Document and Entity Information
Document and Entity Information Document - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Jan. 31, 2018 | Jun. 30, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | WISCONSIN ELECTRIC POWER CO | ||
Entity Central Index Key | 107,815 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Non-accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 33,289,327 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 0 |
Consolidated Income Statements
Consolidated Income Statements - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Statement [Abstract] | |||
Operating revenues | $ 3,711.7 | $ 3,792.8 | $ 3,854.1 |
Cost of sales | 1,286.4 | 1,292.1 | 1,399 |
Other operation and maintenance | 1,358.5 | 1,430.2 | 1,384.9 |
Depreciation and amortization | 331.6 | 325.4 | 304 |
Property and revenue taxes | 109.6 | 115.6 | 117.3 |
Total operating expenses | 3,086.1 | 3,163.3 | 3,205.2 |
Operating income | 625.6 | 629.5 | 648.9 |
Equity in earnings of transmission affiliate | 0 | 55.5 | 47.8 |
Other income, net | 19.7 | 9.1 | 11.2 |
Interest expense | 117.3 | 117.6 | 119 |
Other expense | (97.6) | (53) | (60) |
Income before income taxes | 528 | 576.5 | 588.9 |
Income tax expense | 191.2 | 211 | 212 |
Net income | 336.8 | 365.5 | 376.9 |
Preferred stock dividend requirements | 1.2 | 1.2 | 1.2 |
Net income attributed to common shareholder | $ 335.6 | $ 364.3 | $ 375.7 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and cash equivalents | $ 12.3 | $ 15.4 |
Accounts receivable, net of allowance for doubtful accounts of $39.5 and $40.9, respectively | 513.8 | 503.2 |
Accounts receivable from related parties | 109.1 | 58.2 |
Materials, supplies, and inventories | 250.7 | 271 |
Prepayments | 144.3 | 138 |
Other | 9.4 | 24.6 |
Total current assets | 1,039.6 | 1,010.4 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation of $3,741.8 and $3,619.6, respectively | 10,007.7 | 9,832.3 |
Regulatory assets | 1,984.9 | 2,036.6 |
Equity investment in transmission affiliate | 0 | 402 |
Other | 89.4 | 90.2 |
Long-term assets | 12,082 | 12,361.1 |
Total Assets | 13,121.6 | 13,371.5 |
Current Liabilities | ||
Short-term debt | 210.9 | 159 |
Current portion of long-term debt | 250 | 0 |
Capital Lease Obligations, Current | 42.5 | 28.5 |
Subsidiary note payable to WEC Energy Group | 0 | 18.5 |
Accounts payable | 329.3 | 297.9 |
Accounts payable to related parties | 131.5 | 112.9 |
Accrued payroll and benefits | 53.4 | 51.8 |
Accrued taxes | 58.2 | 46 |
Other | 111.8 | 100.1 |
Current liabilities | 1,187.6 | 814.7 |
Long-term liabilities | ||
Long-term debt | 2,412.3 | 2,661.1 |
Capital lease obligations | 2,823.8 | 2,756.5 |
Deferred income taxes | 1,155.5 | 2,333.3 |
Regulatory liabilities | 1,708 | 853.9 |
Pension and OPEB obligations | 143.2 | 167.6 |
Other | 276.9 | 260.2 |
Long-term liabilities | 8,519.7 | 9,032.6 |
Commitments and contingencies (Note 19) | ||
Common shareholder's equity | ||
Common stock - $10 par value; 65,000,000 shares authorized; 33,289,327 shares outstanding | 332.9 | 332.9 |
Additional paid in capital | 802.7 | 1,020.1 |
Retained earnings | 2,248.3 | 2,140.8 |
Common shareholder's equity | 3,383.9 | 3,493.8 |
Preferred stock | 30.4 | 30.4 |
Total liabilities and equity | $ 13,121.6 | $ 13,371.5 |
Consolidated Balance Sheets Par
Consolidated Balance Sheets Parenthetical (Parentheticals) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Allowance for doubtful accounts receivable | $ 39.5 | $ 40.9 |
Property, plant, and equipment, accumulated depreciation | $ 3,741.8 | $ 3,619.6 |
Common stock, par value | $ 10 | |
Common stock, shares authorized | 65,000,000 | |
Common stock, shares outstanding | 33,289,327 | 33,289,327 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Cash Flows [Abstract] | |||
Net income | $ 336.8 | $ 365.5 | $ 376.9 |
Reconciliation to cash provided by operating activities | |||
Depreciation and amortization | 331.6 | 325.4 | 323.7 |
Deferred income taxes and investment tax credits, net | 109.7 | 206.2 | 178.9 |
Contributions and payments related to pension and OPEB plans | (8.3) | (8) | (107.6) |
Equity income in transmission affiliate, net of distributions | 0 | (17.2) | (4.9) |
Payments for liabilities transferred to WBS | (0.3) | (116) | 0 |
Change In | |||
Accounts receivable and unbilled revenues | (64.9) | (59) | (2.9) |
Material, supplies, and inventories | 20.3 | 30.6 | 18.8 |
Prepaid taxes | 0.5 | 39.4 | (2.8) |
Other current assets | (11.8) | 9.3 | 0.3 |
Accounts payable | 45.8 | 31.3 | (5.9) |
Accrued taxes | 12.8 | 30.4 | (42.1) |
Other current liabilities | 12.2 | 10.7 | (1.2) |
Other, net | (86.4) | (0.2) | (56.8) |
Net cash provided by operating activities | 698 | 848.4 | 674.4 |
Investing Activities | |||
Capital expenditures | (596.1) | (469.5) | (519.2) |
Capital contributions to transmission affiliate | 0 | (16.1) | (4.6) |
Proceeds from the sale of assets | 22.9 | 31.7 | 0.2 |
Proceeds from assets transferred to WBS | 0 | 13.1 | 0 |
Other, net | 5 | 4 | 3.4 |
Net cash used in investing activities | (568.2) | (436.8) | (520.2) |
Financing Activities | |||
Change in short-term debt | 51.9 | 15 | (162.8) |
Repayment of subsidiary note to parent | (18.5) | (1.1) | (2.9) |
Issuance of long-term debt | 0 | 0 | 500 |
Retirement of long-term debt | 0 | 0 | (250) |
Equity contribution from parent | 75 | 0 | 0 |
Payment of dividends to parent | (240) | (455) | (240) |
Payment of preferred stock dividends | (1.2) | (1.2) | (1.2) |
Other, net | (0.1) | 19 | 5.8 |
Net cash used in financing activities | (132.9) | (423.3) | (151.1) |
Net change in cash and cash equivalents | (3.1) | (11.7) | 3.1 |
Cash and cash equivalents at beginning of year | 15.4 | 27.1 | 24 |
Cash and cash equivalents at end of year | $ 12.3 | $ 15.4 | $ 27.1 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Millions | Total | Total Common Shareholders' Equity | Common Stock | Additional Paid-In Capital | Retained Earnings | Preferred Stock | UMERC transfer | UMERC transferTotal Common Shareholders' Equity | UMERC transferCommon Stock | UMERC transferAdditional Paid-In Capital | UMERC transferRetained Earnings | UMERC transferPreferred Stock | Transfer of investment in ATC [Member] | Transfer of investment in ATC [Member]Total Common Shareholders' Equity | Transfer of investment in ATC [Member]Common Stock | Transfer of investment in ATC [Member]Additional Paid-In Capital | Transfer of investment in ATC [Member]Retained Earnings | Transfer of investment in ATC [Member]Preferred Stock | Equity settlement of Bostco Intercompany Receivable [Member] | Equity settlement of Bostco Intercompany Receivable [Member]Total Common Shareholders' Equity | Equity settlement of Bostco Intercompany Receivable [Member]Common Stock | Equity settlement of Bostco Intercompany Receivable [Member]Additional Paid-In Capital | Equity settlement of Bostco Intercompany Receivable [Member]Retained Earnings | Equity settlement of Bostco Intercompany Receivable [Member]Preferred Stock |
Balance at Dec. 31, 2014 | $ 3,443.2 | $ 3,412.8 | $ 332.9 | $ 984.4 | $ 2,095.5 | $ 30.4 | ||||||||||||||||||
Equity | ||||||||||||||||||||||||
Net income | 376.9 | 376.9 | 0 | 0 | 376.9 | 0 | ||||||||||||||||||
Dividends | ||||||||||||||||||||||||
Common stock dividends | (240) | (240) | 0 | 0 | (240) | 0 | ||||||||||||||||||
Preferred stock dividends | (1.2) | (1.2) | 0 | 0 | (1.2) | 0 | ||||||||||||||||||
Tax benefit of exercised stock options allocated from parent | 12.1 | 12.1 | 0 | 12.1 | 0 | 0 | ||||||||||||||||||
Stock-based compensation and other | 3.4 | 3.4 | 0 | (3.2) | 0.2 | 0 | ||||||||||||||||||
Equity contribution from parent | 0 | |||||||||||||||||||||||
Balance at Dec. 31, 2015 | 3,594.4 | 3,564 | 332.9 | 999.7 | 2,231.4 | 30.4 | ||||||||||||||||||
Equity | ||||||||||||||||||||||||
Net income | 365.5 | 365.5 | 0 | 0 | 365.5 | 0 | ||||||||||||||||||
Dividends | ||||||||||||||||||||||||
Common stock dividends | (455) | (455) | 0 | 0 | (455) | 0 | ||||||||||||||||||
Preferred stock dividends | (1.2) | (1.2) | 0 | 0 | (1.2) | 0 | ||||||||||||||||||
Tax benefit of exercised stock options allocated from parent | 19.3 | 19.3 | 0 | 19.3 | 0 | 0 | ||||||||||||||||||
Stock-based compensation and other | 1.2 | 1.2 | 0 | (1.1) | 0.1 | 0 | ||||||||||||||||||
Equity contribution from parent | 0 | |||||||||||||||||||||||
Balance at Dec. 31, 2016 | 3,524.2 | 3,493.8 | 332.9 | 1,020.1 | 2,140.8 | 30.4 | ||||||||||||||||||
