DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION | 9 Months Ended |
Sep. 30, 2017shares | |
Document and Entity Information [Abstract] | |
Entity Registrant Name | WEC Energy Group, Inc. |
Entity Central Index Key | 783,325 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Large Accelerated Filer |
Document Type | 10-Q |
Document Period End Date | Sep. 30, 2017 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | Q3 |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 315,575,562 |
CONDENSED CONSOLIDATED INCOME S
CONDENSED CONSOLIDATED INCOME STATEMENTS - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Income Statement [Abstract] | ||||
Operating revenues | $ 1,657.5 | $ 1,712.5 | $ 5,593.5 | $ 5,509.3 |
Operating expenses | ||||
Cost of sales | 542.7 | 554.7 | 2,025.6 | 1,901.9 |
Other operation and maintenance | 471.7 | 517.5 | 1,453.4 | 1,571 |
Depreciation and amortization | 201.2 | 191.6 | 593.5 | 569.5 |
Property and revenue taxes | 48.3 | 49.7 | 147.9 | 146.5 |
Total operating expenses | 1,263.9 | 1,313.5 | 4,220.4 | 4,188.9 |
Operating income | 393.6 | 399 | 1,373.1 | 1,320.4 |
Equity in earnings of transmission affiliate | 39.2 | 38.3 | 122.9 | 107.7 |
Other income, net | 16.4 | 7.5 | 45.2 | 72.6 |
Interest expense | 103.8 | 99.1 | 310.4 | 300.1 |
Other expense | (48.2) | (53.3) | (142.3) | (119.8) |
Income before income taxes | 345.4 | 345.7 | 1,230.8 | 1,200.6 |
Income tax expense | 129.7 | 128.4 | 458.8 | 455.1 |
Net income | 215.7 | 217.3 | 772 | 745.5 |
Preferred stock dividends of subsidiary | 0.3 | 0.3 | 0.9 | 0.9 |
Net income attributed to common shareholders | $ 215.4 | $ 217 | $ 771.1 | $ 744.6 |
Earnings per share | ||||
Basic (in dollars per share) | $ 0.68 | $ 0.69 | $ 2.44 | $ 2.36 |
Diluted (in dollars per share) | $ 0.68 | $ 0.68 | $ 2.43 | $ 2.35 |
Weighted average common shares outstanding | ||||
Basic (in shares) | 315.6 | 315.6 | 315.6 | 315.6 |
Diluted (in shares) | 317.5 | 316.9 | 317.5 | 317 |
Dividends per share of common stock (in dollars per share) | $ 0.520 | $ 0.495 | $ 1.560 | $ 1.485 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Statement of Other Comprehensive Income [Abstract] | ||||
Net income | $ 215.7 | $ 217.3 | $ 772 | $ 745.5 |
Derivatives accounted for as cash flow hedges | ||||
Reclassification of gains to net income, net of tax | (0.4) | (0.3) | (1) | (0.9) |
Defined benefit plans | ||||
Amortization of pension and OPEB costs (credits) included in net periodic benefit cost, net of tax | 0.3 | (0.4) | 0.5 | 0 |
Other comprehensive loss, net of tax | (0.1) | (0.7) | (0.5) | (0.9) |
Comprehensive income | 215.6 | 216.6 | 771.5 | 744.6 |
Preferred stock dividends of subsidiary | 0.3 | 0.3 | 0.9 | 0.9 |
Comprehensive income attributed to common shareholders | $ 215.3 | $ 216.3 | $ 770.6 | $ 743.7 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash and cash equivalents | $ 18.1 | $ 37.5 |
Accounts receivable and unbilled revenues, net of reserves of $112.7 and $108.0, respectively | 948 | 1,241.7 |
Materials, supplies, and inventories | 672.2 | 587.6 |
Prepayments | 142 | 204.4 |
Other | 43 | 97.5 |
Current assets | 1,823.3 | 2,168.7 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation of $8,525.5 and $8,214.6, respectively | 20,882.9 | 19,915.5 |
Regulatory assets | 3,107.7 | 3,087.9 |
Equity investment in transmission affiliate | 1,560.8 | 1,443.9 |
Goodwill | 3,053.5 | 3,046.2 |
Other | 584.8 | 461 |
Long-term assets | 29,189.7 | 27,954.5 |
Total assets | 31,013 | 30,123.2 |
Current liabilities | ||
Short-term debt | 993.5 | 860.2 |
Current portion of long-term debt | 709.3 | 157.2 |
Accounts payable | 743.9 | 861.5 |
Accrued payroll and benefits | 136.8 | 163.8 |
Other | 442.6 | 388.9 |
Current liabilities | 3,026.1 | 2,431.6 |
Long-term liabilities | ||
Long-term debt | 8,785.8 | 9,158.2 |
Deferred income taxes | 5,616 | 5,146.6 |
Deferred revenue, net | 549.2 | 566.2 |
Regulatory liabilities | 1,534.9 | 1,563.8 |
Environmental remediation liabilities | 617.7 | 633.6 |
Pension and OPEB obligations | 463.2 | 498.6 |
Other | 1,194.4 | 1,164.4 |
Long-term liabilities | 18,761.2 | 18,731.4 |
Commitments and contingencies (Note 17) | ||
Common shareholders' equity | ||
Common stock – $0.01 par value; 325,000,000 shares authorized; 315,575,562 and 315,614,941 shares outstanding, respectively | 3.2 | 3.2 |
Additional paid in capital | 4,281.4 | 4,309.8 |
Retained earnings | 4,908.3 | 4,613.9 |
Accumulated other comprehensive income | 2.4 | 2.9 |
Common shareholders' equity | 9,195.3 | 8,929.8 |
Preferred stock of subsidiary | 30.4 | 30.4 |
Total liabilities and equity | $ 31,013 | $ 30,123.2 |
CONDENSED CONSOLIDATED BALANCE5
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and accrued unbilled revenues, reserves | $ 112.7 | $ 108 |
Property, plant, and equipment, accumulated depreciation | $ 8,525.5 | $ 8,214.6 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 325,000,000 | 325,000,000 |
Common stock, shares outstanding | 315,575,562 | 315,614,941 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2017 | Sep. 30, 2016 | |
Operating Activities | ||
Net income | $ 772 | $ 745.5 |
Reconciliation to cash provided by operating activities | ||
Depreciation and amortization | 593.5 | 581.5 |
Deferred income taxes and investment tax credits, net | 444.4 | 439.5 |
Contributions and payments related to pension and OPEB plans | (115.4) | (23.5) |
Equity income in transmission affiliate, net of distributions | (18.5) | (35.8) |
Change in - | ||
Accounts receivable and unbilled revenues | 310.5 | 185.2 |
Materials, supplies, and inventories | (84.1) | 33.8 |
Other current assets | 57.9 | 88.5 |
Accounts payable | (111.2) | (94.7) |
Other current liabilities | 23.4 | (92.9) |
Other, net | (125.8) | (105.2) |
Net cash provided by operating activities | 1,746.7 | 1,721.9 |
Investing Activities | ||
Capital expenditures | (1,309.2) | (1,000.1) |
Acquisition of Bluewater | (226) | 0 |
Capital contributions to transmission affiliate | (63.3) | (27.1) |
Proceeds from the sale of assets and businesses | 22.7 | 161.2 |
Withdrawal of restricted cash from rabbi trust for qualifying payments | 18.7 | 23.8 |
Other, net | 5.1 | 0.6 |
Net cash used in investing activities | (1,552) | (841.6) |
Financing Activities | ||
Exercise of stock options | 25.6 | 40.4 |
Purchase of common stock | (60.6) | (105.6) |
Dividends paid on common stock | (492.4) | (468.6) |
Issuance of long-term debt | 210 | 200 |
Retirement of long-term debt | (26.9) | (253.5) |
Change in short-term debt | 133.3 | (305.6) |
Other, net | (3.1) | (12.2) |
Net cash used in financing activities | (214.1) | (905.1) |
Net change in cash and cash equivalents | (19.4) | (24.8) |
Cash and cash equivalents at beginning of period | 37.5 | 49.8 |
Cash and cash equivalents at end of period | $ 18.1 | $ 25 |
GENERAL INFORMATION
GENERAL INFORMATION | 9 Months Ended |
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL INFORMATION | GENERAL INFORMATION WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and owns approximately 60% of ATC. As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, 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 WEC Energy Group and all of its subsidiaries. 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 nine months ended September 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. |
ACQUISITIONS
ACQUISITIONS | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
ACQUISITION | ACQUISITIONS Acquisition of a Wind Energy Generation Facility in Wisconsin In October 2017, WPS, along with two other utilities, entered into an agreement to purchase the Forward Wind Energy Center, which consists of 86 wind turbines located in Wisconsin with a total capacity of 129 MWs. The aggregate purchase price is approximately $174 million of which WPS’s proportionate share is 44.6% , or approximately $78 million . WPS currently purchases 44.6% of the facility’s energy output under a power purchase agreement. The transaction is subject to PSCW and FERC approvals and is expected to close in the spring of 2018. Acquisition of Natural Gas Storage Facilities in Michigan On June 30, 2017, we completed the acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that will provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we incurred $4.9 million of acquisition related costs. The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy infrastructure segment. See Note 15, Segment Information, for more information . (in millions) Current assets $ 2.0 Net property, plant, and equipment 217.6 Goodwill 7.3 Current liabilities (0.9 ) Total purchase price $ 226.0 |
DISPOSITIONS
DISPOSITIONS | 9 Months Ended |
Sep. 30, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
DISPOSITIONS | DISPOSITIONS Wisconsin 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. Corporate and 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. Sale of Certain Assets of Wisvest In April 2016, as part of the MCPP sale transaction, we sold the chilled water generation and distribution assets of Wisvest, which were used to provide chilled water services 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 $19.6 million ( $11.8 million after tax), 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. Sale of Integrys Transportation Fuels Through a series of transactions in the fourth quarter of 2015 and the first quarter of 2016, we sold ITF, a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation, and maintenance. There was no gain or loss recorded on the sales, as ITF's assets and liabilities were adjusted to fair value through purchase accounting and presented as held for sale through the sale date. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. The pre-tax profit or loss of this component was not material through the sale date in 2016. |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT | 9 Months Ended |
Sep. 30, 2017 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT, AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT Presque Isle Power Plant In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MWs of natural gas-fired generation in the Upper Peninsula of Michigan. Upon receiving this approval, early retirement of the PIPP generating units became probable. The new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. The net book value of these units was $203.0 million at September 30, 2017. These units are currently included in rate base, and WE continues to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. The net book value of these assets was transferred from plant in service to plant to be retired. See Note 19, Regulatory Environment, for more information regarding UMERC’s application. Edgewater As a result of the continued implementation of the Consent Decree related to the jointly owned Columbia and Edgewater plants, early retirement of the Edgewater 4 generating unit was probable at September 30, 2017. The net book value of our ownership share of this generating unit was $13.3 million at September 30, 2017. This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. This unit is currently included in rate base, and WPS continues to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. See Note 17, Commitments and Contingencies, for more information regarding the Consent Decree. |
COMMON EQUITY
