Document and Enttity Informatio
Document and Enttity Information | 3 Months Ended |
Mar. 31, 2016shares | |
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 | Mar. 31, 2016 |
Document Fiscal Year Focus | 2,016 |
Document Fiscal Period Focus | Q1 |
Amendment Flag | false |
Entity Common Stock, Shares Outstanding | 315,647,207 |
Condensed Consolidated Income S
Condensed Consolidated Income Statements (Unaudited) - USD ($) shares in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Income Statement [Abstract] | ||
Operating revenues | $ 2,194.8 | $ 1,387.9 |
Operating expenses | ||
Cost of sales | 838.9 | 613.9 |
Other operation and maintenance | 531.5 | 280.7 |
Depreciation and amortization | 187.9 | 102.6 |
Property and revenue taxes | 47.2 | 31.9 |
Total operating expenses | 1,605.5 | 1,029.1 |
Operating income | 589.3 | 358.8 |
Equity in earnings of transmission affiliate | 38.5 | 16.1 |
Other income, net | 32.7 | 3 |
Interest expense | 100.9 | 59.4 |
Other expense | (29.7) | (40.3) |
Income before income taxes | 559.6 | 318.5 |
Income tax expense | 213.1 | 122.4 |
Net income | 346.5 | 196.1 |
Preferred stock dividends of subsidiary | 0.3 | 0.3 |
Net income attributed to common shareholders | $ 346.2 | $ 195.8 |
Earnings per share | ||
Basic (in dollars per share) | $ 1.10 | $ 0.87 |
Diluted (in dollars per share) | $ 1.09 | $ 0.86 |
Weighted average common shares outstanding | ||
Basic (in shares) | 315.7 | 225.5 |
Diluted (in shares) | 317.1 | 227.3 |
Dividends per share of common stock (in dollars per share) | $ 0.495 | $ 0.4225 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Statement of Comprehensive Income [Abstract] | ||
Net income | $ 346.5 | $ 196.1 |
Derivatives accounted for as cash flow hedges | ||
Reclassification of gains to net income, net of tax | (0.3) | 0 |
Cash flow hedges, net | (0.3) | 0 |
Other comprehensive loss, net of tax | (0.3) | 0 |
Comprehensive income | 346.2 | 196.1 |
Preferred stock dividends of subsidiary | 0.3 | 0.3 |
Comprehensive income attributed to common shareholders | $ 345.9 | $ 195.8 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Property, plant, and equipment | ||
In service | $ 26,523.3 | $ 26,249.5 |
Accumulated depreciation | (8,005.9) | (7,919.1) |
In service, net | 18,517.4 | 18,330.4 |
Construction work in progress | 706.6 | 822.9 |
Leased facilities, net | 35 | 36.4 |
Net property, plant, and equipment | 19,259 | 19,189.7 |
Investments | ||
Equity investment in transmission affiliate | 1,422.5 | 1,380.9 |
Other | 87.5 | 85.8 |
Total investments | 1,510 | 1,466.7 |
Current assets | ||
Cash and cash equivalents | 34.7 | 49.8 |
Accounts receivable and unbilled revenues, net of reserves of $114.3 and $113.3, respectively | 1,088.1 | 1,028.6 |
Materials, supplies, and inventories | 470.7 | 687 |
Assets held for sale | 0 | 96.8 |
Prepayments | 243.4 | 285.8 |
Other | 59.5 | 58.8 |
Total current assets | 1,896.4 | 2,206.8 |
Deferred charges and other assets | ||
Regulatory assets | 3,060.8 | 3,064.6 |
Goodwill | 2,999.1 | 3,023.5 |
Other | 379.3 | 403.9 |
Total deferred charges and other assets | 6,439.2 | 6,492 |
Total assets | 29,104.6 | 29,355.2 |
Capitalization | ||
Common stock – $.01 par value; 325,000,000 shares authorized; 315,647,207 and 315,683,496 shares outstanding, respectively | 3.2 | 3.2 |
Additional paid in capital | 4,321.1 | 4,347.2 |
Retained earnings | 4,489.7 | 4,299.8 |
Accumulated other comprehensive income | 4.3 | 4.6 |
Preferred Stock, Value, Issued | 30.4 | 30.4 |
Long-term debt | 8,955.8 | 9,124.1 |
Total capitalization | 17,804.5 | 17,809.3 |
Current liabilities | ||
Current portion of long-term debt | 152.4 | 157.7 |
Short-term debt | 896.4 | 1,095 |
Accounts payable | 584.4 | 815.4 |
Accrued payroll and benefits | 102.7 | 169.7 |
Accrued interest | 118.6 | 67.4 |
Other | 375.3 | 403.8 |
Total current liabilities | 2,229.8 | 2,709 |
Deferred credits and other liabilities | ||
Regulatory liabilities | 1,411.8 | 1,392.2 |
Deferred income taxes | 4,856.5 | 4,622.3 |
Deferred revenue, net | 576.1 | 579.4 |
Pension and other postretirement benefit obligations | 541.1 | 543.1 |
Environmental remediation | 617.6 | 628.2 |
Other | 1,067.2 | 1,071.7 |
Total deferred credits and other liabilities | $ 9,070.3 | $ 8,836.9 |
Commitments and contingencies (Note 16) | ||
Total capitalization and liabilities | $ 29,104.6 | $ 29,355.2 |
Condensed Consolidated Balance5
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Allowance for Doubtful Accounts Receivable, Current | $ 114.3 | $ 113.3 |
Common Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 |
Common Stock, Shares Authorized | 325,000,000 | 325,000,000 |
Common Stock, Shares, Outstanding | 315,647,207 | 315,683,496 |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Operating Activities | ||
Net income | $ 346.5 | $ 196.1 |
Reconciliation to cash provided by operating activities | ||
Depreciation and amortization | 191.9 | 107.3 |
Deferred income taxes and investment tax credits, net | 214.6 | 106.6 |
Contributions and payments related to pension and OPEB plans | (15.1) | (103.7) |
Equity income in transmission affiliate, net of distributions | (23.4) | (5.7) |
Change in - | ||
Accounts receivable and unbilled revenues | (48.6) | (28) |
Materials, supplies, and inventories | 217.2 | 110.9 |
Other current assets | (63.7) | 44.5 |
Accounts payable | (123.7) | (71.3) |
Accrued taxes, net | 89.6 | (6.5) |
Other current liabilities | (32.9) | 28.1 |
Other, net | (56.5) | (48.3) |
Net cash provided by operating activities | 695.9 | 330 |
Investing Activities | ||
Capital expenditures | (312) | (153.2) |
Investment in transmission affiliate | (9) | (1.3) |
Proceeds from sale of businesses | 106.5 | 0 |
Withdrawal of restricted cash from Rabbi trust for qualifying payments | 21 | 0 |
Other, net | 5.1 | (1.8) |
Net cash used in investing activities | (188.4) | (156.3) |
Financing Activities | ||
Exercise of stock options | 21.4 | 8.4 |
Purchase of common stock | (59.6) | (23.4) |
Dividends paid on common stock | (156.2) | (95.3) |
Retirement of long-term debt | (139.4) | (9.3) |
Change in short-term debt | (198.6) | (54.6) |
Other, net | 9.8 | 3.8 |
Net cash used in financing activities | (522.6) | (170.4) |
Net change in cash and cash equivalents | (15.1) | 3.3 |
Cash and cash equivalents at beginning of period | 49.8 | 61.9 |
Cash and cash equivalents at end of period | $ 34.7 | $ 65.2 |
General Information
General Information | 3 Months Ended |
Mar. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL INFORMATION | GENERAL INFORMATION On June 29, 2015 , Wisconsin Energy Corporation acquired Integrys and changed its name to WEC Energy Group, Inc. WEC Energy Group serves approximately 1.6 million electric customers and 2.8 million natural gas customers, and it owns approximately 60% of ATC. See Note 2, Acquisition, for more information . 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, 2015 . Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2016 , are not necessarily indicative of expected results for 2016 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. Reclassifications On the income statements for the quarter ended March 31, 2015, we reclassified $2.5 million from treasury grant to depreciation and amortization. We also reclassified an insignificant amount from interest expense to preferred stock dividends of subsidiaries on the income statements for the quarter ended March 31, 2015. These reclassifications were made to be consistent with the current period presentation on the income statements. On the statements of cash flows for the quarter ended March 31, 2015, we reclassified $0.9 million from depreciation and amortization to other operating activities. In addition, we reclassified $3.7 million of non-qualified pension and OPEB contributions from other operating activities to contributions and payments related to pension and OPEB plans on the statements of cash flows for the quarter ended March 31, 2015. We also reclassified $3.7 million from other investing activities to capital expenditures on the statements of cash flows for the quarter ended March 31, 2015. An insignificant amount of preferred stock dividends of subsidiaries was also reclassified from other financing activities to net income on the statements of cash flows for the quarter ended March 31, 2015. These reclassifications were made to be consistent with the current period presentation on the statements of cash flows. During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 14, Segment Information, for more information on our business segments. |
Acquisition
Acquisition | 3 Months Ended |
Mar. 31, 2016 | |
Business Combinations [Abstract] | |
ACQUISITION | ACQUISITION On June 29, 2015 , Wisconsin Energy Corporation acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. Allocation of Purchase Price The Integrys assets acquired and liabilities assumed were measured at estimated fair value in accordance with the accounting guidance under the Business Combinations Topic in the FASB ASC. Substantially all of Integrys's operations are subject to the rate-setting authority of federal and state regulatory commissions. These operations are accounted for following the accounting guidance under the Regulated Operations Topic of the FASB ASC. The underlying assets and liabilities of ATC are also regulated by the FERC. The fair values of Integrys's assets and liabilities subject to rate-setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The goodwill reflects the value paid for the increased scale and efficiencies as a result of the combination. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill. See Note 12, Goodwill , for the allocation of goodwill to our reportable segments. The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. In the first quarter of 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF. The allocation is subject to change during the remainder of the measurement period, which ends one year from the acquisition date, as we obtain additional information, including with respect to certain regulatory and legal matters. (in millions) Current assets $ 1,060.7 Net property, plant, and equipment 7,107.4 Investments * 1,071.8 Goodwill 2,557.2 Deferred charges and other assets, excluding goodwill 1,758.5 Current liabilities, including current maturities of long-term debt (1,299.1 ) Deferred credits and other liabilities (3,678.7 ) Long-term debt (2,943.6 ) Preferred stock of subsidiary (51.1 ) Total purchase price $ 5,583.1 * Includes equity method goodwill related to Integrys's investment in ATC. Pro Forma Information The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results. The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs. (in millions, except per share amounts) Three Months Ended March 31, 2015 Unaudited Pro Forma Financial Information Operating Revenues $ 2,550.9 Net Income $ 329.9 Earnings per share (Basic) $ 1.05 Earnings per share (Diluted) $ 1.04 Impact of Acquisition In connection with the acquisition, WEC Energy Group and its subsidiaries recorded pre-tax acquisition costs of $8.8 million during the three months ended March 31 , 2015 . These costs consisted of professional fees and other miscellaneous costs. They were recorded in the other operation and maintenance line item on the income statement. Acquisition costs recorded during the three months ended March 31 , 2016 were not significant. Our revenues for the three months ended March 31, 2016 , include revenues attributable to Integrys of $983.1 million . Included in our net income for the three months ended March 31, 2016 , is net income attributable to Integrys of $158.2 million . |
Dispositions
Dispositions | 3 Months Ended |
Mar. 31, 2016 | |
Discontinued Operations and Disposal Groups [Abstract] | |
DISPOSITIONS | DISPOSITIONS Corporate and Other Segment – 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 sale in the first quarter of 2016, as ITF's assets and liabilities were adjusted to fair value through purchase accounting. The sale of ITF met the criteria to qualify as held for sale at December 31, 2015, but did not meet the requirements to qualify as a discontinued operation. 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 will not have a major effect on our operations and financial results. The pre-tax profit or loss of this individually significant component was not material for the quarter ended March 31, 2016. The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31: (in millions) 2015 Property, plant, and equipment $ 37.2 Accounts receivable and unbilled revenues 34.9 Materials, supplies, and inventories 18.4 Other current assets 2.6 Other long-term assets 3.7 Total assets $ 96.8 Accounts payable $ 12.9 Accrued payroll and benefits 2.4 Other current liabilities 4.5 Pension and OPEB obligations 1.2 Other long-term liabilities 0.6 Total liabilities * $ 21.6 * Included in other current liabilities on our balance sheet. |
Common Equity
Common Equity | 3 Months Ended |
Mar. 31, 2016 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation Plans During the first quarter of 2016, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees under our and Integrys's normal schedule of awarding long-term incentive compensation: Award Type Number of Awards Stock options (1) 752,085 Restricted shares (2) 140,897 Performance units 283,505 (1) Stock options awarded had a weighted-average exercise price of $51.80 and a weighted-average grant date fair value of $5.03 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $53.40 per share. 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 2015 Annual Report on Form 10-K for additional information on these and other restrictions. We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future. |
