5.1) | $ 4.3 | $ (11.2) |
Natural gas contracts | ||||
Realized Gain (Loss) on Derivatives | ||||
Gains (Losses) | $ 0.2 | $ (4.8) | $ 0.7 | $ (12) |
Notional Sales Volumes | ||||
Notional sales volumes | MMBTU | 5 | 9.6 | 13.2 | 20.2 |
Petroleum products contracts | ||||
Realized Gain (Loss) on Derivatives | ||||
Gains (Losses) | $ (0.4) | $ (0.8) | $ (0.9) | $ (1.5) |
Notional Sales Volumes | ||||
Notional sales volumes (gallons) | gal | 4.9 | 2.6 | 9.8 | 4.2 |
FTRs | ||||
Realized Gain (Loss) on Derivatives | ||||
Gains (Losses) | $ 2 | $ 0.5 | $ 4.5 | $ 2.3 |
Notional Sales Volumes | ||||
Notional sales volumes | MWh | 7.3 | 5.7 | 14.3 | 10.9 |
DERIVATIVE INSTRUMENTS - OFFSET
DERIVATIVE INSTRUMENTS - OFFSETTING TABLE (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Cash collateral | ||
Collateral in margin account | $ 2.3 | |
Cash collateral received | $ 3.4 | |
Offsetting Derivative Assets | ||
Gross amount recognized on the balance sheet | 7.4 | 12 |
Gross amount not offset on the balance sheet | (0.5) | (3.6) |
Net amount | 6.9 | 8.4 |
Collateral received | 3.4 | |
Offsetting Derivative Liabilities | ||
Gross amount recognized on the balance sheet | 3.1 | 0.7 |
Gross amount not offset on the balance sheet | (0.7) | (0.2) |
Net amount | 2.4 | $ 0.5 |
Collateral posted | $ 0.2 |
EMPLOYEE BENEFITS (Details)
EMPLOYEE BENEFITS (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Components of net periodic benefit costs | ||||
Contributions and payments related to pension and OPEB plans | $ 5.6 | $ 4.6 | ||
Pension Costs | ||||
Components of net periodic benefit costs | ||||
Service cost | $ 3.1 | $ 2.5 | 6.1 | 5.2 |
Interest cost | 11.6 | 12.3 | 23.5 | 24.9 |
Expected return on plan assets | (19.1) | (19.4) | (38.3) | (38.8) |
Loss on plan settlement | 2.8 | 0 | 2.8 | 0 |
Amortization of prior service cost (credit) | 0.3 | 0.4 | 0.6 | 0.8 |
Amortization of net actuarial loss | 8.9 | 8.2 | 17.7 | 16.2 |
Net periodic benefit cost | 7.6 | 4 | 12.4 | 8.3 |
Contributions and payments related to pension and OPEB plans | 4.3 | |||
Estimated future employer contributions for the remainder of the year | 0.9 | |||
Other Postretirement Benefit Costs | ||||
Components of net periodic benefit costs | ||||
Service cost | 1.5 | 3.5 | 3.4 | 3.6 |
Interest cost | 3.1 | 4.7 | 6.2 | 6.6 |
Expected return on plan assets | (3.6) | (5.8) | (7.2) | (7) |
Amortization of prior service cost (credit) | (0.3) | (0.2) | (0.6) | (0.5) |
Amortization of net actuarial loss | (0.3) | 0.3 | 0 | 0.5 |
Net periodic benefit cost | $ 0.4 | $ 2.5 | 1.8 | $ 3.2 |
Contributions and payments related to pension and OPEB plans | 1.3 | |||
Estimated future employer contributions for the remainder of the year | $ 3.2 |
INVESTMENT IN AMERICAN TRANSM47
INVESTMENT IN AMERICAN TRANSMISSION COMPANY - CHANGES TO INVESTMENT (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Changes to investment in ATC | |||||
Investment in ATC, balance at beginning of period | $ 402 | ||||
Add: Earnings from equity method investment | $ 0 | $ 11.4 | 0 | $ 26.1 | |
Add: Capital contributions | 0 | 4.6 | |||
Investment in ATC, balance at end of period | 0 | 0 | |||
ATC | |||||
Investment in ATC | |||||
Ownership interest in ATC (as a percent) | 23.00% | ||||
Changes to investment in ATC | |||||
Investment in ATC, balance at beginning of period | 0 | 394.3 | 402 | 382.2 | |
Less: Transfer of ownership interest | 0 | 0 | 402 | 0 | |
Add: Earnings from equity method investment | 0 | 11.4 | 0 | 26.1 | |
Add: Capital contributions | 0 | 1.1 | 0 | 4.6 | |
Less: Distributions | 0 | 12 | 0 | 18 | |
Less: Other | 0 | 0 | 0 | 0.1 | |
Investment in ATC, balance at end of period | $ 0 | $ 394.8 | $ 0 | $ 394.8 |
SEGMENT INFORMATION (Details)
SEGMENT INFORMATION (Details) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2017USD ($)areasegment | Jun. 30, 2016USD ($) | Dec. 31, 2016 | |
Segment information | |||||
Number of reportable segments | segment | 2 | ||||
Operating revenues | $ 855.4 | $ 877.2 | $ 1,827.4 | $ 1,852.7 | |
Other operation and maintenance | 327.7 | 336.2 | 655.5 | 684.4 | |