Dividends | ||||||||||||||||||||||||
Cumulative effect adjustment from adoption of ASU 2016-09 | 11.9 | 11.9 | 0 | 0 | 11.9 | 0 | ||||||||||||||||||
Net income | 336.8 | 336.8 | 0 | 0 | 336.8 | 0 | ||||||||||||||||||
Common stock dividends | (240) | (240) | 0 | 0 | (240) | 0 | ||||||||||||||||||
Preferred stock dividends | (1.2) | (1.2) | 0 | 0 | (1.2) | 0 | ||||||||||||||||||
Stock-based compensation and other | 2.1 | 2.1 | 0 | (2.1) | 0 | 0 | ||||||||||||||||||
Equity contribution from parent | 75 | 75 | 0 | 75 | 0 | 0 | ||||||||||||||||||
Transfer of net assets to UMERC | $ (61.1) | $ (61.1) | $ 0 | $ (61.1) | $ 0 | $ 0 | ||||||||||||||||||
Transfer of ATC ownership interest and related taxes | $ (228.6) | $ (228.6) | $ 0 | $ (228.6) | $ 0 | $ 0 | ||||||||||||||||||
Settlement of a short-tern note receivable between Bostco and our parent company | $ (4.8) | $ (4.8) | $ 0 | $ (4.8) | $ 0 | $ 0 | ||||||||||||||||||
Balance at Dec. 31, 2017 | $ 3,414.3 | $ 3,383.9 | $ 332.9 | $ 802.7 | $ 2,248.3 | $ 30.4 |
Consolidated Statements of Capi
Consolidated Statements of Capitalization - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Common shareholder's equity | $ 3,383.9 | $ 3,493.8 |
Preferred stock | 30.4 | 30.4 |
Obligations under capital leases | 2,866.3 | 2,785 |
Total | 5,551.3 | 5,472 |
Unamortized debt issuance costs | (3.2) | (3.6) |
Unamortized discount, net | (19.5) | (22.3) |
Total long-term debt and capital lease obligations, including current portion | 5,528.6 | 5,446.1 |
Current portion of long-term debt and capital lease obligations | (292.5) | (28.5) |
Total long-term debt and capital lease obligations | 5,236.1 | 5,417.6 |
Total long-term capitalization | $ 8,650.4 | 8,941.8 |
Debentures (unsecured), 1.70% due 2018 | ||
Interest rate, (as a percent) | 1.70% | |
Long-term Debt, unsecured | $ 250 | 250 |
Debentures (unsecured), 4.25% due 2019 | ||
Interest rate, (as a percent) | 4.25% | |
Long-term Debt, unsecured | $ 250 | 250 |
Debentures (unsecured), 2.95% due 2021 | ||
Interest rate, (as a percent) | 2.95% | |
Long-term Debt, unsecured | $ 300 | 300 |
Debentures (unsecured), 3.10% due 2025 | ||
Interest rate, (as a percent) | 3.10% | |
Long-term Debt, unsecured | $ 250 | 250 |
Debentures (unsecured), 6.50% due 2028 | ||
Interest rate, (as a percent) | 6.50% | |
Long-term Debt, unsecured | $ 150 | 150 |
Debentures (unsecured), 5.625% due 2033 | ||
Interest rate, (as a percent) | 5.625% | |
Long-term Debt, unsecured | $ 335 | 335 |
Debentures (unsecured), 5.70% due 2036 | ||
Interest rate, (as a percent) | 5.70% | |
Long-term Debt, unsecured | $ 300 | 300 |
Debentures (unsecured), 3.65% due 2042 | ||
Interest rate, (as a percent) | 3.65% | |
Long-term Debt, unsecured | $ 250 | 250 |
Debentures (unsecured), 4.25% due 2044 | ||
Interest rate, (as a percent) | 4.25% | |
Long-term Debt, unsecured | $ 250 | 250 |
Debentures (unsecured), 4.30% due 2045 | ||
Interest rate, (as a percent) | 4.30% | |
Long-term Debt, unsecured | $ 250 | 250 |
Debentures (unsecured), 6.875% due 2095 | ||
Interest rate, (as a percent) | 6.875% | |
Long-term Debt, unsecured | $ 100 | 100 |
Note (secured, nonrecourse), 4.81% due 2030 | ||
Interest rate, (as a percent) | 4.81% | |
Long-term Debt, secured | $ 0 | $ 2 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) Nature of Operations —On June 29, 2015, our parent company, Wisconsin Energy Corporation, acquired Integrys and changed its name to WEC Energy Group, Inc. See Note 2, Acquisitions, for more information on this acquisition. We are an electric, natural gas, and steam utility company that serves electric customers in Wisconsin and an iron ore mine owned by Tilden in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and it became operational effective January 1, 2017. This utility holds the electric assets previously held by us and the electric and natural gas distribution assets previously held by WPS, located in the Upper Peninsula of Michigan. The existing contract between us and Tilden will remain in place until a new power generation solution for the region is commercially operational, which is expected to occur in 2019. As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted. Through December 31, 2017 , we had one wholly owned subsidiary, Bostco. At December 31, 2016, Bostco had total assets of $24.4 million . In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 3, Dispositions, for more information . The financial statements include our accounts and the accounts of our wholly owned subsidiary. The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. (b) Basis of Presentation —We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. (d) Revenues and Customer Receivables —We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers. We present revenues net of pass-through taxes on the income statements. Below is a summary of the significant mechanisms we had in place that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts: • Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations. • Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. • We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 21, Regulatory Environment , for more information. • Our natural gas utility rates included a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. • Our residential rates included a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Revenues are also impacted by other accounting policies related to our participation in the MISO Energy Markets. We sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If we were a net seller in a particular hour, the net amount was reported as operating revenues. If we were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements. We provide regulated electric, natural gas, and steam service to customers in Wisconsin and to Tilden located in the Upper Peninsula of Michigan, and provided electric service to other customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 4, Related Parties , and Note 21, Regulatory Environment , for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2017 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2017 . (e) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2017 2016 Materials and supplies $ 140.7 $ 148.1 Fossil fuel 74.8 91.1 Natural gas in storage 35.2 31.8 Total $ 250.7 $ 271.0 Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. (f) Regulatory Assets and Liabilities —The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. See Note 5, Regulatory Assets and Liabilities, for more information . (g) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW and MPSC that include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.95% , 3.00% , and 3.01% in 2017 , 2016 , and 2015 , respectively. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment. Third parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. See Note 6, Property, Plant, and Equipment, for more information . (h) Allowance for Funds Used During Construction —AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. Approximately 50% of our retail jurisdictional CWIP expenditures are subject to the AFUDC calculation. Our average AFUDC retail rates were 8.45% for 2017 , 2016 , and 2015 . Our average AFUDC wholesale rates were 5.94% , 2.73% , and 1.72% for 2017 , 2016 , and 2015 , respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2017 2016 2015 AFUDC – Debt $ 1.2 $ 1.7 $ 2.2 AFUDC – Equity $ 3.1 $ 4.2 $ 5.7 (i) Asset Retirement Obligations —We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. See Note 7, Asset Retirement Obligations, for more information . (j) Asset Impairment —We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets applicable criteria to be considered probable of abandonment, we assess the likelihood of recovery of the remaining carrying value of that generating unit at the end of each reporting period. If it becomes probable that regulators will not allow full recovery as well as a return on the remaining net book value of the abandoned generating unit, an impairment charge may be required. An impairment charge would be recorded if the remaining carrying value of the abandoned generating unit is greater than the present value of the amount expected to be recovered from ratepayers. See Note 6, Property, Plant, and Equipment, for more information . (k) Stock-Based Compensation —Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million . Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to increase retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. As we did not record any excess tax benefits in 2017, adoption of ASU 2016-09 had no impact on our financial statements other than the cumulative-effect adjustment discussed above. Stock Options Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after a three -year period. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2017 2016 2015 Stock options granted * 80,770 92,880 495,550 Estimated weighted-average fair value per stock option $ 7.12 $ 4.92 $ 5.29 Assumptions used to value the options: Risk-free interest rate 0.7% – 2.5% 0.5% – 2.2% 0.1% – 2.1% Dividend yield 3.5 % 4.0 % 3.7 % Expected volatility 19.0 % 18.0 % 18.0 % Expected life (years) 6.2 5.8 5.8 * Effective January 1, 2016, certain employees were transferred into WBS. See Note 4, Related Parties, for more information . The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares granted to our employees have a three -year vesting period with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. Performance units granted on or after January 1, 2016 also accrue forfeitable dividend equivalents in the form of additional performance units. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are recorded over the three -year performance period. See Note 8, Common Equity , for more information on WEC Energy Group's stock-based compensation plans. (l) Income Taxes —We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 12, Income Taxes, for more information . We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. (m) Fair Value Measurements —Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term debt, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. See Note 13, Fair Value Measurements, for more information . (n) Derivative Instruments —We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on our income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. See Note 14, Derivative Instruments, for more information . (o) Employee Benefits —The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. See Note 15, Employee Benefits, for more information . (p) Customer Deposits and Credit Balances —When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets. Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets. (q) Environmental Remediation Costs —We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 7, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 19, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the PSCW's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
ACQUISITIONS | ACQUISITIONS Parent Company's Acquisition of Natural Gas Storage Facilities in Michigan On June 30, 2017, our parent company completed the acquisition of Bluewater for $226.0 million . Bluewater owns natural gas storage facilities in Michigan that will provide a portion of the current storage needs for our natural gas utility operations. In September 2017, we entered into a long-term service agreement with a wholly owned subsidiary of Bluewater to take the allocated storage, which was then approved by the PSCW in November 2017. See Note 21, Regulatory Environment, for more information . Parent Company's Acquisition of Integrys On June 29, 2015, our parent company acquired 100% of the outstanding common shares of Integrys and changed its name to WEC Energy Group, Inc. Integrys is a provider of regulated natural gas and electricity, as well as nonregulated renewable energy. The acquisition was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order includes the following conditions: • We are subject to an earnings sharing mechanism for three years beginning January 1, 2016. Under the earnings sharing mechanism, if we earn over our authorized rate of return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and will reduce our transmission escrow. All utility earnings above the first 50 basis points will be solely used to reduce the transmission escrow. For the years ended December 31, 2017 and 2016, we recorded $0.1 million and $21.1 million of expense related to this earnings sharing mechanism, respectively. • Any future electric generation projects affecting Wisconsin ratepayers submitted by WEC Energy Group or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. In September 2015, we and WPS filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that no new generation was needed at the time. In 2015, we recorded $6.6 million of severance expense that resulted from employee reductions related to the post-acquisition integration. The severance expense was recorded in our utility segment and is included in the other operation and maintenance line item on the income statements. Severance expense incurred after 2015 was not significant. Severance payments made during 2017 were not significant. Severance payments of $4.6 million and $1.2 million were made during 2016 and 2015, respectively. The severance accrual on our balance sheets at December 31, 2017 and 2016 related to the acquisition of Integrys was not significant. |
Dispositions
Dispositions | 12 Months Ended |
Dec. 31, 2017 | |
Discontinued Operations and Disposal Groups [Abstract] | |
DISPOSITIONS | DISPOSITIONS Utility Segment Sale of Milwaukee County Power Plant In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of $10.9 million ( $6.5 million after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. Other Segment Sale of Bostco Real Estate Holdings In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
RELATED PARTIES | RELATED PARTIES We routinely enter into transactions with related parties, including WEC Energy Group, its other subsidiaries, ATC, and other affiliated entities. We provide and receive services, property, and other items of value to and from our parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the acquisition of Integrys by Wisconsin Energy Corporation on June 29, 2015, an AIA (Non-WBS AIA) went into effect. The Non-WBS AIA governed the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS continued to provide services to Integrys and its subsidiaries only under the existing WBS AIAs. WBS provided services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries, including us, under interim WBS AIAs. The PSCW and all other relevant state commissions approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA. Services under the Non-WBS AIA were subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary were priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary were priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary were priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS were priced at cost. WBS provided several categories of services (including financial, human resource, and administrative services) to us pursuant to the interim WBS AIAs, which were approved, or from which we were granted appropriate waivers, by the appropriate regulators, including the PSCW. As required by FERC regulations for centralized service companies, WBS renders services at cost. The PSCW must be notified prior to making changes to the services offered under and the allocation methods specified in the interim WBS AIAs. Other modifications or amendments to the interim WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases. A new AIA took effect January 1, 2017. The new agreement replaced the previous agreements. The pricing methodology and services under this new agreement are substantially identical to those under the agreements that were replaced. All of the applicable state commissions approved modifications to the new AIA to incorporate WEC Energy Group's acquisition of Bluewater. See Note 2, Acquisitions, for more information on the acquisition. Effective January 1, 2016, 485 of our employees were transferred into WBS. In connection with this transfer of employees, certain benefit-related liabilities were also transferred to WBS. In addition, we transferred certain software assets to WBS in 2016. Bostco, our consolidated subsidiary, had a note payable to our parent company, WEC Energy Group. The balance of this note payable was $18.5 million at December 31, 2016 , which was paid off in the first half of 2017. In connection with the sale of Bostco’s remaining real estate holdings, Wispark, a subsidiary of WEC Energy Group, provided $7.0 million of financing to the buyer and established a corresponding note receivable. Bostco had a $7.0 million related party receivable from Wispark that was paid in April 2017. See Note 3, Dispositions, for more information on the real estate sale. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our $415.4 million investment in ATC, and the related receivable for distributions approved and recorded in December 2016, to another subsidiary of WEC Energy Group. In addition, we transferred $186.8 million of related deferred income tax liabilities. These transactions were non-cash equity transfers recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which is reimbursed by ATC. Services are billed to and from ATC under agreements approved by the PSCW, at each of our fully allocated costs. Our balance sheets included the following receivables and payables related to transactions entered into with ATC: (in millions) 2017 2016 Accounts receivable Services provided to ATC $ 0.8 $ 1.1 Accounts payable Services received from ATC 22.2 20.0 The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2017 2016 2015 Lease agreements Lease payments to We Power (1) $ 420.5 $ 412.2 $ 410.5 CWIP billed to We Power 57.3 37.9 58.8 Transactions with WBS (2) Billings to WBS (3) 255.7 213.8 11.1 Billings from WBS (4) 215.4 310.6 1.3 Transactions with WPS (2) Natural gas purchases from WPS 1.6 1.9 0.4 Billings to WPS 28.2 9.0 13.4 Billings from WPS 4.5 4.2 4.9 Transactions with WG Natural gas purchases from WG 5.3 5.3 5.3 Billings to WG 64.0 60.6 79.4 Billings from WG 23.1 21.5 23.5 Transactions with UMERC (5) Electric sales to UMERC 30.8 — — Billings to UMERC (2) 125.5 — — Transactions with Bluewater (6) Storage service fees 2.7 — — Transactions with ATC Charges to ATC for services and construction 10.9 10.0 9.7 Charges from ATC for network transmission services 241.4 247.8 238.5 Refund from ATC per FERC ROE order (19.4 ) — — (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. (2) Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs. (3) Includes $1.2 million , for the transfer of certain benefit-related liabilities from WBS for the year ended December 31, 2017 . For the year ended December 31, 2016 , includes $13.1 million for the transfer of certain software assets to WBS. There were no transfers of assets to WBS during the year ended December 31, 2017 , and there were no transfers of liabilities from WBS for the year ended December 31, 2016 . (4) For the year ended December 31, 2017 and 2016 , includes $1.5 million and $116.0 million , respectively, for the transfer of certain benefit-related liabilities to WBS. (5) UMERC became operational effective January 1, 2017. See below for more information. (6) The acquisition of Bluewater was completed on June 30, 2017. See below for more information. Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan. UMERC, a subsidiary of WEC Energy Group, became operational effective January 1, 2017, and we transferred customers and property, plant, and equipment as of that date. See Note 21, Regulatory Environment, for more information . We transferred approximately 27,500 retail electric customers and 50 electric distribution-only customers to UMERC, along with approximately 2,500 miles of electric distribution lines. We also transferred related electric distribution substations in the Upper Peninsula of Michigan and all property rights for the distribution assets to UMERC. The book value of net assets, including the related deferred income tax liabilities, transferred to UMERC from us as of January 1, 2017, was $61.1 million . This transaction was a non-cash equity transfer recorded to additional paid in capital between entities under common control, and therefore, did not result in the recognition of a gain or loss. UMERC currently meets its market obligations through power purchase agreements with us and WPS. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES We recorded a $1,065 million change in our deferred taxes due to the enactment of the Tax Legislation, which resulted in both an increase to income tax related regulatory liabilities as well as a decrease to certain existing income tax related regulatory assets represented in Income tax related items in the table below. The $1,065 million change in our deferred taxes represents our estimate of the tax benefit that will be returned to ratepayers through future refunds, bill credits, or reductions in other regulatory assets. See Note 12, Income Taxes, for more information on the Tax Legislation. The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2017 2016 See Note Regulatory assets (1) (2) Plant related – capital leases $ 801.3 $ 724.8 11 Unrecognized pension and OPEB costs (3) 484.4 520.3 15 SSR 298.9 188.1 21 Electric transmission costs 220.7 231.9 21 We Power generation (4) 71.3 54.1 AROs 41.4 39.7 7 Environmental remediation costs (5) 30.4 29.9 19 Energy efficiency programs (6) 28.2 38.5 Income tax related items — 200.8 12 Other, net 8.3 8.5 Total regulatory assets $ 1,984.9 $ 2,036.6 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in the table. (2) As of December 31, 2017 , we had $11.4 million of regulatory assets not earning a return and $254.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. The other regulatory assets in the table either earn a return or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) Represents amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions. See Note 11, Long-Term Debt and Capital Lease Obligations, for more information on the Tax Legislation impacts on the lease payments. (5) As of December 31, 2017 , we had not yet made cash expenditures for $18.5 million of these environmental remediation costs. (6) Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2017 2016 See Note Regulatory liabilities 2017 Tax Legislation impact and income tax related $ 849.1 $ — 12 Removal costs (1) 730.0 722.9 Mines deferral (2) 95.1 70.2 Other, net 46.9 71.0 Total regulatory liabilities $ 1,721.1 $ 864.1 Balance Sheet Presentation Current liabilities $ 13.1 $ 10.2 Regulatory liabilities 1,708.0 853.9 Total regulatory liabilities $ 1,721.1 $ 864.1 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents the deferral of revenues less the associated cost of sales related to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding. |
Property, Plant, and Equipment
Property, Plant, and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY, PLANT, AND EQUIPMENT | PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31: (in millions) 2017 2016 Utility property, plant, and equipment (1) $ 9,870.7 $ 11,232.9 Less: Accumulated depreciation 2,970.3 3,606.9 Net 6,900.4 7,626.0 CWIP 159.5 111.5 Plant to be retired, net 872.7 — Net utility property, plant, and equipment 7,932.6 7,737.5 Property under capital leases 3,009.1 2,898.0 Less: Accumulated amortization 945.9 837.8 Net leased facilities 2,063.2 2,060.2 Non-utility and other property, plant, and equipment 11.9 46.4 Less: Accumulated depreciation — 12.7 Net (2) 11.9 33.7 CWIP — 0.9 Net non-utility and other property, plant, and equipment 11.9 34.6 Total property, plant, and equipment $ 10,007.7 $ 9,832.3 (1) Effective January 1, 2017, we transferred 2,500 miles of electric distribution lines and related electric distribution substations in the Upper Peninsula of Michigan to UMERC. The net book value of the property, plant, and equipment we transferred to UMERC was $61.1 million . See Note 4, Related Parties, for more information . (2) In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. Utility Segment Plant to be Retired We have evaluated future plans for our older and less efficient fossil fuel generating units and have announced our plans for the retirement of the plants identified below. The net book value of these plants was classified as plant to be retired within property, plant, and equipment on our balance sheet at December 31, 2017. In addition, severance expense in the amount of $25.8 million was recorded within the utility segment in 2017 related to these announced plant retirements. Pleasant Prairie Power Plant As a result of a MISO ruling in December 2017, Pleasant Prairie must be shut down no later than April 10, 2018. Because we had an obligation at December 31, 2017 to shut down the Pleasant Prairie plant in April 2018, retirement of the plant was probable at December 31, 2017 . The net book value of this generating unit was $681.3 million at December 31, 2017 . This amount was classified as plant to be retired within property, plant, and equipment on our balance