Short-term Debt and Lines of Cr
Short-term Debt and Lines of Credit | 3 Months Ended |
Mar. 31, 2016 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates: (in millions, except percentages) March 31, 2016 December 31, 2015 Commercial paper Amount outstanding $ 896.4 $ 1,095.0 Weighted-average interest rate on amounts outstanding 0.61 % 0.68 % Our average amount of commercial paper borrowings based on daily outstanding balances during the three months ended March 31, 2016 , was $1,043.7 million with a weighted-average interest rate during the period of 0.63% . The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including remaining available capacity under these facilities: (in millions) Maturity March 31, 2016 WEC Energy Group December 2020 $ 1,050.0 WE December 2020 500.0 WPS * December 2016 250.0 WG December 2020 350.0 PGL December 2020 350.0 Total short-term credit capacity $ 2,500.0 Less: Letters of credit issued inside credit facilities $ 18.0 Commercial paper outstanding 896.4 Available capacity under existing agreements $ 1,585.6 * In March 2016, WPS requested approval from the PSCW to extend the maturity through December 2020. |
Long Term Debt
Long Term Debt | 3 Months Ended |
Mar. 31, 2016 | |
Long-term Debt, Unclassified [Abstract] | |
Long Term Debt | LONG-TERM DEBT In February 2016, Integrys repurchased and retired $154.9 million aggregate principal amount of its 6.11% Junior Notes for a purchase price of $128.6 million , plus accrued and unpaid interest, through a modified “dutch auction” tender offer. The gain associated with this repurchase is included in other income, net on our income statement. Effective December 1, 2016, the remaining $114.9 million aggregate principal amount of the 6.11% Junior Notes will bear interest at the three-month London Interbank Offered Rate plus 2.12% and will reset quarterly. In connection with this transaction, Integrys issued approximately $66.4 million of additional common stock to WEC Energy Group in satisfaction of its obligations under a replacement capital covenant relating to the 6.11% Junior Notes. |
Materials, Supplies, and Invent
Materials, Supplies, and Inventories | 3 Months Ended |
Mar. 31, 2016 | |
Inventory Disclosure [Abstract] | |
MATERIALS, SUPPLIES, AND INVENTORIES | MATERIALS, SUPPLIES, AND INVENTORIES Our inventory consisted of: (in millions) March 31, 2016 December 31, 2015 Materials and supplies $ 217.8 $ 219.2 Fossil fuel 163.4 183.7 Natural gas in storage 89.5 284.1 Total $ 470.7 $ 687.0 PGL and NSG price natural gas storage injections at the calendar year average of the costs of natural gas supply purchased. Withdrawals from storage are priced on the last-in, first-out (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. The amounts were as follows at March 31, 2016 : (in millions) Balance Sheet Presentation PGL NSG Temporary LIFO liquidation debit Other current assets $ 17.6 $ — Temporary LIFO liquidation credit Other current liabilities — 6.0 Due to seasonality requirements, PGL and NSG expect these interim reductions in LIFO layers to be replenished by year end. Substantially all other materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. We recognize transfers at their value as of the end of the reporting period. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis. The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: March 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 0.6 $ 1.7 $ — $ 2.3 FTRs — — 1.1 1.1 Petroleum products contracts 1.1 — — 1.1 Coal contracts — 1.6 — 1.6 Total derivative assets $ 1.7 $ 3.3 $ 1.1 $ 6.1 Investments held in rabbi trust $ 41.7 $ — $ — $ 41.7 Liabilities Derivative liabilities Natural gas contracts $ 8.8 $ 21.7 $ — $ 30.5 Petroleum products contracts 3.8 — — 3.8 Coal contracts — 14.7 — 14.7 Total derivative liabilities $ 12.6 $ 36.4 $ — $ 49.0 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 1.6 $ 1.5 $ — $ 3.1 FTRs — — 3.6 3.6 Petroleum products contracts 1.2 — — 1.2 Coal contracts — 2.0 — 2.0 Total derivative assets $ 2.8 $ 3.5 $ 3.6 $ 9.9 Investments held in rabbi trust $ 39.8 $ — $ — $ 39.8 Liabilities Derivative liabilities Natural gas contracts $ 16.5 $ 25.3 $ — $ 41.8 Petroleum products contracts 4.9 — — 4.9 Coal contracts — 12.3 — 12.3 Total derivative liabilities $ 21.4 $ 37.6 $ — $ 59.0 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 March 31 (in millions) 2016 2015 Balance at the beginning of the period $ 3.6 $ 7.0 Realized and unrealized losses (0.2 ) — Sales (0.1 ) — Settlements (2.2 ) (3.7 ) Balance at the end of the period $ 1.1 $ 3.3 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: March 31, 2016 December 31, 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.6 $ 30.4 $ 27.3 Long-term debt, including current portion * $ 9,055.4 $ 9,790.5 $ 9,221.9 $ 9,681.0 * The carrying amount of long-term debt excludes capital lease obligations of $52.8 million and $59.9 million at March 31, 2016, and December 31, 2015, respectively. Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a perpetual 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. |
Derivative Instruments
Derivative Instruments | 3 Months Ended |
Mar. 31, 2016 | |
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: March 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 1.7 $ 28.7 $ 2.6 $ 38.5 Petroleum products contracts 0.9 3.3 0.9 3.8 FTRs 1.1 — 3.6 — Coal contracts 1.6 10.3 1.7 6.7 Total other current * $ 5.3 $ 42.3 $ 8.8 $ 49.0 Other long-term Natural gas contracts $ 0.6 $ 1.8 $ 0.5 $ 3.3 Petroleum products contracts 0.2 0.5 0.3 1.1 Coal contracts — 4.4 0.3 5.6 Total other long-term * $ 0.8 $ 6.7 $ 1.1 $ 10.0 Total $ 6.1 $ 49.0 $ 9.9 $ 59.0 * On our balance sheets, we classify derivative assets and liabilities as current or 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 gains (losses) were as follows: Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 (in millions) Volume Gains (Losses) Volume Gains (Losses) Natural gas contracts 50.1 Dth $ (33.5 ) 13.3 Dth $ (7.1 ) Petroleum products contracts 3.0 gallons (1.1 ) 0.9 gallons (0.1 ) FTRs 7.6 MWh 3.0 6.2 MWh 2.1 Total $ (31.6 ) $ (5.1 ) 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 March 31, 2016 , and December 31, 2015 , we had posted collateral of $30.5 million and $42.3 million , respectively, in our margin accounts. These amounts were recorded on the balance sheets in other current assets. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet: March 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 6.1 $ 49.0 $ 9.9 $ 59.0 Gross amount not offset on balance sheet * (1.6 ) (13.6 ) (3.0 ) (22.5 ) Net amount $ 4.5 $ 35.4 $ 6.9 $ 36.5 * Includes cash collateral posted of $12.0 million and $19.5 million as of March 31, 2016 , and December 31, 2015 , respectively. 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 liability position was $21.4 million and $23.8 million at March 31, 2016 , and December 31, 2015 , respectively. At March 31, 2016 , and December 31, 2015 , we had not posted any cash 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 March 31, 2016 , and December 31, 2015 , we would have been required to post collateral of $20.4 million and $18.0 million , respectively. During 2015 , we settled several forward interest rate swap agreements entered into to mitigate interest risk associated with the issuance of $1.2 billion of long-term debt related to the acquisition of Integrys. As these agreements qualified for cash flow hedging accounting treatment, the payments of $19.0 million received upon settlement of these agreements were deferred in accumulated other comprehensive income and are being amortized as a decrease to interest expense over the periods in which the interest costs are recognized in earnings. During the three months ended March 31, 2016 , we reclassified $0.5 million of forward interest rate swap agreement settlements deferred in accumulated other comprehensive income as a reduction to interest expense. We estimate that during the next twelve months, $2.2 million will be reclassified from accumulated other comprehensive income as a reduction to interest expense. |
Guarantees
Guarantees | 3 Months Ended |
Mar. 31, 2016 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEES The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at March 31, 2016 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting commodity transactions of subsidiaries (1) $ 168.7 $ 89.7 $ — $ 79.0 Standby letters of credit (2) 28.3 18.7 9.4 0.2 Surety bonds (3) 10.2 10.2 — — Other guarantees (4) 58.9 20.6 0.1 38.2 Total guarantees $ 266.1 $ 139.2 $ 9.5 $ 117.4 (1) Consists of (a) $5.0 million and $11.0 million to support the business operations of WBS and PDL, respectively; and (b) $114.8 million and $37.9 million related to natural gas supply at MERC and MGU, respectively. These amounts are not reflected on our balance sheets. (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 (a) $19.0 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party; (b) $20.0 million for an interconnection agreement between WPS and ATC; (c) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys; and (d) $9.9 million related to other indemnifications. The amounts discussed in items (a) and (b) are not reflected on our balance sheets. An insignificant liability was recorded for item (c). In addition, a liability of $9.2 million related to workers compensation coverage was recorded for item (d). |
Employee Benefits
Employee Benefits | 3 Months Ended |
Mar. 31, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS Defined Benefit Plans The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Our pension and OPEB costs for the three months ended March 31, 2016 , include costs attributable to the Integrys pension and OPEB plans. The terms and conditions of the legacy company plans have not changed since the acquisition. Pension Costs Three Months Ended March 31 (in millions) 2016 2015 Service cost $ 11.3 $ 3.9 Interest cost 33.2 15.2 Expected return on plan assets (49.0 ) (25.8 ) Amortization of prior service cost 0.9 0.5 Amortization of net actuarial loss 20.5 11.6 Net periodic benefit cost $ 16.9 $ 5.4 OPEB Costs Three Months Ended March 31 (in millions) 2016 2015 Service cost $ 6.7 $ 2.6 Interest cost 9.2 4.2 Expected return on plan assets (13.1 ) (5.9 ) Amortization of prior service credit (2.3 ) (0.3 ) Amortization of net actuarial loss 2.3 0.5 Net periodic benefit cost $ 2.8 $ 1.1 We did not make any contributions to our qualified pension plans during the first three months of 2016. During the three months ended March 31, 2016, we made payments of $13.7 million related to our non-qualified pension plans and $1.4 million to our OPEB plans. We expect to make payments of $8.5 million to our pension plans and $10.8 million to our OPEB plans during the remainder of 2016, dependent upon various factors affecting us, including our liquidity position and possible tax law changes. |
Goodwill
Goodwill | 3 Months Ended |
Mar. 31, 2016 | |
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 three months ended March 31, 2016 : (in millions) Wisconsin Illinois Other States Total Goodwill balance as of January 1, 2016 $ 2,109.5 $ 731.2 $ 182.8 $ 3,023.5 Adjustment to Integrys purchase price allocation (12.4 ) (8.5 ) (3.5 ) (24.4 ) Goodwill balance as of March 31, 2016 (1) $ 2,097.1 (2) $ 722.7 (3) $ 179.3 (3) $ 2,999.1 (1) We had no accumulated impairment losses related to our goodwill as of March 31, 2016 . (2) Of this amount, $1,655.2 million relates to the acquisition of Integrys. (3) Total amount relates to the acquisition of Integrys. |
Investment in American Transmis
Investment in American Transmission Company | 3 Months Ended |
Mar. 31, 2016 | |
Equity Method Investments and Joint Ventures [Abstract] | |
INVESTMENT IN AMERICAN TRANSMISSION COMPANY | INVESTMENT IN AMERICAN TRANSMISSION COMPANY Due to the acquisition of Integrys on June 29, 2015, our ownership of ATC increased from 26.2% to approximately 60% . ATC is 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 March 31 (in millions) 2016 2015 Balance at beginning of period $ 1,380.9 $ 424.1 Add: Earnings from equity method investment 38.5 16.1 Add: Capital contributions 9.0 1.3 Add: Adjustment to equity method goodwill 9.3 — Less: Distributions received 15.1 10.4 Less: Other 0.1 — Balance at end of period $ 1,422.5 $ 431.1 We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed to us 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 March 31 (in millions) 2016 2015 Charges to ATC for services and construction $ 4.1 $ 2.5 Charges from ATC for network transmission services 100.8 59.6 Our balance sheets included the following receivables and payables related to ATC: (in millions) March 31, 2016 December 31, 2015 Accounts receivable Services provided to ATC $ 2.0 $ 1.0 Accounts payable Services received from ATC 30.4 28.3 Summarized financial data for ATC is included in the following tables: Three Months Ended March 31 (in millions) 2016 2015 Income statement data Revenues $ 164.2 $ 152.4 Operating expenses 79.1 80.0 Other expense 24.0 24.4 Net income $ 61.1 $ 48.0 (in millions) March 31, 2016 December 31, 2015 Balance sheet data Current assets $ 88.7 $ 80.5 Noncurrent assets 4,022.1 3,948.3 Total assets $ 4,110.8 $ 4,028.8 Current liabilities $ 337.8 $ 330.3 Long-term debt 1,790.9 1,790.7 Other noncurrent liabilities 265.8 245.0 Shareholders' equity 1,716.3 1,662.8 Total liabilities and shareholders' equity $ 4,110.8 $ 4,028.8 |
Segment Information
Segment Information | 3 Months Ended |