COMMON EQUITY | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation During the first quarter of 2017, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees: Award Type Number of Awards Stock options (1) 552,215 Restricted shares (2) 82,622 Performance units 237,650 (1) Stock options awarded had a weighted-average exercise price of $58.31 and a weighted-average grant date fair value of $7.45 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $58.10 per share. 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 excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a $15.7 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 nine months ended September 30, 2017 : (in millions) Retained Earnings Balance at December 31, 2016 $ 4,613.9 Net income attributed to common shareholders 771.1 Common stock dividends (492.4 ) Cumulative effect of adoption of ASU 2016-09 15.7 Balance at September 30, 2017 $ 4,908.3 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 potential future forfeitures and recording them over the vesting period. Restrictions Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, 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. Common Stock Dividends On October 19, 2017, our Board of Directors declared a quarterly cash dividend of $0.52 per share, payable on December 1, 2017, to stockholders of record on November 14, 2017. |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 9 Months Ended |
Sep. 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) September 30, 2017 December 31, 2016 Commercial paper Amount outstanding $ 993.5 $ 860.2 Weighted-average interest rate on amounts outstanding 1.38 % 0.96 % Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2017 , was $705.0 million with a weighted-average interest rate during the period of 1.21% . The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these facilities: (in millions) Maturity September 30, 2017 WEC Energy Group (1) December 2020 $ 1,050.0 WE (2) December 2020 500.0 WPS (3) December 2020 250.0 WG (2) December 2020 350.0 PGL (2) December 2020 350.0 Total short-term credit capacity $ 2,500.0 Less: Letters of credit issued inside credit facilities $ 32.9 Commercial paper outstanding 993.5 Available capacity under existing agreements $ 1,473.6 (1) In October 2017, WEC Energy Group increased its credit facility to $1,200.0 million , and extended the maturity to October 2022. (2) In October 2017, WE, WG, and PGL extended the maturities of their credit facilities to October 2022. (3) In October 2017, WPS increased its credit facility to $400.0 million . WPS intends to request approval from the PSCW to extend the maturity of its facility to October 2022. |
LONG TERM DEBT
LONG TERM DEBT | 9 Months Ended |
Sep. 30, 2017 | |
Long-term Debt, Unclassified [Abstract] | |
Long Term Debt | LONG-TERM DEBT Effective May 2017, the $500.0 million of 2007 Junior Notes bear interest at the three-month LIBOR plus 211.25 basis points, and reset quarterly. In June 2017, MERC issued $120.0 million of senior notes. The senior notes were issued in three tranches: $40.0 million of 3.11% Senior Notes due July 15, 2027; $40.0 million of 3.41% Senior Notes due July 15, 2032; and $40.0 million of 4.01% Senior Notes due July 15, 2047. Net proceeds were used to repay MERC's $78.0 million aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were used for general corporate purposes, including repayment of short-term debt borrowed from Integrys. In June 2017, MGU issued $90.0 million of senior notes. The senior notes were issued in three tranches: $30.0 million of 3.11% Senior Notes due July 15, 2027; $30.0 million of 3.41% Senior Notes due July 15, 2032; and $30.0 million of 4.01% Senior Notes due July 15, 2047. Net proceeds were used to repay MGU's $71.0 million aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were used for general corporate purposes, including repayment of short-term debt borrowed from Integrys. |
MATERIALS, SUPPLIES, AND INVENT
MATERIALS, SUPPLIES, AND INVENTORIES | 9 Months Ended |
Sep. 30, 2017 | |
Inventory Disclosure [Abstract] | |
MATERIALS, SUPPLIES, AND INVENTORIES | MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) September 30, 2017 December 31, 2016 Natural gas in storage $ 301.5 $ 223.1 Materials and supplies 225.1 206.5 Fossil fuel 145.6 158.0 Total $ 672.2 $ 587.6 PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced using the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. At September 30, 2017, all LIFO layers were replenished, and the LIFO liquidation balance was zero . Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 9 Months Ended |
Sep. 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 financial 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: September 30, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 2.8 $ 3.7 $ — $ 6.5 Petroleum products contracts 1.0 — — 1.0 FTRs — — 7.3 7.3 Coal contracts — 0.9 — 0.9 Total derivative assets $ 3.8 $ 4.6 $ 7.3 $ 15.7 Investments held in rabbi trust $ 113.5 $ — $ — $ 113.5 Derivative liabilities Natural gas contracts $ 1.5 $ 2.5 $ — $ 4.0 Coal contracts — 2.1 — 2.1 Total derivative liabilities $ 1.5 $ 4.6 $ — $ 6.1 December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 10.1 $ 24.2 $ — $ 34.3 Petroleum products contracts 0.2 — — 0.2 FTRs — — 5.1 5.1 Coal contracts — 2.0 — 2.0 Total derivative assets $ 10.3 $ 26.2 $ 5.1 $ 41.6 Investments held in rabbi trust $ 103.9 $ — $ — $ 103.9 Derivative liabilities Natural gas contracts $ 0.2 $ 0.2 $ — $ 0.4 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 1.9 — 1.9 Total derivative liabilities $ 0.3 $ 2.1 $ — $ 2.4 The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. 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 September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Balance at the beginning of the period $ 11.8 $ 13.4 $ 5.1 $ 3.6 Realized and unrealized losses — — — (0.2 ) Purchases — — 13.8 15.2 Sales — — — (0.2 ) Settlements (4.5 ) (4.2 ) (11.6 ) (9.2 ) Balance at the end of the period $ 7.3 $ 9.2 $ 7.3 $ 9.2 Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the income statements. Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: September 30, 2017 December 31, 2016 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 29.6 $ 30.4 $ 28.8 Long-term debt, including current portion * 9,467.5 10,135.2 9,285.8 9,818.2 * The carrying amount of long-term debt excludes capital lease obligations of $27.6 million and $29.6 million at September 30, 2017 and December 31, 2016 , respectively. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term debt, 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 upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 9 Months Ended |
Sep. 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 and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators. We record derivative instruments on our balance sheets as 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, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. The following table shows our derivative assets and derivative liabilities: September 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 5.4 $ 4.0 $ 31.4 $ 0.4 Petroleum products contracts 1.0 — 0.2 0.1 FTRs 7.3 — 5.1 — Coal contracts 0.6 1.4 1.5 1.4 Total other current * $ 14.3 $ 5.4 $ 38.2 $ 1.9 Other long-term Natural gas contracts $ 1.1 $ — $ 2.9 $ — Coal contracts 0.3 0.7 0.5 0.5 Total other long-term * $ 1.4 $ 0.7 $ 3.4 $ 0.5 Total $ 15.7 $ 6.1 $ 41.6 $ 2.4 * 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 September 30, 2017 Three Months Ended September 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 24.9 Dth $ (2.1 ) 30.5 Dth $ (3.4 ) Petroleum products contracts 4.4 gallons (0.5 ) 4.3 gallons (0.4 ) FTRs 9.4 MWh 4.2 9.9 MWh 7.1 Total $ 1.6 $ 3.3 Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 84.2 Dth $ (1.1 ) 113.3 Dth $ (56.9 ) Petroleum products contracts 14.2 gallons (1.4 ) 10.9 gallons (2.5 ) FTRs 28.0 MWh 9.4 24.9 MWh 11.7 Total $ 6.9 $ (47.7 ) 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 September 30, 2017 and December 31, 2016 , we had posted cash collateral of $24.7 million and $16.4 million , respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. At December 31, 2016, we had also received cash collateral of $4.4 million in our margin accounts. This amount was recorded on our balance sheet 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: September 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 15.7 $ 6.1 $ 41.6 $ 2.4 Gross amount not offset on the balance sheet (3.0 ) (3.1 ) (1) (4.9 ) (2) (0.5 ) Net amount $ 12.7 $ 3.0 $ 36.7 $ 1.9 (1) Includes cash collateral posted of $0.1 million . (2) Includes cash collateral received of $4.4 million . Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a net liability position was $2.3 million and $0.2 million at September 30, 2017 and December 31, 2016 , respectively. At September 30, 2017 and December 31, 2016 , we had not posted any collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at September 30, 2017 , we would have been required to post collateral of $0.8 million . At December 31, 2016 , we would not have been required to post any collateral. |
GUARANTEES
GUARANTEES | 9 Months Ended |
Sep. 30, 2017 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEES The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at September 30, 2017 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting commodity transactions of subsidiaries (1) $ 8.1 $ 8.1 $ — $ — Standby letters of credit (2) 35.8 28.7 7.1 — Surety bonds (3) 9.7 9.7 — — Other guarantees (4) 11.1 0.5 — 10.6 Total guarantees $ 64.7 $ 47.0 $ 7.1 $ 10.6 (1) Consists of $8.1 million to support the business operations of Bluewater. (2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (3) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of $11.1 million related to other indemnifications, for which a liability of $10.6 million related to workers compensation coverage was recorded on our balance sheets. |
EMPLOYEE BENEFITS
EMPLOYEE BENEFITS | 9 Months Ended |
Sep. 30, 2017 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Pension Costs Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Service cost $ 11.1 $ 10.9 $ 33.2 $ 32.9 Interest cost 30.3 33.2 91.7 99.4 Expected return on plan assets (48.8 ) (49.0 ) (146.9 ) (147.0 ) Loss on plan settlement 2.9 0.7 8.2 14.8 Amortization of prior service cost 0.7 0.9 2.2 2.6 Amortization of net actuarial loss 21.5 20.4 64.5 61.1 Net periodic benefit cost $ 17.7 $ 17.1 $ 52.9 $ 63.8 OPEB Costs Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Service cost $ 6.0 $ 6.5 $ 17.9 $ 19.6 Interest cost 8.4 9.2 25.3 27.7 Expected return on plan assets (13.6 ) (13.2 ) (40.9 ) (39.6 ) Amortization of prior service credit (2.8 ) (2.3 ) (8.4 ) (7.0 ) Amortization of net actuarial loss 0.7 2.2 2.3 6.4 Net periodic benefit (credit) cost $ (1.3 ) $ 2.4 $ (3.8 ) $ 7.1 During the nine months ended September 30, 2017 , we made payments of $109.8 million to our pension plans and $5.6 million to our OPEB plans. We expect to make payments of $3.8 million related to our pension plans and $3.9 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. |
GOODWILL
GOODWILL | 9 Months Ended |
Sep. 30, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL | GOODWILL Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table shows changes to our goodwill balances by segment during the nine months ended September 30, 2017 : (in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total Goodwill balance as of January 1, 2017 $ 2,104.3 $ 758.7 $ 183.2 $ — $ 3,046.2 Acquisition of Bluewater (1) — — — 7.3 7.3 Goodwill balance as of September 30, 2017 (2) $ 2,104.3 $ 758.7 $ 183.2 $ 7.3 $ 3,053.5 (1) See Note 2, Acquisitions, for more information on the acquisition of Bluewater. (2) We had no accumulated impairment losses related to our goodwill as of September 30, 2017 . In the third quarter of 2017, annual impairment tests were completed at all of our reporting units that carried a goodwill balance as of July 1, 2017. No impairments resulted from these tests. |