sheet. This unit is included in rate base, and we continue to depreciate it on a straight-line basis using the composite depreciation rates approved by the PSCW. The physical dismantlement of the plant will not occur immediately. It may take several years to finalize long-term plans for the site. See Note 19, Commitments and Contingencies, for more information . Presque Isle Power Plant In October 2017, the MPSC approved UMERC’s application to construct and operate approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. Upon receiving this approval, retirement of the PIPP generating units became probable. The new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. The net book value of these units was $191.4 million at December 31, 2017 . These units are included in rate base, and we continue to depreciate them on a straight-line basis using the composite depreciation rates approved by the PSCW. The net book value of these assets was transferred from plant in service to plant to be retired. See Note 19, Commitments and Contingencies, for more information . |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS We have recorded AROs primarily for asbestos abatement at certain generation and substation facilities, the removal and dismantlement of generation facilities, and the closure of fly-ash landfills at our generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the rate-making practices for retirement costs authorized by the applicable regulators. On our balance sheets, AROs are recorded within other long-term liabilities. The following table shows changes to our AROs during the years ended December 31: (in millions) 2017 2016 2015 Balance as of January 1 $ 61.5 $ 58.7 $ 40.5 Accretion 3.2 3.0 2.3 Additions 5.5 (1) — 15.9 (2) Liabilities settled (1.9 ) (0.2 ) — Balance as of December 31 $ 68.3 $ 61.5 $ 58.7 (1) During 2017, an ARO was recorded related to the removal and dismantlement of the Rothschild Biomass Plant. (2) During 2015, an ARO was recorded for the fly-ash landfills located at our generation facilities. |
Common Equity
Common Equity | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation Plans The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31: (in millions) 2017 2016 2015 Stock options $ 1.3 $ 1.8 $ 3.2 Restricted stock 0.8 1.8 2.1 Performance units 9.9 3.9 7.5 Stock-based compensation expense $ 12.0 $ 7.5 $ 12.8 Related tax benefit $ 4.8 $ 3.0 $ 5.1 Stock-based compensation costs capitalized during 2017 , 2016 , and 2015 were not significant. Stock Options The following is a summary of our employees' WEC Energy Group stock option activity during 2017 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2017 1,285,806 $ 33.41 Granted 80,770 $ 58.31 Exercised (300,064 ) $ 25.54 Transferred 129,635 $ 35.48 Outstanding as of December 31, 2017 1,196,147 $ 37.29 4.6 $ 34.9 Exercisable as of December 31, 2017 971,547 $ 33.43 3.8 $ 32.1 The aggregate intrinsic value of outstanding and exercisable options in the above table represents the total pre-tax intrinsic value that would have been received by the option holders had they exercised all of their options on December 31, 2017 . This is calculated as the difference between WEC Energy Group's closing stock price on December 31, 2017 , and the option exercise price, multiplied by the number of in-the-money stock options. The intrinsic value of options exercised during the years ended December 31, 2017 , 2016 , and 2015 was $11.2 million , $14.1 million , and $34.6 million , respectively. Cash received by WEC Energy Group from exercises of its options by our employees was $7.7 million , $12.1 million , and $29.2 million during the years ended December 31, 2017 , 2016 , and 2015 , respectively. The actual tax benefit from option exercises for the same periods was approximately $4.5 million , $5.6 million , and $14.0 million , respectively. As of December 31, 2017 , we expected to recognize approximately $0.9 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group stock options over the next 1.7 years on a weighted-average basis. During the first quarter of 2018 , the Compensation Committee awarded 81,730 non-qualified WEC Energy Group stock options with an exercise price of $66.02 and a weighted-average grant date fair value of $7.26 per option to certain of our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restricted Shares The following is a summary of our employees' WEC Energy Group restricted stock activity during 2017 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2017 16,261 $ 50.39 Granted 8,001 $ 58.10 Released (8,018 ) $ 48.78 Transferred (379 ) $ 57.77 Forfeited (582 ) $ 53.83 Outstanding as of December 31, 2017 15,283 $ 54.96 The intrinsic value of WEC Energy Group restricted stock held by our employees that was released was $0.5 million , $0.4 million , and $2.7 million for the years ended December 31, 2017 , 2016 , and 2015 , respectively. The actual tax benefit from released restricted shares for the same years was $0.2 million , $0.2 million , and $1.1 million , respectively. As of December 31, 2017 , we expected to recognize approximately $1.2 million of unrecognized compensation cost related to WEC Energy Group restricted stock over the next 1.7 years on a weighted-average basis. During the first quarter of 2018 , the Compensation Committee awarded 7,518 WEC Energy Group restricted shares to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. The grant date fair value of these awards was $64.99 per share. Performance Units During 2017 , 2016 , and 2015 , the Compensation Committee awarded 34,765 ; 35,700 ; and 187,450 WEC Energy Group performance units, respectively, to our officers and other key employees under the WEC Energy Group Performance Unit Plan. In 2016, we transferred 573,499 performance units to WBS in connection with the transfer of certain employees. See Note 4, Related Parties, for more information . Performance units with an intrinsic value of $1.4 million , $3.4 million , and $11.6 million were settled during 2017 , 2016 , and 2015 , respectively. The actual tax benefit from the distribution of performance units for the same years was approximately $0.4 million , $0.5 million , and $4.2 million , respectively. At December 31, 2017 , we had 96,577 performance units outstanding, including dividend equivalents. A liability of $4.9 million was recorded on our balance sheet at December 31, 2017 related to these outstanding units. As of December 31, 2017 , we expected to recognize approximately $3.6 million of unrecognized compensation cost related to unvested and outstanding WEC Energy Group performance units over the next 1.4 years on a weighted-average basis. During the first quarter of 2018 , performance units held by our employees with an intrinsic value of $1.8 million were settled. The actual tax benefit from the distribution of these awards was $0.4 million . In January 2018 , the Compensation Committee also awarded 32,650 WEC Energy Group performance units to our officers and other key employees under its normal schedule of awarding long-term incentive compensation. Restrictions Various financing arrangements and regulatory requirements impose certain restrictions on our ability to transfer funds to WEC Energy Group in the form of cash dividends, loans, or advances. In addition, Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group or its subsidiaries. In accordance with our most recent rate order, we may not pay common dividends above the test year forecasted amount reflected in our rate case, if it would cause our average common equity ratio, on a financial basis, to fall below our authorized level of 51% . A return of capital in excess of the test year amount can be paid by us at the end of the year provided that our average common equity ratio does not fall below the authorized level. We may not pay common dividends to WEC Energy Group under our Restated Articles of Incorporation if any dividends on our outstanding preferred stock have not been paid. In addition, pursuant to the terms of our 3.60% Serial Preferred Stock, our ability to declare common dividends would be limited to 75% or 50% of net income during a twelve month period if our common stock equity to total capitalization, as defined in the preferred stock designation, is less than 25% and 20% , respectively. See Note 10, Short-Term Debt and Lines of Credit , for discussion of certain financial covenants related to short-term debt obligations. As of December 31, 2017 , our restricted retained earnings totaled $2.2 billion . Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions. |