Mar. 31, 2016 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION We reorganized our business segments during the third quarter of 2015 to reflect our new internal organization and management structure following the acquisition of Integrys. We use operating income to measure segment profitability and allocate resources to our businesses. All prior period amounts impacted by this change were reclassified to conform to the new presentation. At March 31, 2016 , we reported six segments, which are described below. • The Wisconsin segment includes the electric and natural gas utility and non-utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan. • 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. • The We Power segment includes our nonregulated entity that owns and leases generating facilities to WE. • The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the People's Energy, LLC holding company, Wispark LLC, Bostco LLC, Wisvest LLC, Wisconsin Energy Capital Corporation, WBS, PDL, and ITF. The sale of ITF was completed in the first quarter of 2016. See Note 3, Dispositions , for more information on the sale of ITF. All of our operations are located within the United States. The following tables show summarized financial information concerning our reportable segments for the three months ended March 31, 2016 and 2015 : Regulated Operations (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2016 External revenues $ 1,579.8 $ 448.5 $ 148.4 $ — $ 2,176.7 $ 6.2 $ 11.9 $ — $ 2,194.8 Intersegment revenues 0.1 — — — 0.1 104.5 — (104.6 ) — Other operation and maintenance 491.3 117.9 30.0 — 639.2 0.4 (3.5 ) (104.6 ) 531.5 Depreciation and amortization 122.9 32.8 5.1 — 160.8 17.0 10.1 — 187.9 Operating income (loss) 327.5 137.0 31.8 — 496.3 93.3 (0.3 ) — 589.3 Equity in earnings of transmission affiliate — — — 38.5 38.5 — — — 38.5 Interest expense 44.5 9.7 2.5 — 56.7 15.6 31.3 (2.7 ) 100.9 Regulated Operations (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2015 External revenues $ 1,376.5 $ — $ — $ — $ 1,376.5 $ 11.1 $ 0.3 $ — $ 1,387.9 Intersegment revenues 0.4 — — — 0.4 98.6 — (99.0 ) — Other operation and maintenance 369.1 — — — 369.1 0.4 10.1 (98.9 ) 280.7 Depreciation and amortization 85.4 — — — 85.4 16.8 0.4 — 102.6 Operating income (loss) 276.5 — — — 276.5 92.5 (10.2 ) — 358.8 Equity in earnings of transmission affiliate — — — 16.1 16.1 — — — 16.1 Interest expense 31.4 — — — 31.4 15.9 12.2 (0.1 ) 59.4 |
Variable Interest Entities
Variable Interest Entities | 3 Months Ended |
Mar. 31, 2016 | |
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis. This ASU focuses on the consolidation analysis for companies that are required to evaluate whether they should consolidate certain legal entities. It emphasizes the risk of loss when determining a controlling financial interest and amends the guidance for assessing how related party relationships affect the consolidation analysis of variable interest entities. We adopted the standard upon its effective date in the first quarter of 2016, and our adoption resulted in no changes to our disclosures or financial statement presentation. 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 and 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 instead account for ATC as an equity method investment. See Note 13, Investment in American Transmission Company, for more information . The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment and accounts payable. At March 31, 2016 , and December 31, 2015 , our equity investment was $1,422.5 million and $1,380.9 million , respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had $30.4 million and $28.3 million of accounts payable due to ATC at March 31, 2016 , and December 31, 2015 , respectively, for network transmission services. Purchased Power Agreement We have identified a purchased power agreement that represents a variable interest. This agreement is for 236 MW 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 six years . We have examined the risks of the entity, including operations and 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 $119.2 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 each of the three months ended March 31, 2016 and 2015 were $13.5 million . Our maximum exposure to loss is limited to the capacity payments under the contract. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2016 | |
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. Energy Related Purchased Power Agreements Our natural gas utilities have obligations to distribute and sell natural gas to their customers, and our electric utilities have obligations to distribute and sell electricity 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 March 31, 2016 , including those of our subsidiaries, were $12,494.4 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 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 March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO 2 . The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016. SO 2 emissions from PIPP are above the consent decree emission threshold, which means that the Marquette area required action earlier than would otherwise have been required under the revised NAAQS. However, we were able to show through modeling that the area should be designated as attainment. Based upon this modeling, the state of Michigan recommended to the EPA that the Marquette area be designated as attainment, and in February 2016, the EPA issued a draft recommendation to have the Marquette area classified as unclassified/attainment. We expect the EPA recommendation to be finalized in 2016. We believe our fleet overall is well positioned to meet the new regulation. 8-Hour Ozone National Ambient Air Quality Standards The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state 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 and are in the process of reviewing and determining potential impacts resulting from this rule. Mercury and Other Hazardous Air Pollutants In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, both Wisconsin and Michigan have state mercury rules that require a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect until the D.C. Circuit Court of Appeals takes action on the EPA's April 2016 updated cost evaluation. The WE and WPS fleets are well positioned to comply with this regulation. Controls for acid gases and mercury are already in operation at the Pulliam units, and our compliance plans currently include capital projects for WPS's jointly owned plants to achieve the required reductions for MATS. In April 2013, WE received a one year MATS compliance extension from the MDEQ for PIPP through April 2016. The addition of a dry sorbent injection system for further control of mercury and acid gases at PIPP was placed into service in March 2016, and PIPP is in compliance with MATS. Although WPS received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is on a planned outage to complete the construction of the ReACT TM system. Construction of the ReACT TM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date in 2016. Once Weston Unit 3 comes back on line, it is expected to be in compliance with the MATS regulations. Climate Change In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, 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 final rule for existing fossil generating units, numerous states (including Wisconsin and Michigan), trade associations, and private 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 rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. In addition, in February 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would have been required to submit final plans by September 2018, either alone or in conjunction with other states. The timelines for the 2022 through 2029 interim goals and the 2030 final goal for states, as well as all other aspects of the rule, may be changed due to the stay and subsequent legal proceedings. 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. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. We are in the process of reviewing the final rule for existing fossil generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants and biomass facility, and could have a material adverse impact on our operating costs. Draft Federal Plan and Model Trading Rules were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. Among other things, the petitions narrowly ask the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO 2 equivalent reduction goal by about 10% . Michigan state agencies announced modeling results that suggest that the state will be able to meet existing source requirements until 2025, based on planned coal plant retirements, along with a continuation of state renewable standards and current levels of energy efficiency. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2015, we reported aggregated CO 2 equivalent emissions of 31.0 million metric tonnes to the EPA. The level of CO 2 and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent amounts related to the natural gas that our natural gas utilities distribute and sell. For 2015, we reported aggregated CO 2 equivalent emissions of 27.2 million metric tonnes to the EPA related to our distribution and sale of natural gas. 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 and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the Oak Creek expansion 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 VAPP Unit 1, Pulliam Units 7 and 8, and Weston Unit 2, satisfy the IM BTA requirements. For VAPP Unit 2, a project to install fish protection screens to meet the IM BTA standard was completed in October 2015. The same types of screens are scheduled to be installed on VAPP Unit 1 starting in September 2016. 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 proposed 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 Oak Creek Power Plant Units 5 through 8. During 2016–2018, we will be completing studies and evaluating options to address the EM BTA requirements at our 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), and VAPP, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our 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. In addition, the rule allows the EM BTA requirements to be waived in cases of pending facility retirements, which we are currently considering for PIPP. Based on discussions with the MDEQ, if we submit a signed certification with our next National Pollutant Discharge Elimination System permit application stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. Entrainment studies are currently being conducted at Pulliam Units 7 and 8 and are also underway at PIPP. Steam Electric Effluent Guidelines The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin and Michigan. Unless pending challenges to the final guidelines are successful, the WDNR and MDEQ will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years . We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases 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 will require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek and Pleasant Prairie facilities. The rule also requires 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 will be required at Oak Creek Units 5 and 6, the Pleasant Prairie units, the PIPP 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 $95 million to $130 million for these advanced treatment and bottom ash transport systems. Valley Power Plant Wisconsin Pollutant Discharge Elimination System Permit The WDNR issued a Wisconsin Pollutant Discharge Elimination System permit for VAPP that became effective in January 2013. The permit contains several additional requirements including effluent toxicity testing and monitoring for additional parameters (phosphorous, mercury, and ammonia-nitrogen), and a new heat addition limit from the cooling water discharges that all took effect immediately. Other long-term compliance requirements include thermal discharge studies, phosphorous evaluation and feasibility for reduction, mercury minimization planning, and the installation of new cooling water intake fish protection screens. Installation of wedge wire screens for fish protection on the VAPP Unit 2 cooling water intake structure is complete. An identical modification is scheduled to begin for VAPP Unit 1 in the third quarter of 2016. We are also currently working on plans to meet the remaining long-term requirements. 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 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) March 31, 2016 December 31, 2015 Regulatory assets $ 683.7 $ 697.0 Reserves for future remediation 617.5 628.0 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. Weston Title V Air Permit In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, WPS challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, were stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The parties negotiated a settlement of their challenges to the permit. As a result, in March 2016, the ALJ issued an order dismissing the contested case proceedings, and in April 2016, the Brown County Circuit Court dismissed the Petitions for Judicial Review. We do not expect these matters to have a material impact on our financial statements. Consent Decrees Wisconsin Electric Power Company Consent Decree In April 2003, WE entered into a Consent Decree with the EPA, in which it agreed to significantly reduce air emissions from its coal-fired power plants. Under the terms of the Consent Decree, WE could request its termination after December 31, 2015. WE made this termination request in March 2016, and the request is currently under review. Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam In November 2009, the EPA issued a Notice of Violation (NOV) to WPS, which alleged violations of the Clean Air Act's (CAA) 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. The Consent Decree contains a requirement to, among other things, refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, WPS retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. WPS received approval from the PSCW in its 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023. WPS received approval from the PSCW in its rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of a $1.2 million civil penalty. The majority of the beneficial environmental projects proposed by WPS have been approved by the EPA. In March 2016, WPS submitted a proposed revision to the EPA to update requirements reflecting the conversion of Weston Unit 2 from coal to natural gas fuel and to reflect changes to other environmental projects that are not expected to materially impact the overall cost. 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 March 31, 2016 . 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. WE paid an immaterial portion of the assessed penalty but has no further obligations under the Consent Decree. 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. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available. All of the beneficial environmental projects that WPS proposed have been approved by the EPA. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 3 Months Ended |