INVESTMENT IN AMERICAN TRANSMIS
INVESTMENT IN AMERICAN TRANSMISSION COMPANY | 9 Months Ended |
Sep. 30, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
INVESTMENT IN AMERICAN TRANSMISSION COMPANY | INVESTMENT IN AMERICAN TRANSMISSION COMPANY We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. The following table shows changes to our investment in ATC: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Balance at beginning of period $ 1,544.0 $ 1,425.0 $ 1,443.9 $ 1,380.9 Add: Earnings from equity method investment 39.2 38.3 122.9 107.7 Add: Capital contributions 12.8 15.0 63.3 27.1 Add: Acquisition of Integrys's investment in ATC — — — (1.0 ) (1) Add: Adjustment to equity method goodwill — — — 10.4 Less: Distributions 35.2 25.2 69.2 (2) 71.9 Less: Other — — 0.1 0.1 Balance at end of period $ 1,560.8 $ 1,453.1 $ 1,560.8 $ 1,453.1 (1) Amount reflects an adjustment to the allocation of the purchase price for Integrys made in the second quarter of 2016. (2) Distributions of $35.2 million , received in the first quarter of 2017, were approved and recorded in December 2016. 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 are reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service. The following table summarizes our significant related party transactions with ATC: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Charges to ATC for services and construction $ 4.4 $ 4.4 $ 12.3 $ 12.8 Charges from ATC for network transmission services 87.4 89.3 262.0 271.4 Refund from ATC per FERC ROE order — — (28.3 ) — Our balance sheets included the following receivables and payables related to ATC: (in millions) September 30, 2017 December 31, 2016 Accounts receivable Services provided to ATC $ 1.5 $ 2.2 Accounts payable Services received from ATC 29.1 28.7 Summarized financial data for ATC is included in the following tables: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Income statement data Revenues $ 171.1 $ 158.1 $ 522.4 $ 476.6 Operating expenses 85.0 80.2 250.1 241.0 Other expense 27.5 23.5 79.6 71.2 Net income $ 58.6 $ 54.4 $ 192.7 $ 164.4 (in millions) September 30, 2017 December 31, 2016 Balance sheet data Current assets $ 89.0 $ 75.8 Noncurrent assets 4,564.9 4,312.9 Total assets $ 4,653.9 $ 4,388.7 Current liabilities $ 772.1 $ 495.1 Long-term debt 1,740.8 1,865.3 Other noncurrent liabilities 213.8 271.5 Shareholders' equity 1,927.2 1,756.8 Total liabilities and shareholders' equity $ 4,653.9 $ 4,388.7 |
SEGMENT INFORMATION
SEGMENT INFORMATION | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION At September 30, 2017 , we reported six segments, which are described below. • The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan that were transferred to UMERC effective January 1, 2017. • The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG. • The other states segment includes the natural gas utility and non-utility operations of MERC and MGU. • The electric transmission segment includes our approximate 60% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. • Following the acquisition of Bluewater, our We Power segment was renamed the non-utility energy infrastructure segment. This segment includes We Power, which owns and leases generating facilities to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan. See Note 2, Acquisitions, for more information on the Bluewater transaction. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco, Wisvest, Wisconsin Energy Capital Corporation, WBS, WPS Power Development LLC, and ITF. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco and in the second quarter of 2016, we sold certain assets of Wisvest. The sale of ITF was completed in the first quarter of 2016. See Note 3, Dispositions , for more information on these sales. All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30 , 2017 and 2016 : Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended September 30, 2017 External revenues $ 1,401.3 $ 187.2 $ 49.8 $ 1,638.3 $ — $ 13.6 $ 5.6 $ — $ 1,657.5 Intersegment revenues — — — — — 111.6 — (111.6 ) — Other operation and maintenance 458.3 100.8 21.6 580.7 — 1.5 (1.5 ) (109.0 ) 471.7 Depreciation and amortization 131.5 38.9 6.3 176.7 — 18.2 6.3 — 201.2 Operating income (loss) 279.7 12.5 (3.1 ) 289.1 — 103.4 1.1 — 393.6 Equity in earnings of transmission affiliate — — — — 39.2 — — — 39.2 Interest expense 48.5 11.0 2.3 61.8 — 16.2 25.4 0.4 103.8 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended September 30, 2016 External revenues $ 1,470.6 $ 181.8 $ 49.9 $ 1,702.3 $ — $ 6.2 $ 4.0 $ — $ 1,712.5 Intersegment revenues — — — — — 105.0 — (105.0 ) — Other operation and maintenance 498.2 105.9 21.2 625.3 — 0.4 (3.2 ) (105.0 ) 517.5 Depreciation and amortization 124.5 33.5 5.2 163.2 — 17.1 11.3 — 191.6 Operating income (loss) 299.1 11.7 (1.0 ) 309.8 — 93.7 (4.5 ) — 399.0 Equity in earnings of transmission affiliate — — — — 38.3 — — — 38.3 Interest expense 44.6 9.3 1.9 55.8 — 15.6 29.7 (2.0 ) 99.1 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate Reconciling Eliminations WEC Energy Group Consolidated Nine Months Ended September 30, 2017 External revenues $ 4,316.6 $ 965.7 $ 273.4 $ 5,555.7 $ — $ 26.1 $ 11.7 $ — $ 5,593.5 Intersegment revenues — — — — — 333.2 — (333.2 ) — Other operation and maintenance 1,379.9 326.6 73.2 1,779.7 — 4.6 (0.3 ) (330.6 ) 1,453.4 Depreciation and amortization 391.1 112.6 18.4 522.1 — 53.1 18.3 — 593.5 Operating income (loss) 835.6 209.3 35.0 1,079.9 — 299.5 (6.3 ) — 1,373.1 Equity in earnings of transmission affiliate — — — — 122.9 — — — 122.9 Interest expense 145.4 33.0 6.5 184.9 — 46.7 81.3 (2.5 ) 310.4 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Nine Months Ended September 30, 2016 External revenues $ 4,354.9 $ 853.1 $ 262.3 $ 5,470.3 $ — $ 18.7 $ 20.3 $ — $ 5,509.3 Intersegment revenues 0.3 — — 0.3 — 317.1 — (317.4 ) — Other operation and maintenance 1,477.3 340.0 80.6 1,897.9 — 3.5 (13.0 ) (317.4 ) 1,571.0 Depreciation and amortization 370.1 99.4 15.5 485.0 — 51.1 33.4 — 569.5 Operating income (loss) 841.3 171.3 33.1 1,045.7 — 281.1 (6.4 ) — 1,320.4 Equity in earnings of transmission affiliate — — — — 107.7 — — — 107.7 Interest expense 133.5 28.8 6.5 168.8 — 46.8 91.2 (6.7 ) 300.1 |
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES | 9 Months Ended |
Sep. 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 We own approximately 60% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment. See Note 14, Investment in American Transmission Company, for more information . The significant assets and liabilities related to ATC recorded on our balance sheets include our equity investment, distributions receivable, and accounts payable. At September 30, 2017 and December 31, 2016 , our equity investment was $1,560.8 million and $1,443.9 million , respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had a receivable of $35.2 million recorded at December 31, 2016 for distributions from ATC. We also had $29.1 million and $28.7 million of accounts payable due to ATC at September 30, 2017 and December 31, 2016 , respectively, for network transmission services. Purchased Power Agreement We have 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 $74.9 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 nine months ended September 30, 2017 and 2016 were $13.5 million and $40.5 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 9 Months Ended |
Sep. 30, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of September 30, 2017 , including those of our subsidiaries, were $11,863.2 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 the 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. In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and will finalize its designation by the end of 2017. 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 plans for both Sheboygan and Kenosha County and submitted them to the EPA for approval. The plans 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. We expect the EPA to issue a decision 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 later in 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 October 2017, the EPA issued a notice of proposed rulemaking to repeal the CPP. The EPA is expected subsequently to issue an advanced notice of proposed rulemaking that will solicit input on whether it is appropriate to replace the CPP. 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 have implemented and 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, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit. 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 Pulliam Units 7 and 8, Weston Units 2 through 4, Port Washington Generating Station, 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 and Weston Units 3 and 4 (which all have 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. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. We provided information to the MDEQ about unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), the EM BTA requirements will be waived. We expect to submit this certification in November 2017. We expect to submit entrainment studies being conducted at Pulliam Units 7 and 8 to the WDNR by June 2018. We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Limitation Guidelines The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurization wastewater requirements . 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, the Pleasant Prairie units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $80 million to $110 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 19, Regulatory Environment , regarding the potential retirement of PIPP. Land Quality Manufactured Gas Plant Remediation We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves related to manufactured gas plant sites: (in millions) September 30, 2017 December 31, 2016 Regulatory assets $ 683.3 $ 702.7 Reserves for future remediation 617.5 633.4 Enforcement and Litigation Matters We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations. Consent Decrees Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam In November 2009, the EPA issued a NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013. Also, in May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of September 30, 2017 . It is unknown whether the Sierra Club will take further action in the future. Joint Ownership Power Plants Consent Decree – Columbia and Edgewater In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. The Consent Decree contains a requirement to, among other things, refuel, repower, or retire Edgewater Unit 4, of which WPS is a joint owner, by no later than December 31, 2018. Management of the joint owners has recommended that Edgewater Unit 4 be retired by December 2018. See Note 4, Property, Plant, and Equipment, for more information about the retirement. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 9 Months Ended |
Sep. 30, 2017 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Nine Months Ended September 30 (in millions) 2017 2016 Cash (paid) for interest, net of amount capitalized $ (258.2 ) $ (260.7 ) Cash received for income taxes, net 7.3 11.7 Significant non-cash transactions Accounts payable related to construction costs 172.7 113.1 Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust 4.6 (4.5 ) Portion of Bostco real estate holdings sale financed with note receivable * 7.0 — Amortization of deferred revenue 18.7 18.5 * See Note 3, Dispositions, for more information on this sale. At September 30, 2017 , and December 31, 2016 , restricted cash of $20.4 million and $33.6 million , respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition. Withdrawals of restricted cash from the rabbi trust for qualifying payments are shown as an investing activity on the statements of cash flows. Changes in restricted cash due to the sale or purchase of investments held in the rabbi trust are non-cash transactions and are included in the table above. |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 9 Months Ended |