Depreciation and amortization | 82.7 | 80.8 | 164.8 | 161.2 | |
Operating income | 142.8 | 146.9 | 327.9 | 328.4 | |
Equity in earnings of transmission affiliate | 0 | 11.4 | 0 | 26.1 | |
Interest expense | 29.1 | 29.4 | $ 58.7 | 58.5 | |
Utility | |||||
Segment information | |||||
Number of service areas within the natural gas service area | area | 3 | ||||
Operating revenues | 855.4 | 877.2 | $ 1,827.4 | 1,852.7 | |
Other operation and maintenance | 327.7 | 336.2 | 655.5 | 684.4 | |
Depreciation and amortization | 82.7 | 80.8 | 164.8 | 161.2 | |
Operating income | 142.8 | 146.9 | 327.9 | 328.4 | |
Equity in earnings of transmission affiliate | 0 | 0 | |||
Interest expense | 29.1 | 29.1 | 58.4 | 58 | |
Other | |||||
Segment information | |||||
Operating revenues | 0 | 0 | 0 | 0 | |
Other operation and maintenance | 0 | 0 | 0 | 0 | |
Depreciation and amortization | 0 | 0 | 0 | 0 | |
Operating income | 0 | 0 | 0 | 0 | |
Equity in earnings of transmission affiliate | 11.4 | 26.1 | |||
Interest expense | 0 | 0.3 | 0.3 | 0.5 | |
ATC | |||||
Segment information | |||||
Ownership interest in ATC (as a percent) | 23.00% | ||||
Equity in earnings of transmission affiliate | $ 0 | $ 11.4 | $ 0 | $ 26.1 |
VARIABLE INTEREST ENTITIES (Det
VARIABLE INTEREST ENTITIES (Details) $ in Millions | 6 Months Ended | ||
Jun. 30, 2017USD ($)MW | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($) | |
Variable interest entities | |||
Equity investment in ATC | $ 0 | $ 402 | |
ATC | |||
Variable interest entities | |||
Ownership interest in ATC (as a percent) | 23.00% | ||
Equity investment in ATC | $ 402 | ||
ATC distributions receivable | 13.4 | ||
Accounts payable due to ATC | $ 20 | ||
Purchased power agreement | |||
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) | 5 years | ||
Residual guarantee associated with purchased power agreement | $ 0 | ||
Required payments over remaining term of purchased power agreement | 78.4 | ||
Total capacity and lease payments | $ 9 | $ 26.9 |
RELATED PARTIES (Details)
RELATED PARTIES (Details) - USD ($) $ in Millions | 3 Months Ended | |||
Mar. 31, 2017 | Jun. 30, 2017 | Apr. 30, 2017 | Dec. 31, 2016 | |
Related parties | ||||
Subsidiary note payable to WEC Energy Group | $ 0 | $ 18.5 | ||
Wispark LLC | ||||
Related parties | ||||
Notes receivable, from buyer | $ 7 | |||
Bostco | Wispark LLC | ||||
Related parties | ||||
Accounts receivable, related parties, current | $ 7 | |||
ATC | ||||
Related parties | ||||
Accounts receivable, related parties, current | 0.9 | 1.1 | ||
Transfer equity method investment and related receivable for distributions transfer to affiliated company | 415.4 | |||
Transfer of deferred income tax related to ATC to affiliated company | $ 195.1 | |||
Accounts payable, related parties, current | $ 20.1 | $ 20 |
RELATED PARTIES - OTHER TRANSAC
RELATED PARTIES - OTHER TRANSACTIONS (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Related parties | |||||
Proceeds from (payments for) liabilities transferred from (to) WBS | $ 0.9 | $ (107) | |||
Proceeds received from the transfer of certain software to WBS | 0 | 13.1 | |||
We Power LLC | |||||
Related parties | |||||
Lease payments to W.E. Power, LLC | $ 106.7 | $ 110 | 211.1 | 217.4 | |
Construction work In progress billed to related party | 8.9 | 16.4 | 25.2 | 17.7 | |
WBS | |||||
Related parties | |||||
Charges to related party for services and billings | 60.5 | 53.1 | 117 | 109.8 | |
Charges from related party for services and billings | 52.9 | 62.2 | 102.7 | 225.6 | |
Proceeds from (payments for) liabilities transferred from (to) WBS | 0 | 0 | 0.9 | (107) | |
Proceeds received from the transfer of certain software to WBS | 0 | 3.2 | 13.1 | ||
WPS | |||||
Related parties | |||||
Charges to related party for services and billings | 5.2 | 1.9 | 7.7 | 2.9 | |
Charges from related party for services and billings | 1.1 | 0.6 | 2.2 | 1 | |
WG | |||||
Related parties | |||||
Charges to related party for services and billings | 16.1 | 15.8 | 31.9 | 29.9 | |