Mar. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION Three Months Ended March 31 (in millions) 2016 2015 Cash (paid) for interest, net of amount capitalized $ (40.7 ) $ (20.0 ) Cash (paid) for income taxes, net of refunds (0.4 ) (4.3 ) Significant non-cash transactions: Accounts payable related to construction costs 90.1 1.6 Amortization of deferred revenue 6.2 11.1 At March 31, 2016 , and December 31, 2015, restricted cash of $95.9 million and $118.4 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. |
Regulatory Environment
Regulatory Environment | 3 Months Ended |
Mar. 31, 2016 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT Wisconsin Electric Power Company 2015 Wisconsin Rate Order In May 2014, WE applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved the following rate adjustments, effective January 1, 2015: • A net bill increase related to non-fuel costs for WE's retail electric customers of approximately $2.7 million ( 0.1% ) in 2015. This amount reflects WE's receipt of SSR payments from MISO that were higher than WE anticipated when it filed its rate request in May 2014, as well as an offset of $26.6 million related to a refund of prior fuel costs and the remainder of the proceeds from a Section 1603 Renewable Energy Treasury Grant that WE received in connection with its biomass facility. The majority of this $26.6 million was returned to customers in the form of bill credits in 2015. • A rate increase for WE's retail electric customers of $26.6 million ( 0.9% ) in 2016 related to the expiration of the bill credits provided to customers in 2015. • A rate decrease of $13.9 million ( -0.5% ) in 2015 related to a forecasted decrease in fuel costs. • A rate decrease of $10.7 million ( -2.4% ) for WE's natural gas customers in 2015, with no rate adjustment in 2016. • A rate increase of approximately $0.5 million ( 2.0% ) for WE's Downtown Milwaukee (Valley) steam utility customers in 2015, with no rate adjustment in 2016. • A rate increase of approximately $1.2 million ( 7.3% ) for WE's Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016. The authorized ROE for WE was set at 10.2% , and its common equity component remained at an average of 51.0% . The PSCW order reaffirmed the deferral of WE's transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. The PSCW approved a change in rate design for WE, which included higher fixed charges to better match the related fixed costs of providing service. The PSCW order also authorized escrow accounting for SSR revenues because of the uncertainty of the actual revenues WE will receive under the PIPP SSR agreements. Under escrow accounting, WE records SSR revenues from MISO of $90.7 million a year. If actual SSR payments from MISO exceed $90.7 million a year, the difference is deferred and returned to customers, with interest, in a future rate case. If actual SSR payments from MISO are less than $90.7 million a year, the difference is deferred and recovered from customers with interest, in a future rate case. In January 2015, certain parties appealed a portion of the PSCW's final decision adopting WE's specific rate design changes, including new charges for customer-owned generation within its service territory. The Dane County Circuit Court, in its November 2015 order, ruled that there was not enough evidence provided in WE's rate case to support a demand charge for customer-owned generation. As a result, this demand charge did not take effect on January 1, 2016. No other rates approved by the PSCW in the rate case were impacted by the Dane County Circuit Court order. Wisconsin Gas LLC 2015 Wisconsin Rate Order In May 2014, WG applied to the PSCW for a biennial review of costs and rates. In December 2014, the PSCW approved rate increases of $17.1 million ( 2.6% ) in 2015 and $21.4 million ( 3.2% ) in 2016 for WG's natural gas customers, which were effective January 1, 2015, and January 1, 2016, respectively. The authorized ROE for WG was set at 10.3% . The PSCW also authorized an increase in WG's common equity component to an average of 49.5% . Wisconsin Public Service Corporation 2016 Wisconsin Rate Order In April 2015, WPS initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order for WPS, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0% , authorized a net retail electric rate decrease of $7.9 million ( -0.8% ) and a net retail natural gas rate decrease of $6.2 million ( -2.1% ). The decrease in retail electric rates was due to lower monitored fuel costs in 2016 compared to 2015. Absent the adjustment for electric fuel costs, WPS would have realized an electric rate increase. Based on the order, the PSCW will continue to allow WPS to escrow for ATC and MISO network transmission expenses through 2016. In addition, future SSR payments will continue to be escrowed until a future rate proceeding. This allows WPS to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates. In addition, the PSCW approved a deferral for ReACT™, which requires WPS to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window. In March 2016, WPS requested extensions from the PSCW through 2017 for the deferral of the revenue requirement of ReACT™ costs above the authorized $275.0 million level as well as escrow accounting of ATC and MISO network transmission expenses. In April 2016, WPS also requested a deferral through 2017 of the revenue requirement difference between the Real Time Market Pricing and the standard tariffed rates for any of WPS's current large commercial and industrial customers who entered into a service agreement with WPS under Real Time Market Pricing prior to April 15, 2016. 2015 Wisconsin Rate Order In April 2014, WPS initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order for WPS, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million , reflecting a 10.2% ROE. The order authorized a common equity component average of 50.28% . The PSCW approved a change in rate design for WPS, which included higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014. The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million . In addition, 2015 rates included approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, WPS refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, WPS would have realized an electric rate decrease. In addition, WPS received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 16, Commitments and Contingencies, for more information . The PSCW allowed WPS to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, WPS defers as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window. The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, WPS refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, WPS would have realized a retail natural gas rate increase. 2015 Michigan Rate Order 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. 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, WPS will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. WPS also received approval from the MPSC to defer and amortize 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. Lastly, WPS will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018. The Peoples Gas Light and Coke Company and North Shore Gas Company Illinois Investigations In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding the AMRP. The Illinois Attorney General’s office is also conducting an inquiry into the same allegations. Since the investigations are ongoing, it is too early to determine what effect, if any, the investigations will have on the AMRP. In July 2015, we engaged a nationally recognized engineering and construction firm to conduct an independent, bottom up review of the AMRP's long-term cost, scope, and schedule. We filed the results of that review with the ICC in November 2015. In November 2015, the ICC initiated an investigation into whether we, PGL, or Integrys knowingly misled or withheld material information from the ICC at its open meeting on May 20, 2015. The investigation relates to the ICC Staff's presentation of the independent audit findings reached for the AMRP. The Illinois Attorney General’s office is conducting an inquiry into this matter as well. In December 2015, the ICC ordered a series of stakeholder workshops to evaluate the AMRP. This ICC action does not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provides the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops are expected to result in an ICC order with final and binding recommendations for the AMRP. The workshops that commenced in January 2016 were completed, and a report is expected to be presented to the ICC by the end of May 2016. We are currently unable to determine what, if any, long-term impact there will be on the AMRP. 2015 Illinois Rate Order In February 2014, PGL and NSG initiated a rate proceeding with the ICC. In January 2015, the ICC issued a final written order for PGL and NSG, effective January 28, 2015. The order authorized a retail natural gas rate increase of $74.8 million for PGL and $3.7 million for NSG. In February 2015, the ICC issued an amendatory order that revised the increases to $71.1 million for PGL and $3.5 million for NSG, effective February 26, 2015, to reflect the extension of bonus depreciation in 2014. The rates for PGL reflected a 9.05% ROE and a common equity component average of 50.33% . The rates for NSG reflected a 9.05% ROE and a common equity component average of 50.48% . The rate order allowed PGL and NSG to continue the use of their decoupling mechanisms and uncollectible expense true-up mechanisms. In addition, PGL recovers a return on certain investments and depreciation expense through the qualifying infrastructure plant rider, and accordingly, such costs are not subject to PGL's rate order. Minnesota Energy Resources Corporation 2016 Minnesota Rate Case In September 2015, MERC initiated a rate proceeding with the MPUC to increase retail natural gas rates $14.8 million ( 5.5% ). MERC's request reflects a 10.3% ROE and a common equity component average of 50.32% . The proposed retail natural gas rate increase is primarily driven by higher construction and capital expenditures, general inflation, and improvements to customer service programs. The request also includes increases in costs related to the acquisition of Alliant Energy Corporation's Minnesota natural gas operations in April 2015. MERC is requesting authority from the MPUC to continue the use of its currently authorized decoupling mechanism. In November 2015, the MPUC approved an interim rate order, effective January 1, 2016, authorizing a retail natural gas rate increase for MERC of $9.7 million ( 3.7% ). The interim rates reflect a 9.35% ROE and a common equity component average of 50.32% . The interim rate increase is subject to refund pending the final rate order. 2015 Minnesota Rate Order In September 2013, MERC initiated a rate proceeding with the MPUC. In October 2014, the MPUC issued a final written order for MERC, effective April 1, 2015. The order authorized a retail natural gas rate increase of $7.6 million . The rates reflected a 9.35% ROE and a common equity component average of 50.31% . The order approved a deferral of customer billing system costs, for which recovery will be requested in a future rate case. A decoupling mechanism with a 10% cap remains in effect for MERC's residential and small commercial and industrial customers. The final approved rate increase was lower than the interim rates collected from customers during 2014. Therefore, MERC refunded $4.7 million to customers in 2015. Michigan Gas Utilities Corporation 2016 Michigan Rate Order In June 2015, MGU initiated a rate proceeding with the MPSC. In December 2015, the MPSC issued a final written order approving a settlement agreement for MGU. The order, which reflected a 9.9% ROE and a common equity component average of 52.0% , authorized a retail natural gas rate increase of $3.4 million ( 2.4% ), effective January 1, 2016. Based on the settlement agreement, MGU discontinued the use of its decoupling mechanism after December 31, 2015. In addition, since bonus depreciation is in effect in 2016, MGU is required to establish a regulatory liability for the resulting cost savings and must reflect the liability in its next general rate case. |