Sep. 30, 2017 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT Wisconsin Electric Power Company, Wisconsin Gas LLC, and Wisconsin Public Service Corporation 2018 and 2019 Rates During April 2017, WE, WG, and WPS filed an application with the PSCW for approval of a settlement agreement they made with several of their commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which will freeze base rates through 2019 for electric, gas, and steam customers of WE, WG, and WPS. Based on the PSCW order, the authorized ROE for WE, WG, and WPS remains at 10.2% , 10.3% , and 10.0% , respectively, and the current capital cost structure for all of our Wisconsin utilities will remain unchanged through 2019. Various intervenors have filed requests for rehearing. In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs at WE during the base rate freeze period by accelerating the recognition of certain tax benefits. In addition, WE, WG, and WPS will defer the revenue requirement impacts of any federal corporate tax reform enacted in 2017 or during the base rate freeze period. Additionally, the agreement allows WPS to extend through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized $275.0 million level, and other deferrals related to WPS's electric real-time market pricing program and network transmission expenses. The total cost of the ReACT™ project, excluding $51 million of AFUDC, is currently estimated to be $342 million . Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism currently in place for WE and WG, and all three utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers. Natural Gas Storage Facilities in Michigan In January 2017, we signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide approximately one-third of the current storage needs for the natural gas distribution service customers of WE, WG, and WPS. As a result of this agreement, WE, 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, WG, and WPS requested that the PSCW review and confirm the reasonableness and prudency of their potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facilities. WE, WG, and WPS also requested approval to amend our Affiliated Interest Agreement to ensure WBS and our other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and we acquired Bluewater on June 30, 2017. In September 2017, WE, WG, and WPS finalized the long-term service agreements for the natural gas storage and filed with the PSCW for approval of these agreements. We expect to receive approval of the service agreements in the fourth quarter of 2017. See Note 2, Acquisitions, for more information . The Peoples Gas Light and Coke Company and North Shore Gas Company Illinois Proceedings In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops commenced in January 2016 and were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program. In March 2017, the ICC issued an order directing that additional hearings be held before the ALJ on certain issues to further develop the evidentiary record in the case. This proceeding is expected to result in a final order by the ICC in 2017. We are currently unable to determine what, if any, long-term impact there will be on the SMP. Qualifying Infrastructure Plant Rider In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. The Act provides PGL with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014. PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ICC staff and the Illinois Attorney General's office held an evidentiary hearing in September 2017, and we expect to receive an order related to the 2014 reconciliation in 2017. As of September 30, 2017 , there can be no assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be deemed recoverable by the ICC. Minnesota Energy Resources Corporation 2018 Minnesota Rate Case In October 2017, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $12.6 million ( 5.05% ). MERC's request reflects a 10.3% ROE and a common equity component average of 50.9% . The proposed retail natural gas rate increase is primarily driven by increased capital investments as well as general inflation. MERC is also requesting authority from the MPUC to continue the use of its currently authorized decoupling mechanism. 2016 Minnesota Rate Order In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, effective March 1, 2017. The order authorized a retail natural gas rate increase of $6.8 million ( 3.0% ). The rates reflect a 9.11% ROE and a common equity component average of 50.32% . The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another three years . The final approved rate increase was lower than the interim rates collected from customers during 2016. Therefore, we refunded $4.1 million to MERC's customers during the second quarter of 2017. Upper Michigan Energy Resources Corporation Formation of 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, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WE and WPS, located in the Upper Peninsula of Michigan. In August 2016, we 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. In October 2017, the MPSC approved both the agreement with Tilden and UMERC's application for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is $265.7 million ( $277 million with AFUDC), 50% of which is expected to be recovered from Tilden, with the remaining 50% expected to be recovered from UMERC's other utility customers. 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 a customer of WE until this new generation begins commercial operation. 2015 Michigan Rate Order Prior to the formation of UMERC, in October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement. As a result of the formation of UMERC, the terms and conditions of this WPS rate order now apply to UMERC, including the deferrals described below. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflected a 10.2% ROE and a common equity component average of 50.48% . The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, the Fox Energy Center costs deferral was discontinued and amortization of this deferral began, along with the amortization of the deferral associated with the termination of the Fox Energy Center tolling agreement. In the order, the MPSC also approved the deferral and amortization of the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. UMERC will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018. |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 9 Months Ended |
Sep. 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 finalizing our review of our contracts with customers and the related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider tariff sales at our regulated utilities, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of our operating revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition. 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, if applicable, 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. Restricted Cash In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-the period and end-of-the period total amounts shown on the statements of cash flows. 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. While we have not fully determined the impacts of the adoption of this standard, we expect that as a result of the application of accounting principles for rate regulated entities, a similar amount of net benefit cost (including non-service components), will be recognized in our financial statements consistent with the current ratemaking treatment. As a result, we believe the impacts of adoption will be limited to changes in classification of non-service costs in the income statements. |
GENERAL INFORMATION (Policies)
GENERAL INFORMATION (Policies) | 9 Months Ended |
Sep. 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, statements of comprehensive income, 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 WEC Energy Group and all of its subsidiaries. |
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 nine months ended September 30 , 2017 , are not necessarily indicative of expected results for 2017 due to seasonal variations and other factors. |
Stock-Based Compensation - Forfeitures | As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. |
Fair Value Measurement | 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 financial 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 and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators. We record derivative instruments on our balance sheets as 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, our regulators allow 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 finalizing our review of our contracts with customers and the related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider tariff sales at our regulated utilities, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of our operating revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition. 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, if applicable, 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. Restricted Cash In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-the period and end-of-the period total amounts shown on the statements of cash flows. 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. While we have not fully determined the impacts of the adoption of this standard, we expect that as a result of the application of accounting principles for rate regulated entities, a similar amount of net benefit cost (including non-service components), will be recognized in our financial statements consistent with the current ratemaking treatment. As a result, we believe the impacts of adoption will be limited to changes in classification of non-service costs in the income statements. |
ACQUISITIONS (Tables)
ACQUISITIONS (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Business Combinations [Abstract] | |
Allocation of purchase price | The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy infrastructure segment. See Note 15, Segment Information, for more information . (in millions) Current assets $ 2.0 Net property, plant, and equipment 217.6 Goodwill 7.3 Current liabilities (0.9 ) Total purchase price $ 226.0 |
COMMON EQUITY (Tables)
COMMON EQUITY (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Equity [Abstract] | |
Schedule of stock-based compensation awards granted | During the first quarter of 2017, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees: Award Type Number of Awards Stock options (1) 552,215 Restricted shares (2) 82,622 Performance units 237,650 (1) Stock options awarded had a weighted-average exercise price of $58.31 and a weighted-average grant date fair value of $7.45 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $58.10 per share. |
Retained earnings | |
Schedule of changes to retained earnings | |
Schedule of changes in retained earnings | The following table shows the changes to our retained earnings for the nine months ended September 30, 2017 : (in millions) Retained Earnings Balance at December 31, 2016 $ 4,613.9 Net income attributed to common shareholders 771.1 Common stock dividends (492.4 ) Cumulative effect of adoption of ASU 2016-09 15.7 Balance at September 30, 2017 $ 4,908.3 |
SHORT-TERM DEBT AND LINES OF 30
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Short-term Debt [Abstract] | |