Preferred Stock
Preferred Stock | 12 Months Ended |
Dec. 31, 2017 | |
Class of Stock Disclosures [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2017 and 2016 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — $ 4.4 $100 par value, Serial Preferred Stock 2,286,500 3.60% Series 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of Cr
Short-Term Debt and Lines of Credit | 12 Months Ended |
Dec. 31, 2017 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | SHORT-TERM DEBT AND LINES OF CREDIT The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2017 2016 Commercial paper Amount outstanding at December 31 $ 210.9 $ 159.0 Average interest rate on amounts outstanding at December 31 1.81 % 0.87 % Our average amount of commercial paper borrowings based on daily outstanding balances during 2017 was $53.3 million , with a weighted-average interest rate during the period of 1.38% . We have entered into a bank back-up credit facility to maintain short-term credit liquidity which, among other terms, requires us to maintain, subject to certain exclusions, a minimum total funded debt to capitalization ratio of less than 65% . As of December 31, 2017 , we had approximately $287.9 million of available capacity under our bank back-up credit facility and $210.9 million of commercial paper outstanding that was supported by the credit facility. In April 2017, our consolidated subsidiary, Bostco, paid off a note payable to our parent, WEC Energy Group. The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 : (in millions) Maturity 2017 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 210.9 Available capacity under existing agreement $ 287.9 This facility has a renewal provision for two one -year extensions, subject to lender approval. Our bank back-up credit facility contains customary covenants, including certain limitations on our ability to sell assets. The credit facility also contains customary events of default, including payment defaults, material inaccuracy of representations and warranties, covenant defaults, bankruptcy proceedings, certain judgments, Employee Retirement Income Security Act of 1974 defaults and change of control. |
Long-Term Debt and Capital Leas
Long-Term Debt and Capital Lease Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt and Capital Lease Obligations [Abstract] | |
LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS | LONG-TERM DEBT AND CAPITAL LEASE OBLIGATIONS See our statements of capitalization for details on our long-term debt. Debentures and Notes The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2017 : (in millions) 2018 $ 250.0 2019 250.0 2020 — 2021 300.0 2022 — Thereafter 1,885.0 Total $ 2,685.0 We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. We are the obligor under a series of tax-exempt pollution control refunding bonds with an outstanding principal amount of $80.0 million . In August 2009, we terminated a letter of credit that provided credit and liquidity support for the bonds, which resulted in a mandatory tender of the bonds. We purchased the bonds at par plus accrued interest to the date of purchase. As of December 31, 2017 , the repurchased bonds were still outstanding, but are not reported in our long-term debt or included in our capitalization statements since they are held by us. Depending on market conditions and other factors, we may change the method used to determine the interest rate on this bond series and have it remarketed to third parties. A related bond series that had an outstanding principal amount of $67.0 million matured on August 1, 2016. Obligations Under Capital Leases We are the obligor under a power purchase contract with an unaffiliated third party and we lease power plants from We Power. Under capital lease accounting, we have recorded the leased plants and corresponding obligations under the capital leases on our balance sheets. We treat these agreements as operating leases for rate-making purposes. We record our minimum lease payments under the power purchase contract as purchased power expense on our income statements. We record the lease payments under our leases with We Power as rent expense in other operation and maintenance in our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. See Note 5, Regulatory Assets and Liabilities, for more information on our plant related capital leases. Power Purchase Commitment In 1997, we entered into a 25 -year power purchase contract with an unaffiliated independent power producer. The contract, for 236 MW of firm capacity from a natural gas-fired cogeneration facility, includes zero minimum energy requirements. When the contract expires in 2022 , we may, at our option and with proper notice, renew for another ten years or purchase the generating facility at fair value or allow the contract to expire. We account for this contract as a capital lease and recorded the leased facility and corresponding obligation under the capital lease at the estimated fair value of the plant's electric generating facilities. We are amortizing the leased facility on a straight-line basis over the original 25 -year term of the contract. We treat the long-term power purchase contract as an operating lease for rate-making purposes and we record our minimum lease payments as cost of sales on our income statements. We record the difference between the minimum lease payments and the sum of imputed interest and amortization costs calculated under capital lease accounting as a deferred regulatory asset on our balance sheets. Due to the timing and the amounts of the minimum lease payments, the regulatory asset increased to approximately $78.5 million during 2009, at which time the regulatory asset began to be reduced to zero over the remaining life of the contract. The total obligation under the capital lease was $27.0 million as of December 31, 2017 , and will decrease to zero over the remaining life of the contract. Port Washington Generating Station We are leasing PWGS 1 and PWGS 2, two 545 MW natural gas-fired generation units which were placed in service in July 2005 and May 2008, respectively, from We Power under PSCW approved leases. The leased units and corresponding obligations for the units have been recorded at the estimated fair value of $727.4 million . We are amortizing the leased units on a straight-line basis over the original 25 -year term of the leases. The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $129.1 million in the year 2021 for PWGS 1 and to approximately $124.4 million in the year 2023 for PWGS 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases for the units was $644.7 million as of December 31, 2017 , and will decrease to zero over the remaining lives of the contracts. Elm Road Generating Station We are leasing ER 1, ER 2, and the common facilities, which are also utilized by our OC 5 through OC 8, from We Power under PSCW approved leases. We are amortizing the leased units on a straight-line basis over the 30 -year term of the leases. ER 1 and ER 2 were placed in service in February 2010 and January 2011, respectively. The leased units and corresponding capital lease obligations have been recorded at the estimated fair value of $2,141.4 million . The lease payments are expected to be recovered through our rates, as supported by the 2001 leased generation law. Due to the timing and the amounts of the minimum lease payments, we expect the regulatory asset to increase to approximately $517.9 million in the year 2028 for ER 1 and to approximately $425.0 million in the year 2029 for ER 2, at which time the regulatory assets will be reduced to zero over the remaining lives of the contracts. The total obligation under the capital leases was $2,194.6 million as of December 31, 2017 , and will decrease to zero over the remaining lives of the contracts. We paid the following lease payments during 2017 , 2016 , and 2015 : (in millions) 2017 2016 2015 Long-term power purchase commitment $ 7.2 $ 37.6 $ 36.2 PWGS 85.0 82.4 103.8 ERGS 335.5 329.8 306.7 Total $ 427.7 $ 449.8 $ 446.7 As a result of the Tax Legislation, future PWGS and ERGS lease payments were recalculated and are expected to decrease by approximately $50.0 million annually beginning in 2018. The reduction in lease payments is not