New Accounting Pronouncements
New Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2016 | |
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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements. Classification and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have 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. We are currently assessing the effects this guidance may have on our financial statements. Stock-Based Compensation In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We are currently assessing the effects this guidance may have on our financial statements. |
General Information (Policies)
General Information (Policies) | 3 Months Ended |
Mar. 31, 2016 | |
Accounting policies | |
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, 2015 . Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three months ended March 31, 2016 , are not necessarily indicative of expected results for 2016 due to seasonal variations and other factors. |
Reclassifications | Reclassifications On the income statements for the quarter ended March 31, 2015, we reclassified $2.5 million from treasury grant to depreciation and amortization. We also reclassified an insignificant amount from interest expense to preferred stock dividends of subsidiaries on the income statements for the quarter ended March 31, 2015. These reclassifications were made to be consistent with the current period presentation on the income statements. On the statements of cash flows for the quarter ended March 31, 2015, we reclassified $0.9 million from depreciation and amortization to other operating activities. In addition, we reclassified $3.7 million of non-qualified pension and OPEB contributions from other operating activities to contributions and payments related to pension and OPEB plans on the statements of cash flows for the quarter ended March 31, 2015. We also reclassified $3.7 million from other investing activities to capital expenditures on the statements of cash flows for the quarter ended March 31, 2015. An insignificant amount of preferred stock dividends of subsidiaries was also reclassified from other financing activities to net income on the statements of cash flows for the quarter ended March 31, 2015. These reclassifications were made to be consistent with the current period presentation on the statements of cash flows. During the third quarter of 2015, following the acquisition of Integrys, we reorganized our business segments. All prior period amounts impacted by this change were reclassified to conform to the new presentation. See Note 14, Segment Information, for more information on our business segments. |
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 derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. We recognize transfers at their value as of the end of the reporting period. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis. |
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. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements. Classification and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have 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. We are currently assessing the effects this guidance may have on our financial statements. Stock-Based Compensation In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We are currently assessing the effects this guidance may have on our financial statements. |
Acquisition (Tables)
Acquisition (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Business Combinations [Abstract] | |
Allocation of Purchase Price | The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. In the first quarter of 2016, adjustments were made to the estimated fair values of the assets acquired and liabilities assumed, primarily in connection with the sale of ITF. The allocation is subject to change during the remainder of the measurement period, which ends one year from the acquisition date, as we obtain additional information, including with respect to certain regulatory and legal matters. (in millions) Current assets $ 1,060.7 Net property, plant, and equipment 7,107.4 Investments * 1,071.8 Goodwill 2,557.2 Deferred charges and other assets, excluding goodwill 1,758.5 Current liabilities, including current maturities of long-term debt (1,299.1 ) Deferred credits and other liabilities (3,678.7 ) Long-term debt (2,943.6 ) Preferred stock of subsidiary (51.1 ) Total purchase price $ 5,583.1 * Includes equity method goodwill related to Integrys's investment in ATC. |
Pro Forma Financial Information | The following unaudited pro forma financial information reflects the consolidated results and amortization of purchase price adjustments as if the acquisition had taken place on January 1, 2014. The unaudited pro forma financial information is presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or our future consolidated results. The pro forma financial information does not reflect any potential cost savings from operating efficiencies resulting from the acquisition and does not include certain acquisition-related costs. (in millions, except per share amounts) Three Months Ended March 31, 2015 Unaudited Pro Forma Financial Information Operating Revenues $ 2,550.9 Net Income $ 329.9 Earnings per share (Basic) $ 1.05 Earnings per share (Diluted) $ 1.04 |
Dispositions (Tables)
Dispositions (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Corporate and Other | ITF | |
Dispositions | |
Schedule of assets and liabilities included in held for sale | The following table shows the carrying values of the major classes of assets and liabilities included as held for sale on our balance sheet at December 31: (in millions) 2015 Property, plant, and equipment $ 37.2 Accounts receivable and unbilled revenues 34.9 Materials, supplies, and inventories 18.4 Other current assets 2.6 Other long-term assets 3.7 Total assets $ 96.8 Accounts payable $ 12.9 Accrued payroll and benefits 2.4 Other current liabilities 4.5 Pension and OPEB obligations 1.2 Other long-term liabilities 0.6 Total liabilities * $ 21.6 * Included in other current liabilities on our balance sheet. |
Common Equity (Tables)
Common Equity (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation awards granted | During the first quarter of 2016, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees under our and Integrys's normal schedule of awarding long-term incentive compensation: Award Type Number of Awards Stock options (1) 752,085 Restricted shares (2) 140,897 Performance units 283,505 (1) Stock options awarded had a weighted-average exercise price of $51.80 and a weighted-average grant date fair value of $5.03 per option. (2) Restricted shares awarded had a weighted-average grant date fair value of $53.40 per share. |
Short-term Debt and Lines of 30
Short-term Debt and Lines of Credit (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Short-term Debt [Abstract] | |
Short-term notes payable balances 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) March 31, 2016 December 31, 2015 Commercial paper Amount outstanding $ 896.4 $ 1,095.0 Weighted-average interest rate on amounts outstanding 0.61 % 0.68 % |
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 remaining available capacity under these facilities: (in millions) Maturity March 31, 2016 WEC Energy Group December 2020 $ 1,050.0 WE December 2020 500.0 WPS * December 2016 250.0 WG December 2020 350.0 PGL December 2020 350.0 Total short-term credit capacity $ 2,500.0 Less: Letters of credit issued inside credit facilities $ 18.0 Commercial paper outstanding 896.4 Available capacity under existing agreements $ 1,585.6 * In March 2016, WPS requested approval from the PSCW to extend the maturity through December 2020. |
Materials, Supplies, and Inve31
Materials, Supplies, and Inventories (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Inventory Disclosure [Abstract] | |
Schedule of inventory | Our inventory consisted of: (in millions) March 31, 2016 December 31, 2015 Materials and supplies $ 217.8 $ 219.2 Fossil fuel 163.4 183.7 Natural gas in storage 89.5 284.1 Total $ 470.7 $ 687.0 |
Schedule of LIFO liquidation balance sheet amounts | The amounts were as follows at March 31, 2016 : (in millions) Balance Sheet Presentation PGL NSG Temporary LIFO liquidation debit Other current assets $ 17.6 $ — Temporary LIFO liquidation credit Other current liabilities — 6.0 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy | The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: March 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 0.6 $ 1.7 $ — $ 2.3 FTRs — — 1.1 1.1 Petroleum products contracts 1.1 — — 1.1 Coal contracts — 1.6 — 1.6 Total derivative assets $ 1.7 $ 3.3 $ 1.1 $ 6.1 Investments held in rabbi trust $ 41.7 $ — $ — $ 41.7 Liabilities Derivative liabilities Natural gas contracts $ 8.8 $ 21.7 $ — $ 30.5 Petroleum products contracts 3.8 — — 3.8 Coal contracts — 14.7 — 14.7 Total derivative liabilities $ 12.6 $ 36.4 $ — $ 49.0 December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Assets Derivative assets Natural gas contracts $ 1.6 $ 1.5 $ — $ 3.1 FTRs — — 3.6 3.6 Petroleum products contracts 1.2 — — 1.2 Coal contracts — 2.0 — 2.0 Total derivative assets $ 2.8 $ 3.5 $ 3.6 $ 9.9 Investments held in rabbi trust $ 39.8 $ — $ — $ 39.8 Liabilities Derivative liabilities Natural gas contracts $ 16.5 $ 25.3 $ — $ 41.8 Petroleum products contracts 4.9 — — 4.9 Coal contracts — 12.3 — 12.3 Total derivative liabilities $ 21.4 $ 37.6 $ — $ 59.0 |
Reconciliation of changes in fair value of items categorized as level 3 measurements | The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended March 31 (in millions) 2016 2015 Balance at the beginning of the period $ 3.6 $ 7.0 Realized and unrealized losses (0.2 ) — Sales (0.1 ) — Settlements (2.2 ) (3.7 ) Balance at the end of the period $ 1.1 $ 3.3 |
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: March 31, 2016 December 31, 2015 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 28.6 $ 30.4 $ 27.3 Long-term debt, including current portion * $ 9,055.4 $ 9,790.5 $ 9,221.9 $ 9,681.0 * The carrying amount of long-term debt excludes capital lease obligations of $52.8 million and $59.9 million at March 31, 2016, and December 31, 2015, respectively. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative assets and derivative liabilities | The following table shows our derivative assets and derivative liabilities: March 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 1.7 $ 28.7 $ 2.6 $ 38.5 Petroleum products contracts 0.9 3.3 0.9 3.8 FTRs 1.1 — 3.6 — Coal contracts 1.6 10.3 1.7 6.7 Total other current * $ 5.3 $ 42.3 $ 8.8 $ 49.0 Other long-term Natural gas contracts $ 0.6 $ 1.8 $ 0.5 $ 3.3 Petroleum products contracts 0.2 0.5 0.3 1.1 Coal contracts — 4.4 0.3 5.6 Total other long-term * $ 0.8 $ 6.7 $ 1.1 $ 10.0 Total $ 6.1 $ 49.0 $ 9.9 $ 59.0 * On our balance sheets, we classify derivative assets and liabilities as current or long-term based on the maturities of the underlying contracts. |
Estimated notional volumes and gain (losses) | Our estimated notional sales volumes and gains (losses) were as follows: Three Months Ended March 31, 2016 Three Months Ended March 31, 2015 (in millions) Volume Gains (Losses) Volume Gains (Losses) Natural gas contracts 50.1 Dth $ (33.5 ) 13.3 Dth $ (7.1 ) Petroleum products contracts 3.0 gallons (1.1 ) 0.9 gallons (0.1 ) FTRs 7.6 MWh 3.0 6.2 MWh 2.1 Total $ (31.6 ) $ (5.1 ) |
Offsetting assets and liabilities | The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the balance sheet: March 31, 2016 December 31, 2015 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 6.1 $ 49.0 $ 9.9 $ 59.0 Gross amount not offset on balance sheet * (1.6 ) (13.6 ) (3.0 ) (22.5 ) Net amount $ 4.5 $ 35.4 $ 6.9 $ 36.5 * Includes cash collateral posted of $12.0 million and $19.5 million as of March 31, 2016 , and December 31, 2015 , respectively. |
Guarantees (Tables)
Guarantees (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Guarantees [Abstract] | |
Schedule of outstanding guarantees | The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at March 31, 2016 Less Than 1 Year 1 to 3 Years Over 3 Years Guarantees Guarantees supporting commodity transactions of subsidiaries (1) $ 168.7 $ 89.7 $ — $ 79.0 Standby letters of credit (2) 28.3 18.7 9.4 0.2 Surety bonds (3) 10.2 10.2 — — Other guarantees (4) 58.9 20.6 0.1 38.2 Total guarantees $ 266.1 $ 139.2 $ 9.5 $ 117.4 (1) Consists of (a) $5.0 million and $11.0 million to support the business operations of WBS and PDL, respectively; and (b) $114.8 million and $37.9 million related to natural gas supply at MERC and MGU, respectively. These amounts are not reflected on our balance sheets. (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 (a) $19.0 million to support PDL's future payment obligations related to its distributed solar generation projects, of which $6.6 million is covered by a reciprocal guarantee from a third party; (b) $20.0 million for an interconnection agreement between WPS and ATC; (c) $10.0 million related to the sale of a nonregulated retail marketing business previously owned by Integrys; and (d) $9.9 million related to other indemnifications. The amounts discussed in items (a) and (b) are not reflected on our balance sheets. An insignificant liability was recorded for item (c). In addition, a liability of $9.2 million related to workers compensation coverage was recorded for item (d). |
Employee Benefits (Tables)