Short-term borrowings and their corresponding weighted average interest rate | The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) September 30, 2017 December 31, 2016 Commercial paper Amount outstanding $ 993.5 $ 860.2 Weighted-average interest rate on amounts outstanding 1.38 % 0.96 % |
Schedule of revolving credit facilities and remaining available capacity | The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these facilities: (in millions) Maturity September 30, 2017 WEC Energy Group (1) December 2020 $ 1,050.0 WE (2) December 2020 500.0 WPS (3) December 2020 250.0 WG (2) December 2020 350.0 PGL (2) December 2020 350.0 Total short-term credit capacity $ 2,500.0 Less: Letters of credit issued inside credit facilities $ 32.9 Commercial paper outstanding 993.5 Available capacity under existing agreements $ 1,473.6 (1) In October 2017, WEC Energy Group increased its credit facility to $1,200.0 million , and extended the maturity to October 2022. (2) In October 2017, WE, WG, and PGL extended the maturities of their credit facilities to October 2022. (3) In October 2017, WPS increased its credit facility to $400.0 million . WPS intends to request approval from the PSCW to extend the maturity of its facility to October 2022. |
MATERIALS, SUPPLIES, AND INVE31
MATERIALS, SUPPLIES, AND INVENTORIES (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Inventory Disclosure [Abstract] | |
Schedule of inventory | Our inventory consisted of: (in millions) September 30, 2017 December 31, 2016 Natural gas in storage $ 301.5 $ 223.1 Materials and supplies 225.1 206.5 Fossil fuel 145.6 158.0 Total $ 672.2 $ 587.6 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 9 Months Ended |
Sep. 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: September 30, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 2.8 $ 3.7 $ — $ 6.5 Petroleum products contracts 1.0 — — 1.0 FTRs — — 7.3 7.3 Coal contracts — 0.9 — 0.9 Total derivative assets $ 3.8 $ 4.6 $ 7.3 $ 15.7 Investments held in rabbi trust $ 113.5 $ — $ — $ 113.5 Derivative liabilities Natural gas contracts $ 1.5 $ 2.5 $ — $ 4.0 Coal contracts — 2.1 — 2.1 Total derivative liabilities $ 1.5 $ 4.6 $ — $ 6.1 December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 10.1 $ 24.2 $ — $ 34.3 Petroleum products contracts 0.2 — — 0.2 FTRs — — 5.1 5.1 Coal contracts — 2.0 — 2.0 Total derivative assets $ 10.3 $ 26.2 $ 5.1 $ 41.6 Investments held in rabbi trust $ 103.9 $ — $ — $ 103.9 Derivative liabilities Natural gas contracts $ 0.2 $ 0.2 $ — $ 0.4 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 1.9 — 1.9 Total derivative liabilities $ 0.3 $ 2.1 $ — $ 2.4 |
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 September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Balance at the beginning of the period $ 11.8 $ 13.4 $ 5.1 $ 3.6 Realized and unrealized losses — — — (0.2 ) Purchases — — 13.8 15.2 Sales — — — (0.2 ) Settlements (4.5 ) (4.2 ) (11.6 ) (9.2 ) Balance at the end of the period $ 7.3 $ 9.2 $ 7.3 $ 9.2 |
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: September 30, 2017 December 31, 2016 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 29.6 $ 30.4 $ 28.8 Long-term debt, including current portion * 9,467.5 10,135.2 9,285.8 9,818.2 * The carrying amount of long-term debt excludes capital lease obligations of $27.6 million and $29.6 million at September 30, 2017 and December 31, 2016 , respectively. |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative assets and derivative liabilities | The following table shows our derivative assets and derivative liabilities: September 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 5.4 $ 4.0 $ 31.4 $ 0.4 Petroleum products contracts 1.0 — 0.2 0.1 FTRs 7.3 — 5.1 — Coal contracts 0.6 1.4 1.5 1.4 Total other current * $ 14.3 $ 5.4 $ 38.2 $ 1.9 Other long-term Natural gas contracts $ 1.1 $ — $ 2.9 $ — Coal contracts 0.3 0.7 0.5 0.5 Total other long-term * $ 1.4 $ 0.7 $ 3.4 $ 0.5 Total $ 15.7 $ 6.1 $ 41.6 $ 2.4 * 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 gain (losses) | Our estimated notional sales volumes and realized gains (losses) were as follows: Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 24.9 Dth $ (2.1 ) 30.5 Dth $ (3.4 ) Petroleum products contracts 4.4 gallons (0.5 ) 4.3 gallons (0.4 ) FTRs 9.4 MWh 4.2 9.9 MWh 7.1 Total $ 1.6 $ 3.3 Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016 (in millions) Volumes Gains (Losses) Volumes Gains (Losses) Natural gas contracts 84.2 Dth $ (1.1 ) 113.3 Dth $ (56.9 ) Petroleum products contracts 14.2 gallons (1.4 ) 10.9 gallons (2.5 ) FTRs 28.0 MWh 9.4 24.9 MWh 11.7 Total $ 6.9 $ (47.7 ) |
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: September 30, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 15.7 $ 6.1 $ 41.6 $ 2.4 Gross amount not offset on the balance sheet (3.0 ) (3.1 ) (1) (4.9 ) (2) (0.5 ) Net amount $ 12.7 $ 3.0 $ 36.7 $ 1.9 (1) Includes cash collateral posted of $0.1 million . (2) Includes cash collateral received of $4.4 million . |
GUARANTEES (Tables)
GUARANTEES (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Guarantees [Abstract] | |
Schedule of outstanding guarantees | The following table shows our outstanding guarantees: Expiration (in millions) Total Amounts Committed at September 30, 2017 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting commodity transactions of subsidiaries (1) $ 8.1 $ 8.1 $ — $ — Standby letters of credit (2) 35.8 28.7 7.1 — Surety bonds (3) 9.7 9.7 — — Other guarantees (4) 11.1 0.5 — 10.6 Total guarantees $ 64.7 $ 47.0 $ 7.1 $ 10.6 (1) Consists of $8.1 million to support the business operations of Bluewater. (2) At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets. (3) Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (4) Consists of $11.1 million related to other indemnifications, for which a liability of $10.6 million related to workers compensation coverage was recorded on our balance sheets. |
EMPLOYEE BENEFITS (Tables)
EMPLOYEE BENEFITS (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Retirement Benefits [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 September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Service cost $ 11.1 $ 10.9 $ 33.2 $ 32.9 Interest cost 30.3 33.2 91.7 99.4 Expected return on plan assets (48.8 ) (49.0 ) (146.9 ) (147.0 ) Loss on plan settlement 2.9 0.7 8.2 14.8 Amortization of prior service cost 0.7 0.9 2.2 2.6 Amortization of net actuarial loss 21.5 20.4 64.5 61.1 Net periodic benefit cost $ 17.7 $ 17.1 $ 52.9 $ 63.8 OPEB Costs Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Service cost $ 6.0 $ 6.5 $ 17.9 $ 19.6 Interest cost 8.4 9.2 25.3 27.7 Expected return on plan assets (13.6 ) (13.2 ) (40.9 ) (39.6 ) Amortization of prior service credit (2.8 ) (2.3 ) (8.4 ) (7.0 ) Amortization of net actuarial loss 0.7 2.2 2.3 6.4 Net periodic benefit (credit) cost $ (1.3 ) $ 2.4 $ (3.8 ) $ 7.1 |
GOODWILL (Tables)
GOODWILL (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of changes to our goodwill balances by segment | The following table shows changes to our goodwill balances by segment during the nine months ended September 30, 2017 : (in millions) Wisconsin Illinois Other States Non-Utility Energy Infrastructure Total Goodwill balance as of January 1, 2017 $ 2,104.3 $ 758.7 $ 183.2 $ — $ 3,046.2 Acquisition of Bluewater (1) — — — 7.3 7.3 Goodwill balance as of September 30, 2017 (2) $ 2,104.3 $ 758.7 $ 183.2 $ 7.3 $ 3,053.5 (1) See Note 2, Acquisitions, for more information on the acquisition of Bluewater. (2) We had no accumulated impairment losses related to our goodwill as of September 30, 2017 . |
INVESTMENT IN AMERICAN TRANSM37
INVESTMENT IN AMERICAN TRANSMISSION COMPANY (Tables) - ATC | 9 Months Ended |
Sep. 30, 2017 | |
Investment in ATC | |
Schedule of changes to our investment in ATC | The following table shows changes to our investment in ATC: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Balance at beginning of period $ 1,544.0 $ 1,425.0 $ 1,443.9 $ 1,380.9 Add: Earnings from equity method investment 39.2 38.3 122.9 107.7 Add: Capital contributions 12.8 15.0 63.3 27.1 Add: Acquisition of Integrys's investment in ATC — — — (1.0 ) (1) Add: Adjustment to equity method goodwill — — — 10.4 Less: Distributions 35.2 25.2 69.2 (2) 71.9 Less: Other — — 0.1 0.1 Balance at end of period $ 1,560.8 $ 1,453.1 $ 1,560.8 $ 1,453.1 (1) Amount reflects an adjustment to the allocation of the purchase price for Integrys made in the second quarter of 2016. (2) Distributions of $35.2 million , received in the first quarter of 2017, were approved and recorded in December 2016 |
Schedule of significant transactions with ATC | The following table summarizes our significant related party transactions with ATC: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Charges to ATC for services and construction $ 4.4 $ 4.4 $ 12.3 $ 12.8 Charges from ATC for network transmission services 87.4 89.3 262.0 271.4 Refund from ATC per FERC ROE order — — (28.3 ) — |
Schedule of receivables and payables with ATC | Our balance sheets included the following receivables and payables related to ATC: (in millions) September 30, 2017 December 31, 2016 Accounts receivable Services provided to ATC $ 1.5 $ 2.2 Accounts payable Services received from ATC 29.1 28.7 |
Schedule of summarized income statement data for ATC | Summarized financial data for ATC is included in the following tables: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2017 2016 2017 2016 Income statement data Revenues $ 171.1 $ 158.1 $ 522.4 $ 476.6 Operating expenses 85.0 80.2 250.1 241.0 Other expense 27.5 23.5 79.6 71.2 Net income $ 58.6 $ 54.4 $ 192.7 $ 164.4 |
Schedule of summarized balance sheet data for ATC | (in millions) September 30, 2017 December 31, 2016 Balance sheet data Current assets $ 89.0 $ 75.8 Noncurrent assets 4,564.9 4,312.9 Total assets $ 4,653.9 $ 4,388.7 Current liabilities $ 772.1 $ 495.1 Long-term debt 1,740.8 1,865.3 Other noncurrent liabilities 213.8 271.5 Shareholders' equity 1,927.2 1,756.8 Total liabilities and shareholders' equity $ 4,653.9 $ 4,388.7 |
SEGMENT INFORMATION (Tables)
SEGMENT INFORMATION (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Segment Reporting [Abstract] | |
Financial information of reportable segments | The following tables show summarized financial information related to our reportable segments for the three and nine months ended September 30 , 2017 and 2016 : Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended September 30, 2017 External revenues $ 1,401.3 $ 187.2 $ 49.8 $ 1,638.3 $ — $ 13.6 $ 5.6 $ — $ 1,657.5 Intersegment revenues — — — — — 111.6 — (111.6 ) — Other operation and maintenance 458.3 100.8 21.6 580.7 — 1.5 (1.5 ) (109.0 ) 471.7 Depreciation and amortization 131.5 38.9 6.3 176.7 — 18.2 6.3 — 201.2 Operating income (loss) 279.7 12.5 (3.1 ) 289.1 — 103.4 1.1 — 393.6 Equity in earnings of transmission affiliate — — — — 39.2 — — — 39.2 Interest expense 48.5 11.0 2.3 61.8 — 16.2 25.4 0.4 103.8 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended September 30, 2016 External revenues $ 1,470.6 $ 181.8 $ 49.9 $ 1,702.3 $ — $ 6.2 $ 4.0 $ — $ 1,712.5 Intersegment revenues — — — — — 105.0 — (105.0 ) — Other operation and maintenance 498.2 105.9 21.2 625.3 — 0.4 (3.2 ) (105.0 ) 517.5 Depreciation and amortization 124.5 33.5 5.2 163.2 — 17.1 11.3 — 191.6 Operating income (loss) 299.1 11.7 (1.0 ) 309.8 — 93.7 (4.5 ) — 399.0 Equity in earnings of transmission affiliate — — — — 38.3 — — — 38.3 Interest expense 44.6 9.3 1.9 55.8 — 15.6 29.7 (2.0 ) 99.1 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate Reconciling Eliminations WEC Energy Group Consolidated Nine Months Ended September 30, 2017 External revenues $ 4,316.6 $ 965.7 $ 273.4 $ 5,555.7 $ — $ 26.1 $ 11.7 $ — $ 5,593.5 Intersegment revenues — — — — — 333.2 — (333.2 ) — Other operation and maintenance 1,379.9 326.6 73.2 1,779.7 — 4.6 (0.3 ) (330.6 ) 1,453.4 Depreciation and amortization 391.1 112.6 18.4 522.1 — 53.1 18.3 — 593.5 Operating income (loss) 835.6 209.3 35.0 1,079.9 — 299.5 (6.3 ) — 1,373.1 Equity in earnings of transmission affiliate — — — — 122.9 — — — 122.9 Interest expense 145.4 33.0 6.5 184.9 — 46.7 81.3 (2.5 ) 310.4 Utility Operations (in millions) Wisconsin Illinois Other States Total Utility Operations Electric Transmission Non-Utility Energy Infrastructure Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Nine Months Ended September 30, 2016 External revenues $ 4,354.9 $ 853.1 $ 262.3 $ 5,470.3 $ — $ 18.7 $ 20.3 $ — $ 5,509.3 Intersegment revenues 0.3 — — 0.3 — 317.1 — (317.4 ) — Other operation and maintenance 1,477.3 340.0 80.6 1,897.9 — 3.5 (13.0 ) (317.4 ) 1,571.0 Depreciation and amortization 370.1 99.4 15.5 485.0 — 51.1 33.4 — 569.5 Operating income (loss) 841.3 171.3 33.1 1,045.7 — 281.1 (6.4 ) — 1,320.4 Equity in earnings of transmission affiliate — — — — 107.7 — — — 107.7 Interest expense 133.5 28.8 6.5 168.8 — 46.8 91.2 (6.7 ) 300.1 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 9 Months Ended |