Charges from related party for services and billings | 5.8 | 5.6 | 11.3 | 10.5 | |
Natural gas purchases from Wisconsin Gas LLC | 1.3 | 1.3 | 2.6 | 2.7 | |
UMERC | |||||
Related parties | |||||
Charges to related party for services and billings | 29.3 | 0 | 33.9 | 0 | |
Charges from related party for services and billings | 16.1 | 0 | 30.5 | 0 | |
Electric sales to UMERC | 6.4 | 0 | 14.1 | 0 | |
ATC | |||||
Related parties | |||||
Charges to related party for services and billings | 2.4 | 2.4 | 5.2 | 4.5 | |
Charges from related party for services and billings | 60.4 | 63.3 | 120.7 | 126.6 | |
Refund from ATC per FERC ROE order | $ 0 | $ 0 | $ (19.4) | $ 0 | |
Natural gas storage facilities in Michigan | |||||
Related parties | |||||
Purchase price | $ 226 |
RELATED PARTIES - UMERC (Detail
RELATED PARTIES - UMERC (Details) - UMERC transfer $ in Millions | 6 Months Ended | ||
Jun. 30, 2017USD ($) | Jun. 30, 2016USD ($) | Jan. 01, 2017customermile | |
Related parties | |||
Miles of electric distribution lines | mile | 2,500 | ||
Book value of net assets transferred (including the related deferred income tax liabilities) | $ | $ 60 | $ 0 | |
Utility segment | |||
Related parties | |||
Number of customers | 27,500 | ||
Electric distribution | |||
Related parties | |||
Number of customers | 50 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Jun. 30, 2017USD ($) |
Minimum future commitments for purchase obligations | |
Purchase obligations | $ 9,926 |
COMMITMENTS AND CONTINGENCIES54
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | ||
Oct. 31, 2014 | Jun. 30, 2017USD ($) | Dec. 31, 2015 | Dec. 31, 2016USD ($) | Sep. 30, 2016 | |
Climate Change | Electric | |||||
Air quality | |||||
Number of legal cases heard by a court | 1 | ||||
Percentage of nationwide greenhouse gas emissions reduction | 32.00% | ||||
Interim goal for greenhouse gas emissions reduction (fraction) | 0.667 | ||||
Company goal for percentage of carbon dioxide emissions reduction | 40.00% | ||||
Climate Change | Electric | Wisconsin | |||||
Air quality | |||||
Percentage of greenhouse gas emissions reduction by state | 41.00% | ||||
Climate Change | Electric | Michigan | |||||
Air quality | |||||
Percentage of greenhouse gas emissions reduction by state | 39.00% | ||||
Clean Water Act Cooling Water Intake Structure Rule | Electric | |||||
Water quality | |||||
Number of compliance options available to meet standard | 7 | ||||
Steam Electric Effluent Limitation Guidelines | Electric | |||||
Water quality | |||||
Renewal period for facility permits | 5 years | ||||
Steam Electric Effluent Limitation Guidelines | Minimum | Electric | |||||
Water quality | |||||
Expected costs to achieve required emissions reduction | $ 55 | ||||
Steam Electric Effluent Limitation Guidelines | Maximum | Electric | |||||
Water quality | |||||
Expected costs to achieve required emissions reduction | 75 | ||||
Manufactured Gas Plant Remediation | Natural gas | |||||
Manufactured gas plant remediation | |||||
Regulatory assets recorded for remediation of manufactured gas plant sites | 29.7 | $ 29.9 | |||
Reserves recorded for remediation of manufactured gas plant sites | $ 19 | $ 19 |
SUPPLEMENTAL CASH FLOW INFORM55
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Supplemental cash flow information | |||
Cash (paid) for interest, net of amount capitalized | $ (57.6) | $ (58.1) | |
Cash (paid) received for income taxes, net | (63.4) | 0.6 | |
Significant noncash transactions | |||
Accounts payable related to construction costs | 13 | 12.4 | |
Transfer of investment in ATC | |||
Related parties | |||
Equity method investment transfer to affiliated company | 415.4 | 0 | |
Dividends not received transfered to affiliate | $ 13.4 | ||
UMERC transfer | |||
Related parties | |||
Transfer of net assets to UMERC | $ 60 | $ 0 |
REGULATORY ENVIRONMENT (Details
REGULATORY ENVIRONMENT (Details) - UMERC | 1 Months Ended |
Aug. 31, 2016MW | |
Regulatory environment | |
Term of electric power purchase agreement (in years) | 20 years |
Capacity of natural gas-fired generation facility (in megawatts) | 180 |