Employee Benefits (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of the components of net periodic benefit cost | The following tables show the components of net periodic pension and OPEB costs for our benefit plans. Our pension and OPEB costs for the three months ended March 31, 2016 , include costs attributable to the Integrys pension and OPEB plans. The terms and conditions of the legacy company plans have not changed since the acquisition. Pension Costs Three Months Ended March 31 (in millions) 2016 2015 Service cost $ 11.3 $ 3.9 Interest cost 33.2 15.2 Expected return on plan assets (49.0 ) (25.8 ) Amortization of prior service cost 0.9 0.5 Amortization of net actuarial loss 20.5 11.6 Net periodic benefit cost $ 16.9 $ 5.4 OPEB Costs Three Months Ended March 31 (in millions) 2016 2015 Service cost $ 6.7 $ 2.6 Interest cost 9.2 4.2 Expected return on plan assets (13.1 ) (5.9 ) Amortization of prior service credit (2.3 ) (0.3 ) Amortization of net actuarial loss 2.3 0.5 Net periodic benefit cost $ 2.8 $ 1.1 |
Goodwill (Tables)
Goodwill (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
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 three months ended March 31, 2016 : (in millions) Wisconsin Illinois Other States Total Goodwill balance as of January 1, 2016 $ 2,109.5 $ 731.2 $ 182.8 $ 3,023.5 Adjustment to Integrys purchase price allocation (12.4 ) (8.5 ) (3.5 ) (24.4 ) Goodwill balance as of March 31, 2016 (1) $ 2,097.1 (2) $ 722.7 (3) $ 179.3 (3) $ 2,999.1 (1) We had no accumulated impairment losses related to our goodwill as of March 31, 2016 . (2) Of this amount, $1,655.2 million relates to the acquisition of Integrys. (3) Total amount relates to the acquisition of Integrys. |
Investment in American Transm37
Investment in American Transmission Company (Tables) - ATC | 3 Months Ended |
Mar. 31, 2016 | |
Investment in ATC | |
Schedule of changes to our investment in ATC | The following table shows changes to our investment in ATC: Three Months Ended March 31 (in millions) 2016 2015 Balance at beginning of period $ 1,380.9 $ 424.1 Add: Earnings from equity method investment 38.5 16.1 Add: Capital contributions 9.0 1.3 Add: Adjustment to equity method goodwill 9.3 — Less: Distributions received 15.1 10.4 Less: Other 0.1 — Balance at end of period $ 1,422.5 $ 431.1 |
Schedule of significant transactions with ATC | The following table summarizes our significant related party transactions with ATC: Three Months Ended March 31 (in millions) 2016 2015 Charges to ATC for services and construction $ 4.1 $ 2.5 Charges from ATC for network transmission services 100.8 59.6 |
Schedule of receivables and payables with ATC | Our balance sheets included the following receivables and payables related to ATC: (in millions) March 31, 2016 December 31, 2015 Accounts receivable Services provided to ATC $ 2.0 $ 1.0 Accounts payable Services received from ATC 30.4 28.3 |
Schedule of summarized income statement data for ATC | Summarized financial data for ATC is included in the following tables: Three Months Ended March 31 (in millions) 2016 2015 Income statement data Revenues $ 164.2 $ 152.4 Operating expenses 79.1 80.0 Other expense 24.0 24.4 Net income $ 61.1 $ 48.0 |
Schedule of summarized balance sheet data for ATC | (in millions) March 31, 2016 December 31, 2015 Balance sheet data Current assets $ 88.7 $ 80.5 Noncurrent assets 4,022.1 3,948.3 Total assets $ 4,110.8 $ 4,028.8 Current liabilities $ 337.8 $ 330.3 Long-term debt 1,790.9 1,790.7 Other noncurrent liabilities 265.8 245.0 Shareholders' equity 1,716.3 1,662.8 Total liabilities and shareholders' equity $ 4,110.8 $ 4,028.8 |
Segment Information (Tables)
Segment Information (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Segment Reporting [Abstract] | |
Financial information of reportable operating segments | The following tables show summarized financial information concerning our reportable segments for the three months ended March 31, 2016 and 2015 : Regulated Operations (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2016 External revenues $ 1,579.8 $ 448.5 $ 148.4 $ — $ 2,176.7 $ 6.2 $ 11.9 $ — $ 2,194.8 Intersegment revenues 0.1 — — — 0.1 104.5 — (104.6 ) — Other operation and maintenance 491.3 117.9 30.0 — 639.2 0.4 (3.5 ) (104.6 ) 531.5 Depreciation and amortization 122.9 32.8 5.1 — 160.8 17.0 10.1 — 187.9 Operating income (loss) 327.5 137.0 31.8 — 496.3 93.3 (0.3 ) — 589.3 Equity in earnings of transmission affiliate — — — 38.5 38.5 — — — 38.5 Interest expense 44.5 9.7 2.5 — 56.7 15.6 31.3 (2.7 ) 100.9 Regulated Operations (in millions) Wisconsin Illinois Other States Electric Transmission Total Regulated Operations We Power Corporate and Other Reconciling Eliminations WEC Energy Group Consolidated Three Months Ended March 31, 2015 External revenues $ 1,376.5 $ — $ — $ — $ 1,376.5 $ 11.1 $ 0.3 $ — $ 1,387.9 Intersegment revenues 0.4 — — — 0.4 98.6 — (99.0 ) — Other operation and maintenance 369.1 — — — 369.1 0.4 10.1 (98.9 ) 280.7 Depreciation and amortization 85.4 — — — 85.4 16.8 0.4 — 102.6 Operating income (loss) 276.5 — — — 276.5 92.5 (10.2 ) — 358.8 Equity in earnings of transmission affiliate — — — 16.1 16.1 — — — 16.1 Interest expense 31.4 — — — 31.4 15.9 12.2 (0.1 ) 59.4 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We have established the following regulatory assets and reserves related to manufactured gas plant sites: (in millions) March 31, 2016 December 31, 2015 Regulatory assets $ 683.7 $ 697.0 Reserves for future remediation 617.5 628.0 |
Supplemental Cash Flow Inform40
Supplemental Cash Flow Information (Tables) | 3 Months Ended |
Mar. 31, 2016 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | Three Months Ended March 31 (in millions) 2016 2015 Cash (paid) for interest, net of amount capitalized $ (40.7 ) $ (20.0 ) Cash (paid) for income taxes, net of refunds (0.4 ) (4.3 ) Significant non-cash transactions: Accounts payable related to construction costs 90.1 1.6 Amortization of deferred revenue 6.2 11.1 |
General Information - General (
General Information - General (Details) - customer customer in Millions | Mar. 31, 2016 | Jun. 29, 2015 |
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% | 26.20% |
General Information - Reclassif
General Information - Reclassifications (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2015USD ($) | |
Income Statement Reclassification | |
Item Effected [Line Items] | |
Prior Period Income Statement Reclassification Treasury Grant | $ 2.5 |
Cash Flow Statement Reclassification | |
Item Effected [Line Items] | |
Prior Period Cash Flow Statement Reclassification Depreciation and Amortization | 0.9 |
Prior Period Cash Flow Statement Reclassification Other Operating Activities | 3.7 |
Prior period cash flow statment reclassification other investing activities | $ 3.7 |
Acquisition - General (Details)
Acquisition - General (Details) | Jun. 29, 2015 |
Business Combinations [Abstract] | |
Percentage of Integrys common shares acquired | 100.00% |
Acquisition - Purchase Price Al
Acquisition - Purchase Price Allocation (Details) $ in Millions | Jun. 29, 2015USD ($) |
Business Combinations [Abstract] | |
Duration of the measurement period | 1 year |
Assets acquired | |
Current assets | $ 1,060.7 |
Net property, plant, and equipment | 7,107.4 |
Investments | 1,071.8 |
Goodwill | 2,557.2 |
Deferred charges and other assets, excluding goodwill | 1,758.5 |
Liabilities assumed | |
Current liabilities, including current maturities of long-term debt | (1,299.1) |
Deferred credits and other liabilities | (3,678.7) |
Long-term debt | (2,943.6) |
Preferred stock of subsidiary | (51.1) |
Total purchase price | $ 5,583.1 |
Acquisition - Pro Forma Financi
Acquisition - Pro Forma Financial Information (Details) $ / shares in Units, $ in Millions | 3 Months Ended |
Mar. 31, 2015USD ($)$ / shares | |
Business Combinations [Abstract] | |
Operating Revenues | $ | $ 2,550.9 |
Net Income | $ | $ 329.9 |
Earnings per share (Basic) | $ / shares | $ 1.05 |
Earnings per share (Diluted) | $ / shares | $ 1.04 |
Acquisition - Impacts (Details)
Acquisition - Impacts (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Business Combinations [Abstract] | ||
Acquisition costs | $ 8.8 | |
Revenue attributable to Integrys | $ 983.1 | |
Net income attributable to Integrys | $ 158.2 |
Dispositions (Details)
Dispositions (Details) - Corporate and Other - ITF - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2015 | |
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract] | ||
Gain (loss) on disposition of business | $ 0 | |
Assets and liabilities included in held for sale | ||
Property, plant, and equipment | $ 37.2 | |
Accounts receivable and unbilled revenues | 34.9 | |
Materials, supplies, and inventories | 18.4 | |
Other current assets | 2.6 | |
Other long-term assets | 3.7 | |
Total assets | 96.8 | |
Accounts payable | 12.9 | |
Accrued payroll and benefits | 2.4 | |
Other current liabilities | 4.5 | |
Pension and OPEB obligations | 1.2 | |
Other long-term liabilities | 0.6 | |
Total liabilities | $ 21.6 |
Common Equity - Share-Based Com
Common Equity - Share-Based Compensation Plans (Details) | 3 Months Ended |
Mar. 31, 2016$ / sharesshares | |
Stock options | |
Stock-based Compensation Plans | |
Stock options granted | shares | 752,085 |
Stock options granted, weighted average exercise price (in dollars per share) | $ / shares | $ 51.80 |
Stock options granted, weighted-average grant date fair value (in dollars per share) | $ / shares | $ 5.03 |
Restricted shares | |
Stock-based Compensation Plans | |
Awards granted, other than stock options | shares | 140,897 |
Weighted average grant date fair value, awards other than stock options (in dollars per share) | $ / shares | $ 53.40 |
Performance units | |
Stock-based Compensation Plans | |
Awards granted, other than stock options | shares | 283,505 |
Short-term Debt and Lines of 49
Short-term Debt and Lines of Credit - Short-term Borrowings (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Dec. 31, 2015 | |
Short-term borrowings | ||
Commercial Paper | $ 896.4 | $ 1,095 |
Commercial paper | ||
Short-term borrowings | ||
Weighted-average interest rate on amounts outstanding | 0.61% | 0.68% |
Average amounts outstanding during the period | $ 1,043.7 | |
Weighted-average interest rate during the period | 0.63% |
Short-term Debt and Lines of 50
Short-term Debt and Lines of Credit - Revolving Credit Facilities (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 2,500 | |
Letters of credit issued inside credit facilities | 18 | |
Commercial Paper | 896.4 | $ 1,095 |
Available capacity under existing agreements | 1,585.6 | |
WEC Energy Group | Credit facility maturing December 2020 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | 1,050 | |
Wisconsin Electric | Credit facility maturing December 2020 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | 500 | |
WPS | Credit facility maturing December 2016 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | 250 | |
Wisconsin Gas | Credit facility maturing December 2020 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | 350 | |
PGL | Credit facility maturing December 2020 | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 350 |
Long Term Debt (Details)
Long Term Debt (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | ||
Feb. 29, 2016 | Mar. 31, 2016 | Feb. 01, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||||
Common Stock, Value, Issued | $ 3.2 | $ 3.2 | ||
Integrys | ||||
Debt Instrument [Line Items] | ||||
Common Stock, Value, Issued | $ 66.4 | |||
Integrys | TEG Junior Subordinated Notes, 6.11% due 2066 [Member] | ||||
Debt Instrument [Line Items] | ||||
Retirement of long-term debt | $ 154.9 | |||
Interest rate on long-term debt | 6.11% | |||
Debt Instrument, Repurchase Amount | $ 128.6 | |||
Long-term Debt, Gross | $ 114.9 | |||
Debt Instrument, Basis Spread on Variable Rate | 2.12% |
Materials, Supplies, and Inve52
Materials, Supplies, and Inventories (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Materials, supplies, and inventories | ||
Materials and supplies | $ 217.8 | $ 219.2 |
Fossil fuel | 163.4 | 183.7 |
Natural gas in storage | 89.5 | 284.1 |
Total | 470.7 | $ 687 |
PGL | ||
Materials, supplies, and inventories | ||
Temporary LIFO liquidation debit | 17.6 | |
Temporary LIFO liquidation credit | 0 | |
NSG | ||
Materials, supplies, and inventories | ||
Temporary LIFO liquidation debit | 0 | |
Temporary LIFO liquidation credit | $ 6 |
Fair Value Measurements - Asse
Fair Value Measurements - Assets and liabilities measured on a recurring basis (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Assets | ||
Derivative asset | $ 6.1 | $ 9.9 |
Liabilities | ||
Derivative liability | 49 | 59 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 1.7 | 2.8 |
Investment in exchange-traded funds | 41.7 | 39.8 |
Liabilities | ||
Derivative liability | 12.6 | 21.4 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 3.3 | 3.5 |
Investment in exchange-traded funds | 0 | 0 |
Liabilities | ||
Derivative liability | 36.4 | 37.6 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 1.1 | 3.6 |
Investment in exchange-traded funds | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Total | ||
Assets | ||
Derivative asset | 6.1 | 9.9 |
Investment in exchange-traded funds | 41.7 | 39.8 |
Liabilities | ||
Derivative liability | 49 | 59 |
Natural gas contracts | Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 0.6 | 1.6 |
Liabilities | ||
Derivative liability | 8.8 | 16.5 |
Natural gas contracts | Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 1.7 | 1.5 |
Liabilities | ||
Derivative liability | 21.7 | 25.3 |
Natural gas contracts | Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Natural gas contracts | Fair value measurements on a recurring basis | Total | ||