Sep. 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) September 30, 2017 December 31, 2016 Regulatory assets $ 683.3 $ 702.7 Reserves for future remediation 617.5 633.4 |
SUPPLEMENTAL CASH FLOW INFORM40
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 9 Months Ended |
Sep. 30, 2017 | |
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | Nine Months Ended September 30 (in millions) 2017 2016 Cash (paid) for interest, net of amount capitalized $ (258.2 ) $ (260.7 ) Cash received for income taxes, net 7.3 11.7 Significant non-cash transactions Accounts payable related to construction costs 172.7 113.1 Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust 4.6 (4.5 ) Portion of Bostco real estate holdings sale financed with note receivable * 7.0 — Amortization of deferred revenue 18.7 18.5 * See Note 3, Dispositions, for more information on this sale. |
GENERAL INFORMATION - GENERAL (
GENERAL INFORMATION - GENERAL (Details) customer in Millions | Sep. 30, 2017customer |
Electric | |
Product information [Line Items] | |
Number Of Customers | 1.6 |
Natural gas | |
Product information [Line Items] | |
Number Of Customers | 2.8 |
ATC | |
Product information [Line Items] | |
Equity method investment, ownership interest (as a percent) | 60.00% |
ACQUISITIONS - FORWARD ACQUISIT
ACQUISITIONS - FORWARD ACQUISITION (Details) - Forward Wind Energy Center $ in Millions | 1 Months Ended | |
Oct. 31, 2017USD ($)wind_turbinesutilityMW | Sep. 30, 2017 | |
WPS | ||
Business Acquisition [Line Items] | ||
Percentage of Forward Wind Energy Center's output purchased by WPS | 44.60% | |
Subsequent event | ||
Business Acquisition [Line Items] | ||
Number of wind turbines at Forward Wind Energy Center | wind_turbines | 86 | |
Capacity of Foward Wind Energy Center | MW | 129 | |
Approximate purchase price | $ 174 | |
Subsequent event | WPS | ||
Business Acquisition [Line Items] | ||
Number of utilities along with WPS that entered in an agreement to purchase Forward Wind Energy Center | utility | 2 | |
Approximate purchase price | $ 78 | |
WPS's share of Forward Wind Energy Center's purchase price | 44.60% |
ACQUISITIONS - BLUEWATER ACQUIS
ACQUISITIONS - BLUEWATER ACQUISITION - CONSIDERATION TRANSFERRED (Details) - Bluewater - USD ($) $ in Millions | 1 Months Ended | |
Jun. 30, 2017 | Sep. 30, 2017 | |
Business Acquisition [Line Items] | ||
Purchase price | $ 226 | |
Percentage of current storage needs provided | 33.00% | |
Acquisition related costs | $ 4.9 |
ACQUISITIONS- BLUEWATER ACQUISI
ACQUISITIONS- BLUEWATER ACQUISITION - PURCHASE PRICE ALLOCATION (Details) - Bluewater - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended |
Jun. 30, 2017 | Sep. 30, 2017 | |
Business Acquisition [Line Items] | ||
Current assets | $ 2 | |
Net property, plant, and equipment | 217.6 | |
Goodwill | 7.3 | $ 7.3 |
Current liabilities | (0.9) | |
Total purchase price | $ 226 |
DISPOSITIONS (Details)
DISPOSITIONS (Details) - USD ($) $ in Millions | 3 Months Ended | |
Jun. 30, 2016 | Mar. 31, 2016 | |
Wisconsin | WE | ||
Dispositions | ||
After-tax gain on sale | $ 6.5 | |
Wisconsin | WE | Other operation and maintenance | ||
Dispositions | ||
Pre-tax gain on sale | 10.9 | |
Corporate and Other | Wisvest | ||
Dispositions | ||
After-tax gain on sale | 11.8 | |
Corporate and Other | Wisvest | Other income, net | ||
Dispositions | ||
Pre-tax gain on sale | $ 19.6 | |
Corporate and Other | ITF | ||
Dispositions | ||
Pre-tax gain on sale | $ 0 |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT (Details) $ in Millions | 1 Months Ended | ||
Oct. 31, 2017MW | Sep. 30, 2017USD ($) | Dec. 31, 2016USD ($) | |
Property, Plant and Equipment [Line Items] | |||
Net book value of property, plant, and equipment | $ 20,882.9 | $ 19,915.5 | |
UMERC | Subsequent event | |||
Property, Plant and Equipment [Line Items] | |||
Capacity of natural gas-fired generation facility (in megawatts) | MW | 180 | ||
WE | Presque Isle Power Plant | |||
Property, Plant and Equipment [Line Items] | |||
Net book value of property, plant, and equipment | 203 | ||
WPS | Edgewater Unit 4 | Plant to be retired | |||
Property, Plant and Equipment [Line Items] | |||
Net book value of property, plant, and equipment | $ 13.3 |
COMMON EQUITY - STOCK-BASED COM
COMMON EQUITY - STOCK-BASED COMPENSATION AWARDS GRANTED (Details) | 9 Months Ended |
Sep. 30, 2017$ / sharesshares | |
Stock options | |
Stock-based Compensation | |
Stock options granted | shares | 552,215 |
Stock options granted, weighted average exercise price | $ / shares | $ 58.31 |
Stock options granted, weighted-average grant date fair value | $ / shares | $ 7.45 |
Restricted shares | |
Stock-based Compensation | |
Awards granted | shares | 82,622 |
Restricted shares granted, weighted-average grant date fair value | $ / shares | $ 58.10 |
Performance units | |
Stock-based Compensation | |
Awards granted | shares | 237,650 |
COMMON EQUITY - ADOPTION OF ASU
COMMON EQUITY - ADOPTION OF ASU 2016-09 (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Changes in retained earnings [Roll Forward] | ||||
Balance at December 31, 2016 | $ 4,613.9 | |||
Net income attributed to common shareholders | $ 215.4 | $ 217 | 771.1 | $ 744.6 |
Common stock dividends | (492.4) | |||
Cumulative effect of adoption of ASU 2016-09 | 15.7 | 15.7 | ||
Balance at September 30, 2017 | $ 4,908.3 | $ 4,908.3 |
COMMON EQUITY - COMMON STOCK DI
COMMON EQUITY - COMMON STOCK DIVIDENDS (Details) - $ / shares | Oct. 19, 2017 | Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 |
Dividends Payable | |||||
Quarterly cash dividend declared (in dollars per share) | $ 0.520 | $ 0.495 | $ 1.560 | $ 1.485 | |
Subsequent event | |||||
Dividends Payable | |||||
Quarterly cash dividend declared (in dollars per share) | $ 0.52 |
SHORT-TERM DEBT AND LINES OF 50
SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2017 | Dec. 31, 2016 | |
Short-term borrowings | ||
Commercial Paper | $ 993.5 | $ 860.2 |
Commercial paper | ||
Short-term borrowings | ||
Weighted-average interest rate on amounts outstanding | 1.38% | 0.96% |
Average amounts outstanding during the period | $ 705 | |
Weighted-average interest rate during the period | 1.21% |
SHORT-TERM DEBT AND LINES OF 51
SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions | Oct. 31, 2017 | Sep. 30, 2017 | Dec. 31, 2016 |
Line of Credit Facility | |||
Short-term credit capacity | $ 2,500 | ||
Letters of credit issued inside credit facilities | 32.9 | ||
Commercial Paper | 993.5 | $ 860.2 | |
Available capacity under existing agreements | 1,473.6 | ||
WEC Energy Group | Credit facility maturing December 2020 | |||
Line of Credit Facility | |||
Short-term credit capacity | 1,050 | ||
WE | Credit facility maturing December 2020 | |||
Line of Credit Facility | |||
Short-term credit capacity | 500 | ||
WPS | Credit facility maturing December 2020 | |||
Line of Credit Facility | |||
Short-term credit capacity | 250 | ||
WG | Credit facility maturing December 2020 | |||
Line of Credit Facility | |||
Short-term credit capacity | 350 | ||
PGL | Credit facility maturing December 2020 | |||
Line of Credit Facility | |||
Short-term credit capacity | $ 350 | ||
Subsequent event | WEC Energy Group | Credit facility maturing October 2022 | |||
Line of Credit Facility | |||
Short-term credit capacity | $ 1,200 | ||
Subsequent event | WE | Credit facility maturing October 2022 | |||
Line of Credit Facility | |||
Short-term credit capacity | 500 | ||
Subsequent event | WPS | Credit facility maturing October 2022 | |||
Line of Credit Facility | |||
Short-term credit capacity | 400 | ||
Subsequent event | WG | Credit facility maturing October 2022 | |||
Line of Credit Facility | |||
Short-term credit capacity | 350 | ||
Subsequent event | PGL | Credit facility maturing October 2022 | |||
Line of Credit Facility | |||
Short-term credit capacity | $ 350 |
LONG TERM DEBT (Details)
LONG TERM DEBT (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2017USD ($) | |
WEC Energy Group | 2007 Junior Notes (unsecured), due 2067 | |
Debt Instrument [Line Items] | |
Unsecured Long-term Debt, Noncurrent | $ 500 |
Interest rate percentage in excess of LIBOR | 2.1125% |
MERC | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 120 |
MERC | MERC Senior Notes 3.11% due July 15, 2027 | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 40 |
Interest rate on long-term debt | 3.11% |
MERC | MERC Senior Notes 3.41% due July 15, 2032 | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 40 |
Interest rate on long-term debt | 3.41% |
MERC | MERC Senior Notes 4.01% due July 15, 2047 | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 40 |
Interest rate on long-term debt | 4.01% |
MGU | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 90 |
MGU | MGU Senior Notes 3.11% due July 15, 2027 | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 30 |
Interest rate on long-term debt | 3.11% |
MGU | MGU Senior Notes 3.41% due July 15, 2032 | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 30 |
Interest rate on long-term debt | 3.41% |
MGU | MGU Senior Notes 4.01% due July 15, 2047 | |
Debt Instrument [Line Items] | |
Proceeds from Issuance of Debt | $ 30 |
Interest rate on long-term debt | 4.01% |
Integrys | MERC | |
Debt Instrument [Line Items] | |
Repayment of long-term debt from parent | $ 78 |
Integrys | MGU | |
Debt Instrument [Line Items] | |
Repayment of long-term debt from parent | $ 71 |
MATERIALS, SUPPLIES, AND INVE53
MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Inventory Disclosure [Abstract] | ||
Natural gas in storage | $ 301.5 | $ 223.1 |
Materials and supplies | 225.1 | 206.5 |
Fossil fuel | 145.6 | 158 |
Total | 672.2 | $ 587.6 |
LIFO cost method | ||
LIFO liquidation balance | $ 0 |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Assets | ||
Derivative asset | $ 15.7 | $ 41.6 |
Liabilities | ||
Derivative liability | 6.1 | 2.4 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative asset | 15.7 | 41.6 |
Investments held in rabbi trust | 113.5 | 103.9 |
Liabilities | ||
Derivative liability | 6.1 | 2.4 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 3.8 | 10.3 |
Investments held in rabbi trust | 113.5 | 103.9 |
Liabilities | ||
Derivative liability | 1.5 | 0.3 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 4.6 | 26.2 |
Investments held in rabbi trust | 0 | 0 |
Liabilities | ||
Derivative liability | 4.6 | 2.1 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 7.3 | 5.1 |
Investments held in rabbi trust | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative asset | 6.5 | 34.3 |
Liabilities | ||
Derivative liability | 4 | 0.4 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative asset | 2.8 | 10.1 |
Liabilities | ||
Derivative liability | 1.5 | 0.2 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative asset | 3.7 | 24.2 |
Liabilities | ||
Derivative liability | 2.5 | 0.2 |
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 | 1 | 0.2 |
Liabilities | ||
Derivative liability | 0.1 | |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1 | ||
Assets | ||
Derivative asset | 1 | 0.2 |
Liabilities | ||
Derivative liability | 0.1 | |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | |
Fair value measurements on a recurring basis | FTRs | ||
Assets | ||
Derivative asset | 7.3 | 5.1 |
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 | 7.3 | 5.1 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative asset | 0.9 | 2 |
Liabilities | ||
Derivative liability | 2.1 | 1.9 |
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 | 0.9 | 2 |
Liabilities | ||
Derivative liability | 2.1 | 1.9 |
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 | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||||
Balance at the beginning of the period | $ 11.8 | $ 13.4 | $ 5.1 | $ 3.6 |
Realized and unrealized losses | 0 | 0 | 0 | (0.2) |
Purchases | 0 | 0 | 13.8 | 15.2 |
Sales | 0 | 0 | 0 | (0.2) |
Settlements | (4.5) | (4.2) | (11.6) | (9.2) |
Balance at the end of period | 7.3 | 9.2 | 7.3 | 9.2 |
Unrealized gains and losses on level 3 derivatives included in earnings | $ 0 | $ 0 | $ 0 | $ 0 |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Financial Instruments | ||
Preferred stock | $ 30.4 | $ 30.4 |
Carrying Amount | ||
Financial Instruments | ||
Preferred stock | 30.4 | 30.4 |
Long-term debt, including current portion | 9,467.5 | 9,285.8 |
Capital lease obligations | 27.6 | 29.6 |
Fair Value | ||
Financial Instruments | ||
Preferred stock | 29.6 | 28.8 |
Long-term debt, including current portion | $ 10,135.2 | $ 9,818.2 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Derivative Asset | ||
Other current derivative assets | $ 14.3 | $ 38.2 |
Other long-term derivative assets | 1.4 | 3.4 |
Derivative asset | 15.7 | 41.6 |
Derivative Liability | ||
Other current derivative liabilities | 5.4 | 1.9 |
Other long-term derivative liabilities | 0.7 | 0.5 |
Derivative liability | 6.1 | 2.4 |
Natural gas contracts | ||
Derivative Asset | ||
Other current derivative assets | 5.4 | 31.4 |
Other long-term derivative assets | 1.1 | 2.9 |
Derivative Liability | ||
Other current derivative liabilities | 4 | 0.4 |
Other long-term derivative liabilities | 0 | 0 |
Petroleum products contracts | ||
Derivative Asset | ||
Other current derivative assets | 1 | 0.2 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0.1 |
FTRs | ||
Derivative Asset | ||
Other current derivative assets | 7.3 | 5.1 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.6 | 1.5 |
Other long-term derivative assets | 0.3 | 0.5 |
Derivative Liability | ||
Other current derivative liabilities | 1.4 | 1.4 |
Other long-term derivative liabilities | $ 0.7 | $ 0.5 |
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 | 9 Months Ended | ||
Sep. 30, 2017USD ($)MMBTUMWhgal | Sep. 30, 2016USD ($)MMBTUMWhgal | Sep. 30, 2017USD ($)MMBTUMWhgal | Sep. 30, 2016USD ($)MMBTUMWhgal | |
Realized Gain (Loss) on Derivatives, Net | ||||
Gains (Losses) | $ 1.6 | $ 3.3 | $ 6.9 | $ (47.7) |
Natural gas contracts | ||||
Realized Gain (Loss) on Derivatives, Net | ||||
Gains (Losses) | $ (2.1) | $ (3.4) | $ (1.1) | $ (56.9) |
Notional Sales Volumes | ||||
Notional sales volumes | MMBTU | 24.9 | 30.5 | 84.2 | 113.3 |
Petroleum products contracts | ||||
Realized Gain (Loss) on Derivatives, Net | ||||
Gains (Losses) | $ (0.5) | $ (0.4) | $ (1.4) | $ (2.5) |
Notional Sales Volumes | ||||
Notional sales volumes (gallons) | gal | 4.4 | 4.3 | 14.2 | 10.9 |
FTRs | ||||
Realized Gain (Loss) on Derivatives, Net | ||||
Gains (Losses) | $ 4.2 | $ 7.1 | $ 9.4 | $ 11.7 |
Notional Sales Volumes | ||||
Notional sales volumes | MWh | 9.4 | 9.9 | 28 | 24.9 |
DERIVATIVE INSTRUMENTS - BALANC
DERIVATIVE INSTRUMENTS - BALANCE SHEET OFFSETTING (Details) - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Cash collateral | ||
Cash collateral in margin account | $ 24.7 | $ 16.4 |
Cash collateral received | 4.4 | |
Offsetting Derivative Assets | ||
Gross amount recognized on the balance sheet | 15.7 | 41.6 |
Gross amount not offset on the balance sheet | (3) | (4.9) |
Net amount | 12.7 | 36.7 |
Collateral received | 4.4 | |
Offsetting Derivative Liabilities | ||
Gross amount recognized on the balance sheet | 6.1 | 2.4 |
Gross amount not offset on the balance sheet | (3.1) | (0.5) |
Net amount | 3 | 1.9 |
Collateral posted | 0.1 | |
Credit Risk Related Contingent Features | ||
Aggregate fair value of all derivative instruments with specific credit risk-related contingent fearures in a net liability position | 2.3 | $ 0.2 |
Additional collateral that would have been required | $ 0.8 |
GUARANTEES (Details)
GUARANTEES (Details) $ in Millions | Sep. 30, 2017USD ($) |
Guarantees | |
Total guarantees | $ 64.7 |
Guarantees expiring in less than 1 year | 47 |
Guarantees expiring within 1 to 3 years | 7.1 |
Guarantees with expiration over 3 years | 10.6 |
Commodity transactions guarantee | |
Guarantees | |
Total guarantees | 8.1 |
Guarantees expiring in less than 1 year | 8.1 |
Guarantees expiring within 1 to 3 years | 0 |
Guarantees with expiration over 3 years | 0 |
Standby letters of credit | |
Guarantees | |
Total guarantees | 35.8 |
Guarantees expiring in less than 1 year | 28.7 |
Guarantees expiring within 1 to 3 years | 7.1 |
Guarantees with expiration over 3 years | 0 |
Surety bonds | |
Guarantees | |
Total guarantees | 9.7 |
Guarantees expiring in less than 1 year | 9.7 |
Guarantees expiring within 1 to 3 years | 0 |
Guarantees with expiration over 3 years | 0 |
Other guarantees | |
Guarantees | |
Total guarantees | 11.1 |
Guarantees expiring in less than 1 year | 0.5 |
Guarantees expiring within 1 to 3 years | 0 |
Guarantees with expiration over 3 years | 10.6 |
Other indemnifications | |
Guarantees | |
Total guarantees | 11.1 |
Liability related to workers compensation coverage | 10.6 |
Non-Utility Energy Infrastructure | Commodity transactions guarantee | |
Guarantees | |
Total guarantees | $ 8.1 |
EMPLOYEE BENEFITS (Details)
EMPLOYEE BENEFITS (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Components of net periodic benefit cost | ||||
Contributions and payments related to pension and OPEB plans | $ 115.4 | $ 23.5 | ||
Pension Costs | ||||
Components of net periodic benefit cost | ||||
Service cost | $ 11.1 | $ 10.9 | 33.2 | 32.9 |
Interest cost | 30.3 | 33.2 | 91.7 | 99.4 |
Expected return on plan assets | (48.8) | (49) | (146.9) | (147) |
Loss on plan settlement | 2.9 | 0.7 | 8.2 | 14.8 |
Amortization of prior service cost (credit) | 0.7 | 0.9 | 2.2 | 2.6 |
Amortization of net actuarial loss | 21.5 | 20.4 | 64.5 | 61.1 |
Net periodic benefit (credit) cost | 17.7 | 17.1 | 52.9 | 63.8 |
Contributions and payments related to pension and OPEB plans | 109.8 | |||
Estimated future employer contributions for the remainder of the year | 3.8 | 3.8 | ||
Other Postretirement Benefit Costs | ||||
Components of net periodic benefit cost | ||||
Service cost | 6 | 6.5 | 17.9 | 19.6 |
Interest cost | 8.4 | 9.2 | 25.3 | 27.7 |
Expected return on plan assets | (13.6) | (13.2) | (40.9) | (39.6) |
Amortization of prior service cost (credit) | (2.8) | (2.3) | (8.4) | (7) |
Amortization of net actuarial loss | 0.7 | 2.2 | 2.3 | 6.4 |
Net periodic benefit (credit) cost | (1.3) | $ 2.4 | (3.8) | $ 7.1 |
Contributions and payments related to pension and OPEB plans | 5.6 | |||
Estimated future employer contributions for the remainder of the year | $ 3.9 | $ 3.9 |
GOODWILL (Details)
GOODWILL (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 9 Months Ended |
Jun. 30, 2017 | Sep. 30, 2017 | Sep. 30, 2017 | |
Changes to our goodwill balances by segment | |||
Goodwill balance as of January 1, 2017 | $ 3,046.2 | ||
Goodwill balance as of June 30, 2017 | $ 3,053.5 | 3,053.5 | |
Accumulated impairment losses | 0 | 0 | |
Amount of Impairment from Goodwill test | 0 | ||
Bluewater | |||
Changes to our goodwill balances by segment | |||
Acquisition of Bluewater | $ 7.3 | 7.3 | |
Wisconsin | |||
Changes to our goodwill balances by segment | |||
Goodwill balance as of January 1, 2017 | 2,104.3 | ||
Goodwill balance as of June 30, 2017 | 2,104.3 | 2,104.3 | |
Wisconsin | Bluewater | |||
Changes to our goodwill balances by segment | |||
Acquisition of Bluewater | 0 | ||
Illinois | |||
Changes to our goodwill balances by segment | |||
Goodwill balance as of January 1, 2017 | 758.7 | ||
Goodwill balance as of June 30, 2017 | 758.7 | 758.7 | |
Illinois | Bluewater | |||
Changes to our goodwill balances by segment | |||
Acquisition of Bluewater | 0 | ||
Other States | |||
Changes to our goodwill balances by segment | |||
Goodwill balance as of January 1, 2017 | 183.2 | ||
Goodwill balance as of June 30, 2017 | 183.2 | 183.2 | |
Other States | Bluewater | |||
Changes to our goodwill balances by segment | |||
Acquisition of Bluewater | 0 | ||
Non-Utility Energy Infrastructure | |||
Changes to our goodwill balances by segment | |||
Goodwill balance as of January 1, 2017 | 0 | ||
Goodwill balance as of June 30, 2017 | $ 7.3 | 7.3 | |
Non-Utility Energy Infrastructure | Bluewater | |||
Changes to our goodwill balances by segment | |||
Acquisition of Bluewater | $ 7.3 |
INVESTMENT IN AMERICAN TRANSM63
INVESTMENT IN AMERICAN TRANSMISSION COMPANY - CHANGES TO INVESTMENT (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Changes to investment in ATC | |||||
Investment in ATC, balance at beginning of period | $ 1,443.9 | ||||
Add: Earnings from equity method investment | $ 39.2 | $ 38.3 | 122.9 | $ 107.7 | |
Investment in ATC, balance at end of period | $ 1,560.8 | $ 1,560.8 | |||
ATC | |||||
Investment in ATC | |||||
Ownership interest in ATC (as a percent) | 60.00% | 60.00% | |||
Changes to investment in ATC | |||||
Investment in ATC, balance at beginning of period | $ 1,544 | 1,425 | $ 1,443.9 | 1,380.9 | |
Add: Earnings from equity method investment | 39.2 | 38.3 | 122.9 | 107.7 | |
Add: Capital contributions | 12.8 | 15 | 63.3 | 27.1 | |
Acquisition of Integrys's investment in ATC | 0 | 0 | 0 | (1) | |
Add: Adjustment to equity method goodwill | 0 | 0 | 0 | 10.4 | |
Less: Distributions | 35.2 | 25.2 | 69.2 | 71.9 | |
Less: Other | 0 | 0 | 0.1 | 0.1 | |
Investment in ATC, balance at end of period | $ 1,560.8 | $ 1,453.1 | $ 1,560.8 | $ 1,453.1 | |
Dividends Receivable | $ 35.2 |
INVESTMENT IN AMERICAN TRANSM64
INVESTMENT IN AMERICAN TRANSMISSION COMPANY - RELATED PARTY TRANSACTIONS (Details) - ATC - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | |
Investment in ATC | ||||
Charges to ATC for services and construction | $ 4.4 | $ 4.4 | $ 12.3 | $ 12.8 |
Charges from ATC for network transmission services | 87.4 | 89.3 | 262 | 271.4 |
Refund from ATC per FERC ROE order | $ 0 | $ 0 | $ (28.3) | $ 0 |
INVESTMENT IN AMERICAN TRANSM65
INVESTMENT IN AMERICAN TRANSMISSION COMPANY - RELATED PARTY TRANSACTIONS BALANCE SHEET INFORMATION (Details) - ATC - USD ($) $ in Millions | Sep. 30, 2017 | Dec. 31, 2016 |
Investment in ATC | ||
Accounts receivable for services provided to ATC | $ 1.5 | $ 2.2 |
Accounts payable for services received from ATC | $ 29.1 | $ 28.7 |
INVESTMENT IN AMERICAN TRANSM66
INVESTMENT IN AMERICAN TRANSMISSION COMPANY - SUMMARIZED FINANCIAL DATA (Details) - ATC - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2017 | Sep. 30, 2016 | Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Income statement data | |||||