Assets | ||
Derivative asset | 2.3 | 3.1 |
Liabilities | ||
Derivative liability | 30.5 | 41.8 |
FTRs | Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 0 | 0 |
FTRs | Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 0 | 0 |
FTRs | Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 1.1 | 3.6 |
FTRs | Fair value measurements on a recurring basis | Total | ||
Assets | ||
Derivative asset | 1.1 | 3.6 |
Petroleum products contracts | Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 1.1 | 1.2 |
Liabilities | ||
Derivative liability | 3.8 | 4.9 |
Petroleum products contracts | Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Petroleum products contracts | Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Petroleum products contracts | Fair value measurements on a recurring basis | Total | ||
Assets | ||
Derivative asset | 1.1 | 1.2 |
Liabilities | ||
Derivative liability | 3.8 | 4.9 |
Coal contracts | Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Coal contracts | Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 1.6 | 2 |
Liabilities | ||
Derivative liability | 14.7 | 12.3 |
Coal contracts | Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Coal contracts | Fair value measurements on a recurring basis | Total | ||
Assets | ||
Derivative asset | 1.6 | 2 |
Liabilities | ||
Derivative liability | $ 14.7 | $ 12.3 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract] | ||
Balance at the beginning of the period | $ 3.6 | $ 7 |
Realized and unrealized losses | (0.2) | 0 |
Sales | (0.1) | 0 |
Settlements | (2.2) | (3.7) |
Balance at the end of period | 1.1 | 3.3 |
Unrealized gains and losses on level 3 derivatives included in earnings | $ 0 | $ 0 |
Fair Value Measurements - Finan
Fair Value Measurements - Financial Instruments not recorded at fair value (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Financial Instruments | ||
Preferred stock | $ 30.4 | $ 30.4 |
Carrying Amount | ||
Financial Instruments | ||
Preferred stock | 30.4 | 30.4 |
Long-term debt, including current portion | 9,055.4 | 9,221.9 |
Capital lease obligations | 52.8 | 59.9 |
Fair Value | ||
Financial Instruments | ||
Preferred stock | 28.6 | 27.3 |
Long-term debt, including current portion | $ 9,790.5 | $ 9,681 |
Derivative Instruments - Deriva
Derivative Instruments - Derivative assets and liabilities (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Derivative Asset | ||
Other current derivative assets | $ 5.3 | $ 8.8 |
Other long-term derivative assets | 0.8 | 1.1 |
Derivative asset | 6.1 | 9.9 |
Derivative Liability | ||
Other current derivative liabilities | 42.3 | 49 |
Other long-term derivative liabilities | 6.7 | 10 |
Derivative liability | 49 | 59 |
Natural gas contracts | ||
Derivative Asset | ||
Other current derivative assets | 1.7 | 2.6 |
Other long-term derivative assets | 0.6 | 0.5 |
Derivative Liability | ||
Other current derivative liabilities | 28.7 | 38.5 |
Other long-term derivative liabilities | 1.8 | 3.3 |
Petroleum products contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.9 | 0.9 |
Other long-term derivative assets | 0.2 | 0.3 |
Derivative Liability | ||
Other current derivative liabilities | 3.3 | 3.8 |
Other long-term derivative liabilities | 0.5 | 1.1 |
FTRs | ||
Derivative Asset | ||
Other current derivative assets | 1.1 | 3.6 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative Asset | ||
Other current derivative assets | 1.6 | 1.7 |
Other long-term derivative assets | 0 | 0.3 |
Derivative Liability | ||
Other current derivative liabilities | 10.3 | 6.7 |
Other long-term derivative liabilities | $ 4.4 | $ 5.6 |
Derivative Instruments - Gains
Derivative Instruments - Gains (Losses) and Notional Volumes (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions | 3 Months Ended | |
Mar. 31, 2016USD ($)MMBTUMWhgal | Mar. 31, 2015USD ($)MMBTUMWhgal | |
Realized Gain (Loss) on Derivatives, Net | ||
Gains (Losses) | $ (31.6) | $ (5.1) |
Natural gas contracts | ||
Realized Gain (Loss) on Derivatives, Net | ||
Gains (Losses) | $ (33.5) | $ (7.1) |
Notional Volumes | ||
Notional sales volumes (Dth or MWh) | MMBTU | 50.1 | 13.3 |
Petroleum products contracts | ||
Realized Gain (Loss) on Derivatives, Net | ||
Gains (Losses) | $ (1.1) | $ (0.1) |
Notional Volumes | ||
Notional sales volumes (gallons) | gal | 3 | 0.9 |
FTRs | ||
Realized Gain (Loss) on Derivatives, Net | ||
Gains (Losses) | $ 3 | $ 2.1 |
Notional Volumes | ||
Notional sales volumes (Dth or MWh) | MWh | 7.6 | 6.2 |
Derivative Instruments - Balanc
Derivative Instruments - Balance Sheet Offseting (Details) - USD ($) $ in Millions | Mar. 31, 2016 | Dec. 31, 2015 |
Cash collateral | ||
Collateral in margin account | $ 30.5 | $ 42.3 |
Offsetting Derivative Assets | ||
Gross amount recognized on the balance sheet | 6.1 | 9.9 |
Gross amount not offset on balance sheet | (1.6) | (3) |
Net amount | 4.5 | 6.9 |
Offsetting Derivative Liabilities | ||
Gross amount recognized on the balance sheet | 49 | 59 |
Gross amount not offset on balance sheet | (13.6) | (22.5) |
Net amount | 35.4 | 36.5 |
Cash collateral posted | 12 | 19.5 |
Credit Risk Related Contingent Features | ||
Aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position | 21.4 | 23.8 |
Collateral that would have been required | $ 20.4 | $ 18 |
Derivative Instruments - Intere
Derivative Instruments - Interest Rate Swap (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Jun. 30, 2015 | |
Interest rate swap | ||
Amount of hedged item deferred into accumulated other comprehensive income | $ 19 | |
Amount of accumulated other comprehensive income reclassified into income | $ 0.5 | |
Amount of accumulated other comprehensive income to be reclassified into income over the next twelve months | 2.2 | |
Total senior notes issued in June 2015 | ||
Interest rate swap | ||
Issuance of long-term debt related to the acquisition of Integrys | $ 1,200 |
Guarantees (Details)
Guarantees (Details) $ in Millions | Mar. 31, 2016USD ($) |
Guarantees | |
Total guarantees | $ 266.1 |
Guarantees expiring in less than 1 year | 139.2 |
Guarantees expiring within 1 to 3 years | 9.5 |
Guarantees with expiration over 3 years | 117.4 |
Guarantees supporting commodity transactions of subsidiaries | |
Guarantees | |
Total guarantees | 168.7 |
Guarantees expiring in less than 1 year | 89.7 |
Guarantees expiring within 1 to 3 years | 0 |
Guarantees with expiration over 3 years | 79 |
Guarantees supporting commodity transactions of subsidiaries | WBS | |
Guarantees | |
Total guarantees | 5 |
Guarantees supporting commodity transactions of subsidiaries | PDL | |
Guarantees | |
Total guarantees | 11 |
Guarantees supporting commodity transactions of subsidiaries | MERC | |
Guarantees | |
Total guarantees | 114.8 |
Guarantees supporting commodity transactions of subsidiaries | MGU | |
Guarantees | |
Total guarantees | 37.9 |
Standby letters of credit | |
Guarantees | |
Total guarantees | 28.3 |
Guarantees expiring in less than 1 year | 18.7 |
Guarantees expiring within 1 to 3 years | 9.4 |
Guarantees with expiration over 3 years | 0.2 |
Surety bonds | |
Guarantees | |
Total guarantees | 10.2 |
Guarantees expiring in less than 1 year | 10.2 |
Guarantees expiring within 1 to 3 years | 0 |
Guarantees with expiration over 3 years | 0 |
Other guarantees | |
Guarantees | |
Total guarantees | 58.9 |
Guarantees expiring in less than 1 year | 20.6 |
Guarantees expiring within 1 to 3 years | 0.1 |
Guarantees with expiration over 3 years | 38.2 |
Other guarantees | PDL | |
Guarantees | |
Total guarantees | 19 |
Other guarantees | WPS | |
Guarantees | |
Total guarantees | 20 |
Other guarantees | Integrys | |
Guarantees | |
Total guarantees | 10 |
Reciprocal guarantee | PDL | |
Guarantees | |
Total guarantees | 6.6 |
Other indemnifications | |
Guarantees | |
Total guarantees | 9.9 |
Liability related to workers compensation coverage | $ 9.2 |
Employee Benefits (Details)
Employee Benefits (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2016 | Mar. 31, 2015 | |
Components of net periodic benefit cost | ||
Contributions and payments related to pension and OPEB plans | $ 15.1 | $ 103.7 |
Pension Costs | ||
Components of net periodic benefit cost | ||
Service cost | 11.3 | 3.9 |
Interest cost | 33.2 | 15.2 |
Expected return on plan assets | (49) | (25.8) |
Amortization of prior service cost (credit) | 0.9 | 0.5 |
Amortization of net actuarial loss | 20.5 | 11.6 |
Net periodic benefit cost | 16.9 | 5.4 |
Contributions and payments related to pension and OPEB plans | 13.7 | |
Estimated future employer contributions for the remainder of the year | 8.5 | |
Other Postretirement Benefit Costs | ||
Components of net periodic benefit cost | ||
Service cost | 6.7 | 2.6 |
Interest cost | 9.2 | 4.2 |
Expected return on plan assets | (13.1) | (5.9) |
Amortization of prior service cost (credit) | (2.3) | (0.3) |
Amortization of net actuarial loss | 2.3 | 0.5 |
Net periodic benefit cost | 2.8 | $ 1.1 |
Contributions and payments related to pension and OPEB plans | 1.4 | |
Estimated future employer contributions for the remainder of the year | $ 10.8 |
Goodwill (Details)
Goodwill (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2016USD ($) | |
Goodwill | |
Accumulated impairment losses | $ 0 |
Changes to our goodwill balances by segment | |
Goodwill balance as of January 1, 2016 | 3,023.5 |
Adjustment to Integrys purchase price allocation | (24.4) |
Goodwill balance as of March 31, 2016 | 2,999.1 |
Wisconsin | |
Changes to our goodwill balances by segment | |
Goodwill balance as of January 1, 2016 | 2,109.5 |
Adjustment to Integrys purchase price allocation | (12.4) |
Goodwill balance as of March 31, 2016 | 2,097.1 |
Wisconsin | Integrys | |
Changes to our goodwill balances by segment | |
Goodwill balance as of March 31, 2016 | 1,655.2 |
Illinois | |
Changes to our goodwill balances by segment | |
Goodwill balance as of January 1, 2016 | 731.2 |
Adjustment to Integrys purchase price allocation | (8.5) |
Goodwill balance as of March 31, 2016 | 722.7 |
Other States | |
Changes to our goodwill balances by segment | |
Goodwill balance as of January 1, 2016 | 182.8 |
Adjustment to Integrys purchase price allocation | (3.5) |
Goodwill balance as of March 31, 2016 | $ 179.3 |
Investment in American Transm63
Investment in American Transmission Company - Changes to Investment (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Jun. 29, 2015 | |
Changes to investment in ATC | |||
Investment in ATC, balance at beginning of period | $ 1,380.9 | ||
Add: Earnings from equity method investment | 38.5 | $ 16.1 | |
Add: Adjustment to equity method goodwill | (24.4) | ||
Investment in ATC, balance at end of period | $ 1,422.5 | ||
ATC | |||
Investment in ATC | |||
Ownership interest in ATC (as a percent) | 60.00% | 26.20% | |
Changes to investment in ATC | |||
Investment in ATC, balance at beginning of period | $ 1,380.9 | 424.1 | |
Add: Earnings from equity method investment | 38.5 | 16.1 | |
Add: Capital contributions | 9 | 1.3 | |
Add: Adjustment to equity method goodwill | 9.3 | 0 | |
Less: Distributions received | 15.1 | 10.4 | |
Less: Other | 0.1 | 0 | |
Investment in ATC, balance at end of period | $ 1,422.5 | $ 431.1 |
Investment in American Transm64
Investment in American Transmission Company - Related Party Transactions (Details) - ATC - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Investment in ATC | |||
Charges to ATC for services and construction | $ 4.1 | $ 2.5 | |
Charges from ATC for network transmission services | 100.8 | $ 59.6 | |
Accounts receivable for services provided to ATC | 2 | $ 1 | |
Accounts payable for services received from ATC | $ 30.4 | $ 28.3 |
Investment in American Transm65
Investment in American Transmission Company - Summarized Financial Data (Details) - ATC - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Income statement data | |||
Revenues | $ 164.2 | $ 152.4 | |
Operating expenses | 79.1 | 80 | |
Other expense | 24 | 24.4 | |
Net income | 61.1 | $ 48 | |
Balance sheet data | |||
Current assets | 88.7 | $ 80.5 | |
Noncurrent assets | 4,022.1 | 3,948.3 | |
Total assets | 4,110.8 | 4,028.8 | |
Current liabilities | 337.8 | 330.3 | |
Long-term debt | 1,790.9 | 1,790.7 | |
Other noncurrent liabilities | 265.8 | 245 | |
Shareholders' equity | 1,716.3 | 1,662.8 | |
Total liabilities and shareholders' equity | $ 4,110.8 | $ 4,028.8 |
Segment Information (Details)
Segment Information (Details) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016USD ($)segment | Mar. 31, 2015USD ($) | Jun. 29, 2015 | |
Segment information | |||
Number of reportable segments | segment | 6 | ||
Revenues | $ 2,194.8 | $ 1,387.9 | |
Other operation and maintenance | 531.5 | 280.7 | |
Depreciation and amortization | 187.9 | 102.6 | |
Operating income (loss) | 589.3 | 358.8 | |
Equity in earnings of transmission affiliate | 38.5 | 16.1 | |
Interest expense | 100.9 | 59.4 | |
Intersegment revenues | |||
Segment information | |||
Revenues | 0 | 0 | |
We Power | |||
Segment information | |||
Revenues | 6.2 | 11.1 | |
Other operation and maintenance | 0.4 | 0.4 | |
Depreciation and amortization | 17 | 16.8 | |
Operating income (loss) | 93.3 | 92.5 | |
Equity in earnings of transmission affiliate | 0 | 0 | |
Interest expense | 15.6 | 15.9 | |
We Power | Intersegment revenues | |||
Segment information | |||
Revenues | 104.5 | 98.6 | |
Corporate and other | |||
Segment information | |||
Revenues | 11.9 | 0.3 | |
Other operation and maintenance | (3.5) | 10.1 | |
Depreciation and amortization | 10.1 | 0.4 | |
Operating income (loss) | (0.3) | (10.2) | |
Equity in earnings of transmission affiliate | 0 | 0 | |
Interest expense | 31.3 | 12.2 | |
Corporate and other | Intersegment revenues | |||
Segment information | |||
Revenues | 0 | 0 | |
Reconciling eliminations | |||
Segment information | |||
Revenues | 0 | 0 | |
Other operation and maintenance | (104.6) | (98.9) | |
Depreciation and amortization | 0 | 0 | |
Operating income (loss) | 0 | 0 | |
Equity in earnings of transmission affiliate | 0 | 0 | |
Interest expense | (2.7) | (0.1) | |
Reconciling eliminations | Intersegment revenues | |||
Segment information | |||
Revenues | (104.6) | (99) | |
Regulated operations | |||
Segment information | |||
Revenues | 2,176.7 | 1,376.5 | |
Other operation and maintenance | 639.2 | 369.1 | |
Depreciation and amortization | 160.8 | 85.4 | |
Operating income (loss) | 496.3 | 276.5 | |
Equity in earnings of transmission affiliate | 38.5 | 16.1 | |
Interest expense | 56.7 | 31.4 | |
Regulated operations | Intersegment revenues | |||
Segment information | |||
Revenues | 0.1 | 0.4 | |
Regulated operations | Wisconsin | |||
Segment information | |||
Revenues | 1,579.8 | 1,376.5 | |
Other operation and maintenance | 491.3 | 369.1 | |
Depreciation and amortization | 122.9 | 85.4 | |
Operating income (loss) | 327.5 | 276.5 | |
Equity in earnings of transmission affiliate | 0 | 0 | |
Interest expense | 44.5 | 31.4 | |
Regulated operations | Wisconsin | Intersegment revenues | |||
Segment information | |||
Revenues | 0.1 | 0.4 | |
Regulated operations | Illinois | |||
Segment information | |||
Revenues | 448.5 | 0 | |
Other operation and maintenance | 117.9 | 0 | |
Depreciation and amortization | 32.8 | 0 | |
Operating income (loss) | 137 | 0 | |
Equity in earnings of transmission affiliate | 0 | 0 | |
Interest expense | 9.7 | 0 | |
Regulated operations | Illinois | Intersegment revenues | |||
Segment information | |||
Revenues | 0 | 0 | |
Regulated operations | Other States | |||
Segment information | |||
Revenues | 148.4 | 0 | |
Other operation and maintenance | 30 | 0 | |
Depreciation and amortization | 5.1 | 0 | |
Operating income (loss) | 31.8 | 0 | |
Equity in earnings of transmission affiliate | 0 | 0 | |
Interest expense | 2.5 | 0 | |
Regulated operations | Other States | Intersegment revenues | |||
Segment information | |||
Revenues | 0 | 0 | |
Regulated operations | Electric transmission | |||
Segment information | |||
Revenues | 0 | 0 | |
Other operation and maintenance | 0 | 0 | |
Depreciation and amortization | 0 | 0 | |
Operating income (loss) | 0 | 0 | |
Equity in earnings of transmission affiliate | 38.5 | 16.1 | |
Interest expense | 0 | 0 | |
Regulated operations | Electric transmission | Intersegment revenues | |||
Segment information | |||
Revenues | $ 0 | 0 | |
ATC | |||
Segment information | |||
Equity method investment, ownership interest (as a percent) | 60.00% | 26.20% | |
Equity in earnings of transmission affiliate | $ 38.5 | $ 16.1 |
Variable Interest Entities (Det
Variable Interest Entities (Details) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016USD ($)MW | Mar. 31, 2015USD ($) | Dec. 31, 2015USD ($) | |
Variable interest entities | |||
Equity investment in ATC | $ 1,422.5 | $ 1,380.9 | |
ATC | |||
Variable interest entities | |||
Ownership interest in ATC (as a percent) | 60.00% | ||
Equity investment in ATC | $ 1,422.5 | 1,380.9 | |
Accounts payable due to ATC | $ 30.4 | $ 28.3 | |
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) | 6 years | ||
Residual guarantee associated with purchased power agreement | $ 0 | ||
Required payments over remaining term of purchased power agreement | 119.2 | ||
Total capacity and lease payments | 13.5 | $ 13.5 | |
Accounting Standards Update 2015-02 | |||
Variable interest entities | |||
Changes to disclosures and financial statement presentation | $ 0 |
Commitments and Contingencies -
Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions | Mar. 31, 2016USD ($) |
Minimum future commitments for purchase obligations | |
Purchase obligations | $ 12,494.4 |
Commitments and Contingencies69
Commitments and Contingencies - Environmental Matters (Details) T in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||||
Jan. 31, 2016 | Dec. 31, 2015USD ($) | Aug. 31, 2014 | Apr. 30, 2013 | Mar. 31, 2013USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($)T | Jun. 01, 2015USD ($) | |
Mercury and Other Hazardous Air Pollutants | Electric | ||||||||
Air quality | ||||||||
Percentage of mercury emissions reduction required by Wisconsin and Michigan | 90.00% | |||||||
Mercury and Other Hazardous Air Pollutants | Electric | WE | ||||||||
Air quality | ||||||||
Term of Mercury and Air Toxics Standards (MATS) compliance extension | 1 year | |||||||
Mercury and Other Hazardous Air Pollutants | Electric | WPS | ||||||||
Air quality | ||||||||
Term of Mercury and Air Toxics Standards (MATS) compliance extension | 1 year | |||||||
Climate Change | Electric | ||||||||
Air quality | ||||||||
Percentage of greenhouse gas emissions reduction nationwide | 32.00% | |||||||
Percentage of greenhouse gas emissions reduction for retirement of a nuclear plant | 10.00% | |||||||
Carbon dioxide emissions | T | 31 | |||||||
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% | |||||||
Climate Change | Natural gas | ||||||||
Air quality | ||||||||
Carbon dioxide emissions | T | 27.2 | |||||||
Clean Water Act Cooling Water Intake Structure Rule | Electric | ||||||||
Water quality | ||||||||
Number of compliance options available to meet standard | 7 | |||||||
Steam Electric Effluent Guidelines | Electric | ||||||||
Water quality | ||||||||
Renewal period for facility permits | 5 years | |||||||
Steam Electric Effluent Guidelines | Minimum | Electric | ||||||||
Water quality | ||||||||
Expected environmental costs to achieve required emission reductions | $ 95 | |||||||
Steam Electric Effluent Guidelines | Maximum | Electric | ||||||||
Water quality | ||||||||
Expected environmental costs to achieve required emission reductions | 130 | |||||||
Manufactured Gas Plant Remediation | Natural gas | ||||||||
Manufactured gas plant remediation | ||||||||
Regulatory assets recorded for cash and estimated future remediation expenditures | $ 697 | 683.7 | $ 697 | |||||
Liabilities estimated and accrued for future undiscounted investigation and cleanup costs for all sites | $ 628 | $ 617.5 | $ 628 | |||||
Weston and Pulliam Consent Decree | Electric | WPS | ||||||||
Consent decrees | ||||||||
Regulatory asset for undepreciated book value of retired plants | $ 11.5 | |||||||
Civil penalty | $ 1.2 |
Supplemental Cash Flow Inform70
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 3 Months Ended | ||
Mar. 31, 2016 | Mar. 31, 2015 | Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash (paid) for interest, net of amount capitalized | $ (40.7) | $ (20) | |
Cash (paid) for income taxes, net of refunds | (0.4) | (4.3) | |
Accounts payable related to construction costs | 90.1 | 1.6 | |
Amortization of deferred revenue | 6.2 | $ 11.1 | |
Restricted Cash and Cash Equivalents, Noncurrent | $ 95.9 | $ 118.4 |
Regulatory Environment (Details
Regulatory Environment (Details) - USD ($) $ in Millions | 1 Months Ended | ||||||||
Mar. 31, 2016 | Dec. 31, 2015 | Nov. 30, 2015 | Sep. 30, 2015 | Apr. 30, 2015 | Feb. 28, 2015 | Jan. 31, 2015 | Dec. 31, 2014 | Oct. 31, 2014 | |
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 26.6 | ||||||||
Approved annual rate increase (decrease), percentage | 0.90% | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 0 | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | 0 | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Milwaukee County steam customers | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 0 | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | |||||||||
Regulatory environment | |||||||||
Approved return on equity (as a percent) | 10.20% | ||||||||
Approved common equity component average (as a percent) | 51.00% | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Refund related to prior fuel costs and the proceeds of a Treasury Grant | $ 26.6 | ||||||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | ||||||||
System Support Resource (SSR) revenues | $ 90.7 | ||||||||
Number of other rates impacted by the Dane County Circuit Court order | 0 | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | Non-fuel costs | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 2.7 | ||||||||
Approved annual rate increase (decrease), percentage | 0.10% | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | Fuel costs | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ (13.9) | ||||||||
Approved annual rate increase (decrease), percentage | (0.50%) | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ (10.7) | ||||||||
Approved annual rate increase (decrease), percentage | (2.40%) | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 0.5 | ||||||||
Approved annual rate increase (decrease), percentage | 2.00% | ||||||||
Wisconsin Electric | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Steam rates | Milwaukee County steam customers | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 1.2 | ||||||||
Approved annual rate increase (decrease), percentage | 7.30% | ||||||||
Wisconsin Gas | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 21.4 | ||||||||
Approved annual rate increase (decrease), percentage | 3.20% | ||||||||
Wisconsin Gas | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 17.1 | ||||||||
Approved annual rate increase (decrease), percentage | 2.60% | ||||||||
Approved return on equity (as a percent) | 10.30% | ||||||||
Approved common equity component average (as a percent) | 49.50% | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | |||||||||
Regulatory environment | |||||||||
Approved return on equity (as a percent) | 10.00% | ||||||||
Approved common equity component average (as a percent) | 51.00% | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ (7.9) | ||||||||
Approved annual rate increase (decrease), percentage | (0.80%) | ||||||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | ||||||||
Authorized revenue requirement for ReACT | $ 275 | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ (6.2) | ||||||||
Approved annual rate increase (decrease), percentage | (2.10%) | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | |||||||||
Regulatory environment | |||||||||
Approved return on equity (as a percent) | 10.20% | ||||||||
Approved common equity component average (as a percent) | 50.28% | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 24.6 | ||||||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | ||||||||
Increase in cost of fuel for electric generation | $ 42 | ||||||||
Year-over-year positive (negative) change in decoupling refunded to or collected from customers | 9 | ||||||||
Customer recoveries (refunds) related to decoupling | (4) | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | (15.4) | ||||||||
Year-over-year positive (negative) change in decoupling refunded to or collected from customers | (16) | ||||||||
Customer recoveries (refunds) related to decoupling | (8) | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Customer recoveries (refunds) related to decoupling | (13) | ||||||||
WPS | Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Customer recoveries (refunds) related to decoupling | $ 8 | ||||||||
WPS | Michigan Public Service Commission (MPSC) | 2015 Rates | Electric rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 4 | ||||||||
Approved return on equity (as a percent) | 10.20% | ||||||||
Approved common equity component average (as a percent) | 50.48% | ||||||||
Period of rate implementation | 3 years | ||||||||
PGL | Illinois Commerce Commission (ICC) | 2015 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 74.8 | ||||||||
Approved return on equity (as a percent) | 9.05% | ||||||||
Approved common equity component average (as a percent) | 50.33% | ||||||||
Amended approved annual rate increase (decrease) | $ 71.1 | ||||||||
NSG | Illinois Commerce Commission (ICC) | 2015 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 3.7 | ||||||||
Approved return on equity (as a percent) | 9.05% | ||||||||
Approved common equity component average (as a percent) | 50.48% | ||||||||
Amended approved annual rate increase (decrease) | $ 3.5 | ||||||||
MERC | Minnesota Public Utilities Commission (MPUC) | 2016 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Requested annual rate increase (decrease) | $ 14.8 | ||||||||
Requested annual rate increase (decrease), percentage | 5.50% | ||||||||
Requested return on equity (as a percent) | 10.30% | ||||||||
Requested common equity component average (as a percent) | 50.32% | ||||||||
Interim rate increase | $ 9.7 | ||||||||
Interim rate increase, percentage | 3.70% | ||||||||
Interim return on equity (as a percent) | 9.35% | ||||||||
Interim common equity component average (as a percent) | 50.32% | ||||||||
MERC | Minnesota Public Utilities Commission (MPUC) | 2015 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 7.6 | ||||||||
Approved return on equity (as a percent) | 9.35% | ||||||||
Approved common equity component average (as a percent) | 50.31% | ||||||||
Annual cap for decoupling mechanism (as a percent of rate case approved distribution revenues) | 10.00% | ||||||||
Interim rates refunded to customers | $ 4.7 | ||||||||
MGU | Michigan Public Service Commission (MPSC) | 2016 Rates | Natural gas rates | |||||||||
Regulatory environment | |||||||||
Approved annual rate increase (decrease) | $ 3.4 | ||||||||
Approved annual rate increase (decrease), percentage | 2.40% | ||||||||
Approved return on equity (as a percent) | 9.90% | ||||||||
Approved common equity component average (as a percent) | 52.00% |