Revenues | $ 171.1 | $ 158.1 | $ 522.4 | $ 476.6 | |
Operating expenses | 85 | 80.2 | 250.1 | 241 | |
Other expense | 27.5 | 23.5 | 79.6 | 71.2 | |
Net income | 58.6 | $ 54.4 | 192.7 | $ 164.4 | |
Balance sheet data | |||||
Current assets | 89 | 89 | $ 75.8 | ||
Noncurrent assets | 4,564.9 | 4,564.9 | 4,312.9 | ||
Total assets | 4,653.9 | 4,653.9 | 4,388.7 | ||
Current liabilities | 772.1 | 772.1 | 495.1 | ||
Long-term debt | 1,740.8 | 1,740.8 | 1,865.3 | ||
Other noncurrent liabilities | 213.8 | 213.8 | 271.5 | ||
Shareholders' equity | 1,927.2 | 1,927.2 | 1,756.8 | ||
Total liabilities and shareholders' equity | $ 4,653.9 | $ 4,653.9 | $ 4,388.7 |
SEGMENT INFORMATION (Details)
SEGMENT INFORMATION (Details) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2017USD ($) | Sep. 30, 2016USD ($) | Sep. 30, 2017USD ($)segment | Sep. 30, 2016USD ($) | |
Segment information | ||||
Number of reportable segments | segment | 6 | |||
Revenues | $ 1,657.5 | $ 1,712.5 | $ 5,593.5 | $ 5,509.3 |
Other operation and maintenance | 471.7 | 517.5 | 1,453.4 | 1,571 |
Depreciation and amortization | 201.2 | 191.6 | 593.5 | 569.5 |
Operating income (loss) | 393.6 | 399 | 1,373.1 | 1,320.4 |
Equity in earnings of transmission affiliate | 39.2 | 38.3 | 122.9 | 107.7 |
Interest expense | 103.8 | 99.1 | 310.4 | 300.1 |
Intersegment revenues | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0 |
Electric Transmission | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0 |
Other operation and maintenance | 0 | 0 | 0 | 0 |
Depreciation and amortization | 0 | 0 | 0 | 0 |
Operating income (loss) | 0 | 0 | 0 | 0 |
Equity in earnings of transmission affiliate | 39.2 | 38.3 | 122.9 | 107.7 |
Interest expense | 0 | 0 | 0 | 0 |
Electric Transmission | Intersegment revenues | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0 |
Non-Utility Energy Infrastructure | ||||
Segment information | ||||
Revenues | 13.6 | 6.2 | 26.1 | 18.7 |
Other operation and maintenance | 1.5 | 0.4 | 4.6 | 3.5 |
Depreciation and amortization | 18.2 | 17.1 | 53.1 | 51.1 |
Operating income (loss) | 103.4 | 93.7 | 299.5 | 281.1 |
Equity in earnings of transmission affiliate | 0 | 0 | 0 | 0 |
Interest expense | 16.2 | 15.6 | 46.7 | 46.8 |
Non-Utility Energy Infrastructure | Intersegment revenues | ||||
Segment information | ||||
Revenues | 111.6 | 105 | 333.2 | 317.1 |
Corporate and Other | ||||
Segment information | ||||
Revenues | 5.6 | 4 | 11.7 | 20.3 |
Other operation and maintenance | (1.5) | (3.2) | (0.3) | (13) |
Depreciation and amortization | 6.3 | 11.3 | 18.3 | 33.4 |
Operating income (loss) | 1.1 | (4.5) | (6.3) | (6.4) |
Equity in earnings of transmission affiliate | 0 | 0 | 0 | 0 |
Interest expense | 25.4 | 29.7 | 81.3 | 91.2 |
Corporate and Other | Intersegment revenues | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0 |
Reconciling Eliminations | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0 |
Other operation and maintenance | (109) | (105) | (330.6) | (317.4) |
Depreciation and amortization | 0 | 0 | 0 | 0 |
Operating income (loss) | 0 | 0 | 0 | 0 |
Equity in earnings of transmission affiliate | 0 | 0 | 0 | 0 |
Interest expense | 0.4 | (2) | (2.5) | (6.7) |
Reconciling Eliminations | Intersegment revenues | ||||
Segment information | ||||
Revenues | (111.6) | (105) | (333.2) | (317.4) |
Public Utility | ||||
Segment information | ||||
Revenues | 1,638.3 | 1,702.3 | 5,555.7 | 5,470.3 |
Other operation and maintenance | 580.7 | 625.3 | 1,779.7 | 1,897.9 |
Depreciation and amortization | 176.7 | 163.2 | 522.1 | 485 |
Operating income (loss) | 289.1 | 309.8 | 1,079.9 | 1,045.7 |
Equity in earnings of transmission affiliate | 0 | 0 | 0 | 0 |
Interest expense | 61.8 | 55.8 | 184.9 | 168.8 |
Public Utility | Intersegment revenues | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0.3 |
Public Utility | Wisconsin | ||||
Segment information | ||||
Revenues | 1,401.3 | 1,470.6 | 4,316.6 | 4,354.9 |
Other operation and maintenance | 458.3 | 498.2 | 1,379.9 | 1,477.3 |
Depreciation and amortization | 131.5 | 124.5 | 391.1 | 370.1 |
Operating income (loss) | 279.7 | 299.1 | 835.6 | 841.3 |
Equity in earnings of transmission affiliate | 0 | 0 | 0 | 0 |
Interest expense | 48.5 | 44.6 | 145.4 | 133.5 |
Public Utility | Wisconsin | Intersegment revenues | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0.3 |
Public Utility | Illinois | ||||
Segment information | ||||
Revenues | 187.2 | 181.8 | 965.7 | 853.1 |
Other operation and maintenance | 100.8 | 105.9 | 326.6 | 340 |
Depreciation and amortization | 38.9 | 33.5 | 112.6 | 99.4 |
Operating income (loss) | 12.5 | 11.7 | 209.3 | 171.3 |
Equity in earnings of transmission affiliate | 0 | 0 | 0 | 0 |
Interest expense | 11 | 9.3 | 33 | 28.8 |
Public Utility | Illinois | Intersegment revenues | ||||
Segment information | ||||
Revenues | 0 | 0 | 0 | 0 |
Public Utility | Other States | ||||
Segment information | ||||
Revenues | 49.8 | 49.9 | 273.4 | 262.3 |
Other operation and maintenance | 21.6 | 21.2 | 73.2 | 80.6 |
Depreciation and amortization | 6.3 | 5.2 | 18.4 | 15.5 |
Operating income (loss) | (3.1) | (1) | 35 | 33.1 |
Equity in earnings of transmission affiliate | 0 | 0 | 0 | 0 |
Interest expense | 2.3 | 1.9 | 6.5 | 6.5 |
Public Utility | Other States | Intersegment revenues | ||||
Segment information | ||||
Revenues | $ 0 | 0 | $ 0 | 0 |
ATC | ||||
Segment information | ||||
Equity method investment, ownership interest (as a percent) | 60.00% | 60.00% | ||
Equity in earnings of transmission affiliate | $ 39.2 | $ 38.3 | $ 122.9 | $ 107.7 |
ATC | Electric Transmission | ||||
Segment information | ||||
Equity method investment, ownership interest (as a percent) | 60.00% | 60.00% |
VARIABLE INTEREST ENTITIES (Det
VARIABLE INTEREST ENTITIES (Details) $ in Millions | 9 Months Ended | ||
Sep. 30, 2017USD ($)MW | Sep. 30, 2016USD ($) | Dec. 31, 2016USD ($) | |
Variable interest entities | |||
Equity investment in ATC | $ 1,560.8 | $ 1,443.9 | |
ATC | |||
Variable interest entities | |||
Ownership interest in ATC (as a percent) | 60.00% | ||
Equity investment in ATC | $ 1,560.8 | 1,443.9 | |
ATC distributions receivable | 35.2 | ||
Accounts payable due to ATC | $ 29.1 | $ 28.7 | |
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 | 74.9 | ||
Total capacity and lease payments | $ 13.5 | $ 40.5 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Sep. 30, 2017USD ($) |
Minimum future commitments for purchase obligations | |
Purchase obligations | $ 11,863.2 |
COMMITMENTS AND CONTINGENCIES70
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions | 1 Months Ended | 9 Months Ended | 12 Months Ended | ||
Oct. 31, 2014compliance_option | Sep. 30, 2017USD ($) | Dec. 31, 2015 | Dec. 31, 2016USD ($) | Sep. 30, 2016Case | |
Climate Change | Electric | |||||
Air quality | |||||
Number of legal cases heard by a court | Case | 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 | compliance_option | 7 | ||||
Steam Electric Effluent Limitation Guidelines | Electric | |||||
Water quality | |||||
Renewal period for facility permits | 5 years | ||||
Steam Electric Effluent Limitation Guidelines | Electric | Minimum | |||||
Water quality | |||||
Expected cost to achieve required emissions reductions | $ 80 | ||||
Steam Electric Effluent Limitation Guidelines | Electric | Maximum | |||||
Water quality | |||||
Expected cost to achieve required emissions reductions | 110 | ||||
Manufactured Gas Plant Remediation | Natural gas | |||||
Manufactured gas plant remediation | |||||
Regulatory assets recorded for remediation of manufactured gas plant sites | 683.3 | $ 702.7 | |||
Reserves recorded for remediation of manufactured gas plant sites | $ 617.5 | $ 633.4 |
SUPPLEMENTAL CASH FLOW INFORM71
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2017 | Sep. 30, 2016 | Dec. 31, 2016 | |
Supplemental Cash Flow Information | |||
Cash (paid) for interest, net of amount capitalized | $ (258.2) | $ (260.7) | |
Cash received for income taxes, net | 7.3 | 11.7 | |
Significant noncash transactions: | |||
Accounts payable related to construction costs | 172.7 | 113.1 | |
Increase (decease) in restricted cash from the sale (purchase) of investments held in the rabbi trust | 4.6 | (4.5) | |
Portion of Bostco real estate holdings sale financed with note receivable | 7 | 0 | |
Amortization of deferred revenue | 18.7 | $ 18.5 | |
Long-term restricted cash | $ 20.4 | $ 33.6 |
REGULATORY ENVIRONMENT (Details
REGULATORY ENVIRONMENT (Details) $ in Millions | 1 Months Ended | |||||
Oct. 31, 2017USD ($)MW | Sep. 30, 2017USD ($)utilityAssurance | Jan. 31, 2017 | Oct. 31, 2016USD ($) | Apr. 30, 2015USD ($) | Jun. 30, 2017USD ($) | |
WE | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.20% | |||||
WG | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.30% | |||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.00% | |||||
Authorized revenue requirement for the ReACT project | $ 275 | |||||
AFUDC | 51 | |||||
Estimated cost of the ReACT project, excluding AFUDC | $ 342 | |||||
WE, WG, and WPS | Public Service Commission of Wisconsin (PSCW) | Natural gas storage facilities in Michigan | ||||||
Regulatory environment | ||||||
Percentage of natural gas storage needs provided by the facilities | 33.33% | |||||
WE, WG, and WPS | Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 rates | ||||||
Regulatory environment | ||||||
Number of utilities with earnings sharing mechanism | utility | 3 | |||||
Percentage of first 50 basis points of additional utility earnings shared with customers | 50.00% | |||||
Return on equity in excess of authorized amount (as a percent) | 0.50% | |||||
PGL | Illinois Commerce Commission (ICC) | ||||||
Regulatory environment | ||||||
Amount of assurance that PGL's QIP rider costs will be recoverable | Assurance | 0 | |||||
MERC | Minnesota Public Utilities Commission (MPUC) | 2018 rates | Natural gas rates | Subsequent event | ||||||
Regulatory environment | ||||||
Requested rate increase | $ 12.6 | |||||
Requested rate increase (as a percent) | 5.05% | |||||
Requested return on equity (as a percent) | 10.30% | |||||
Requested common equity component average (as a percent) | 50.90% | |||||
MERC | Minnesota Public Utilities Commission (MPUC) | 2016 rates | Natural gas rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 9.11% | |||||
Approved rate increase | $ 6.8 | |||||
Approved rate increase (as a percent) | 3.00% | |||||
Approved common equity component average (as a percent) | 50.32% | |||||
Number of years decoupling mechanism authorized for use | 3 years | |||||
Interim rate refund | $ 4.1 | |||||
UMERC | Subsequent event | ||||||
Regulatory environment | ||||||
Capacity of natural gas-fired generation facility (in megawatts) | MW | 180 | |||||
UMERC | Michigan Public Service Commission (MPSC) | Subsequent event | ||||||
Regulatory environment | ||||||
Term of electric power purchase agreement (in years) | 20 years | |||||
Capacity of natural gas-fired generation facility (in megawatts) | MW | 180 | |||||
Estimated cost of constructing a power plant | $ 265.7 | |||||
Estimated cost of constructing a power plant, including AFUDC | $ 277 | |||||
Portion of the power plant costs recoverable from Tilden Mining Company (as a percent) | 50.00% | |||||
Portion of the power plant costs recoverable from utility customers (as a percent) | 50.00% | |||||
UMERC | Michigan Public Service Commission (MPSC) | 2015 rates | Electric rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.20% | |||||
Approved rate increase | $ 4 | |||||
Approved common equity component average (as a percent) | 50.48% | |||||
Period of rate implementation (in years) | 3 years |