expected to impact earnings as it will be recorded as a reduction to regulatory assets until our next rate case. See Note 5, Regulatory Assets and Liabilities , and Note 12, Income Taxes , for more information on the Tax Legislation. The following table summarizes our capitalized leased facilities as of December 31: (in millions) 2017 2016 Long-term power purchase commitment Under capital lease $ 140.3 $ 140.3 Accumulated amortization (115.2 ) (109.5 ) Total long-term power purchase commitment $ 25.1 $ 30.8 PWGS Under capital lease $ 727.4 $ 704.2 Accumulated amortization (305.1 ) (274.7 ) Total PWGS $ 422.3 $ 429.5 ERGS Under capital lease $ 2,141.4 $ 2,053.5 Accumulated amortization (525.6 ) (453.6 ) Total ERGS $ 1,615.8 $ 1,599.9 Total leased facilities $ 2,063.2 $ 2,060.2 Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2017 are as follows: (in millions) Power Purchase Commitment PWGS ERGS Total 2018 $ 14.7 $ 96.3 $ 287.7 $ 398.7 2019 15.5 96.3 287.7 399.5 2020 16.4 96.3 287.7 400.4 2021 17.2 96.3 287.7 401.2 2022 7.6 96.3 287.6 391.5 Thereafter — 857.3 5,029.5 5,886.8 Total minimum lease payments 71.4 1,338.8 6,467.9 7,878.1 Less: Estimated executory costs (33.1 ) — — (33.1 ) Net minimum lease payments 38.3 1,338.8 6,467.9 7,845.0 Less: Interest (11.3 ) (694.1 ) (4,273.3 ) (4,978.7 ) Present value of minimum lease payments 27.0 644.7 2,194.6 2,866.3 Less: Due currently (3.7 ) (19.4 ) (19.4 ) (42.5 ) Long-term obligations under capital lease $ 23.3 $ 625.3 $ 2,175.2 $ 2,823.8 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | INCOME TAXES Income Tax Expense The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2017 2016 2015 Current tax expense $ 81.5 $ 4.8 $ 33.1 Deferred income taxes, net 110.6 207.3 180.0 Investment tax credit, net (0.9 ) (1.1 ) (1.1 ) Total income tax expense $ 191.2 $ 211.0 $ 212.0 Statutory Rate Reconciliation The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following: 2017 2016 2015 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 184.4 35.0 % $ 201.4 35.0 % $ 205.7 35.0 % State income taxes net of federal tax benefit 27.9 5.3 % 31.8 5.5 % 31.0 5.3 % Production tax credits (17.6 ) (3.3 )% (16.5 ) (2.8 )% (17.8 ) (3.0 )% Domestic production activities deduction (7.8 ) (1.5 )% (7.8 ) (1.4 )% (7.8 ) (1.3 )% AFUDC – Equity (1.1 ) (0.2 )% (1.5 ) (0.3 )% (2.0 ) (0.3 )% Investment tax credit restored (0.9 ) (0.2 )% (1.1 ) (0.2 )% (1.1 ) (0.2 )% Other, net 6.3 1.1 % 4.7 0.8 % 4.0 0.5 % Total income tax expense $ 191.2 36.2 % $ 211.0 36.6 % $ 212.0 36.0 % Deferred Income Tax Assets and Liabilities On December 22, 2017, the Tax Legislation was signed into law. For businesses, the Tax Legislation reduces the corporate federal tax rate from a maximum of 35% to a 21% rate effective January 1, 2018. We estimated a preliminary tax benefit related to the re-measurement of our deferred taxes in the amount of approximately $1,065 million . Accordingly, this amount has been recorded as both an increase to regulatory liabilities as well as a decrease to certain existing regulatory assets as of December 31, 2017. Our revaluation of our deferred tax assets and liabilities is subject to further clarification of the new law that cannot be estimated at this time. The impact of the Tax Legislation could materially differ from this estimate due to, among other things, changes in interpretations and assumptions we have made. On December 22, 2017, the SEC staff issued guidance in Staff Accounting Bulletin 118 (SAB 118), Income Tax Accounting Implications of the Tax Cuts and Jobs Act, which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, certain amounts related to bonus depreciation and future tax benefit utilization recorded in the financial statements as a result of the Tax Legislation are to be considered "provisional" as discussed in SAB 118 and subject to revision. We are awaiting additional guidance from industry and income tax authorities in order to finalize our accounting. The components of deferred income taxes as of December 31 were as follows: (in millions) 2017 2016 Deferred tax assets Tax gross up – regulatory items $ 240.1 $ — Future tax benefits 133.1 143.7 Deferred revenues 128.8 207.2 Employee benefits and compensation 50.2 77.6 Construction advances 15.0 20.0 Uncollectible account expense 12.5 16.1 Emission allowances 0.1 0.2 Other 54.8 70.9 Total deferred tax assets 634.6 535.7 Deferred tax liabilities Property-related 1,487.0 2,257.3 Employee benefits and compensation 117.4 179.3 Deferred transmission costs 60.1 93.1 Prepaid tax, insurance, and other 33.8 50.2 Investment in transmission affiliate — 195.1 Other 91.8 94.0 Total deferred tax liabilities 1,790.1 2,869.0 Deferred tax liability, net $ 1,155.5 $ 2,333.3 Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities. As of December 31, 2017, we had $4.0 million and $125.6 million of federal charitable contribution and tax credit carryforwards resulting in deferred tax assets of $0.8 million and $125.6 million , respectively. These federal charitable contribution carryforwards begin to expire in 2020 and tax credit carryforwards begin to expire in 2031. We expect to have future taxable income sufficient to utilize these deferred tax assets. As of December 31, 2016, we had approximately $82.8 million and $107.2 million of federal net operating loss and tax credit carryforwards resulting in deferred tax assets of $29.0 million and $107.2 million , respectively. As of December 31, 2017 we had $74.7 million and $31.9 million of state net operating loss and state charitable contribution carryforwards resulting in deferred tax assets of $4.7 million and $2.0 million , respectively. These state net operating loss carryforwards begin to expire in 2035 and state charitable contribution carryforwards begin to expire in 2017. We expect to have future taxable income sufficient to utilize these deferred tax assets. As of December 31, 2016 we had $149.9 million state net operating loss carryforwards resulting in deferred tax assets of $7.5 million . Unrecognized Tax Benefits We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2017 2016 Balance as of January 1 $ 5.1 $ 6.1 Reductions for tax positions of prior years (5.1 ) (1.0 ) Balance as of December 31 $ — $ 5.1 The amount of unrecognized tax benefits as of December 31, 2017 and 2016 excludes deferred tax assets related to uncertainty in income taxes of zero and $5.1 million , respectively. As of December 31, 2017 and 2016, there were no unrecognized tax benefits that, if recognized, would impact the effective tax rate for continuing operations. We recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense. For the years ended December 31, 2017, 2016, and 2015, we recognized $0.7 million of interest income, $0.2 million of interest expense, and $0.1 million of interest income, respectively, in our income statements. For the years ended December 31, 2017, 2016, and 2015, we recognized no penalties in our income statements. As of December 31, 2017, we had no interest accrued and no penalties accrued on our balance sheets. As of December 31, 2016, we had $0.7 million of accrued interest and no penalties accrued on our balance sheets. We do not anticipate any significant increases or decreases in the total amounts of unrecognized tax benefits within the next 12 months. Our primary tax jurisdictions include Federal and the state of Wisconsin. With a few exceptions, we are no longer subject to federal income tax examination by the IRS for years prior to 2014. As of December 31, 2017, we were subject to examination by the Wisconsin taxing authority for tax years 2013 through 2017. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.5 $ 0.1 $ — $ 0.6 Petroleum products contracts 0.9 — — 0.9 FTRs — — 2.4 2.4 Coal contracts — 0.7 — 0.7 Total derivative assets $ 1.4 $ 0.8 $ 2.4 $ 4.6 Derivative liabilities Natural gas contracts $ 2.0 $ 0.1 $ — $ 2.1 Coal contracts — 0.3 — 0.3 Total derivative liabilities $ 2.0 $ 0.4 $ — $ 2.4 December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.0 $ 0.8 $ — $ 6.8 Petroleum products contracts 0.2 — — 0.2 FTRs — — 3.1 3.1 Coal contracts — 1.9 — 1.9 Total derivative assets $ 6.2 $ 2.7 $ 3.1 $ 12.0 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 0.2 $ 0.5 $ — $ 0.7 The derivative assets and liabilities listed in the tables above include options, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 14, Derivative Instruments, for more information . The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: (in millions) 2017 2016 2015 Balance at the beginning of the period $ 3.1 $ 1.6 $ 7.0 Purchases 6.9 8.1 3.9 Settlements (7.6 ) (6.6 ) (9.3 ) Balance at the end of the period $ 2.4 $ 3.1 $ 1.6 Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2017 December 31, 2016 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 30.5 $ 30.4 $ 28.8 Long-term debt, including current portion 2,662.3 2,976.3 2,661.1 2,923.4 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities: December 31, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.6 $ 1.9 $ 6.3 $ 0.1 Petroleum products contracts 0.9 — 0.2 0.1 FTRs 2.4 — 3.1 — Coal contracts 0.6 0.1 1.5 0.5 Total other current $ 4.5 $ 2.0 $ 11.1 $ 0.7 Other long-term Natural gas contracts $ — $ 0.2 $ 0.5 $ — Coal contracts 0.1 0.2 0.4 — Total other long-term $ 0.1 $ 0.4 $ 0.9 $ — Total $ 4.6 $ 2.4 $ 12.0 $ 0.7 Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2017 December 31, 2016 December 31, 2015 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains (Losses) Natural gas contracts 26.9 Dth $ (1.0 ) 35.3 Dth $ (12.3 ) 24.0 Dth $ (12.6 ) Petroleum products contracts 16.7 gallons (1.4 ) 10.3 gallons (2.6 ) 4.0 gallons (0.2 ) FTRs 27.1 MWh 7.6 25.3 MWh 7.3 22.8 MWh 3.2 Total $ 5.2 $ (7.6 ) $ (9.6 ) At December 31, 2017 , we had posted cash collateral of $4.9 million in our margin accounts, and at December 31, 2016 , we had received cash collateral of $3.4 million in our margin accounts. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 4.6 $ 2.4 $ 12.0 $ 0.7 Gross amount not offset on the balance sheet (1.3 ) (2.0 ) (1) (3.6 ) (2) (0.2 ) Net amount $ 3.3 $ 0.4 $ 8.4 $ 0.5 (1) Includes cash collateral posted of $0.7 million at December 31, 2017 . (2) Includes cash collateral received of $3.4 million at December 31, 2016 . |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFITS | EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We participate in WEC Energy Group's defined benefit pension plans and OPEB plans that cover substantially all of our employees. We are responsible for our share of the plan assets and obligations. The benefits for a portion of these plans are funded through irrevocable trusts, as allowed for income tax purposes. Our balance sheets reflect only the liabilities associated with our past and current employees and our share of the plan assets and obligations. We also offer medical, dental, and life insurance benefits to active employees and their dependents. We expense the costs of these benefits as incurred. Generally, employees who started with us after 1995 receive a benefit based on a percentage of their annual salary plus an interest credit, while employees who started before 1996 receive a benefit based upon years of service and final average salary. New management employees hired after December 31, 2014 receive a 6% annual company contribution to their 401(k) savings plan instead of being enrolled in the defined benefit plans. We use a year-end measurement date to measure the funded status of all of the pension and OPEB plans. Due to the regulated nature of our business, we have concluded that substantially all of the unrecognized costs resulting from the recognition of the funded status of the pension and OPEB plans qualify as a regulatory asset. The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2017 2016 2017 2016 Change in benefit obligation Obligation at January 1 $ 1,177.0 $ 1,290.6 $ 298.5 $ 313.8 Service cost 12.2 10.5 7.0 7.3 Interest cost 47.0 49.7 12.1 13.2 Participant contributions — — 5.7 8.8 Plan amendments — (2.6 ) (6.8 ) — Net transfer to/from affiliates (13.4 ) (1) (121.1 ) (2) (3.3 ) (1) (17.0 ) (2) Actuarial loss (gain) 53.1 25.3 5.1 (9.7 ) Benefit payments (82.0 ) (75.4 ) (16.5 ) (19.0 ) Federal subsidy on benefits paid N/A N/A 1.7 1.1 Obligation at December 31 $ 1,193.9 $ 1,177.0 $ 303.5 $ 298.5 Change in fair value of plan assets Fair value at January 1 $ 1,102.8 $ 1,179.3 $ 205.1 $ 216.1 Actual return on plan assets 121.9 73.0 25.9 13.5 Employer contributions 5.1 5.3 3.2 2.7 Participant contributions — — 5.7 8.8 Net transfer to/from affiliates (13.7 ) (1) (79.4 ) (2) (3.3 ) (1) (17.0 ) (2) Benefit payments (82.0 ) (75.4 ) (16.5 ) (19.0 ) Fair value at December 31 $ 1,134.1 $ 1,102.8 $ 220.1 $ 205.1 Funded status at December 31 $ (59.8 ) $ (74.2 ) $ (83.4 ) $ (93.4 ) (1) Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities, primarily a result of our customer service employees being transferred to WBS. (2) Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 4, Related Parties, for more information . The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2017 2016 2017 2016 Pension and OPEB obligations $ (59.8 ) $ (74.2 ) $ (83.4 ) $ (93.4 ) The accumulated benefit obligation for all defined benefit pension plans was $1,192.4 million and $1,175.8 million as of December 31, 2017 and 2016 , respectively. The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2017 2016 Projected benefit obligation $ 1,193.9 $ 1,177.0 Accumulated benefit obligation 1,192.4 1,175.8 Fair value of plan assets 1,134.1 1,102.8 The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2017 2016 2017 2016 Net regulatory assets Net actuarial loss (gain) $ 485.4 $ 518.5 $ (1.6 ) $ 4.6 Prior service costs (credits) (1.0 ) 0.2 (8.4 ) (3.0 ) Total $ 484.4 $ 518.7 $ (10.0 ) $ 1.6 The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2018: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 37.5 $ — Prior service costs (credits) 0.9 (2.3 ) Total 2018 – estimated amortization $ 38.4 $ (2.3 ) The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2017 2016 2015 2017 2016 2015 Service cost $ 12.2 $ 10.5 $ 14.7 $ 7.0 $ 7.3 $ 9.0 Interest cost 47.0 49.7 52.9 12.1 13.2 13.4 Expected return on plan assets (76.6 ) (77.7 ) (83.6 ) (14.7 ) (14.0 ) (16.0 ) Plan settlement 4.1 — — — — — Amortization of prior service cost (credit) 1.1 1.6 2.0 (1.4 ) (1.1 ) (1.1 ) Amortization of net actuarial loss 35.4 32.4 35.6 — 1.0 1.0 Net periodic benefit cost $ 23.2 $ 16.5 $ 21.6 $ 3.0 $ 6.4 $ 6.3 The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2017 2016 2017 2016 Discount rate 3.65% 4.15% 3.65% 4.20% Rate of compensation increase 3.20% 3.20% N/A N/A Assumed medical cost trend rate (pre 65) N/A N/A 6.50% 7.00% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2024 2021 Assumed medical cost trend rate (post 65) N/A N/A 6.18% 7.00% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2028 2021 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2017 2016 2015 Discount rate 4.12% 4.45% 4.15% Expected return on plan assets 7.00% 7.00% 7.00% Rate of compensation increase 3.20% 3.50% 4.00% OPEB Costs 2017 2016 2015 Discount rate 4.10% 4.45% 4.20% Expected return on plan assets 7.25% 7.25% 7.25% Assumed medical cost trend rate (Pre 65/Post 65) 7.00% 7.50% 7.50% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2021 2021 2021 WEC Energy Group consults with its investment advisors on an annual basis to help forecast expected long-term returns on plan assets by reviewing historical returns as well as calculating expected total trust returns using the weighted-average of long-term market returns for each of the major target asset categories utilized in the fund. For 2018, the expected return on assets assumption is 7.00% for the pension plan and 7.25% for the OPEB plan. Assumed health care cost trend rates have a significant effect on the amounts reported by us for the health care plans. For the year ended December 31, 2017 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 2.9 $ (2.3 ) Effect on the health care component of the accumulated postretirement benefit obligation 29.3 (24.2 ) Plan Assets Current pension trust assets and amounts which are expected to be contributed to the trusts in the future are expected to be adequate to meet pension payment obligations to current and future retirees. The Investment Trust Policy Committee oversees investment matters related to all of our funded benefit plans. The Committee works with external actuaries and investment consultants on an on-going basis to establish and monitor investment strategies and target asset allocations. Forecasted cash flows for plan liabilities are regularly updated based on annual valuation results. Target allocations are determined utilizing projected benefit payment cash flows and risk analyses of appropriate investments. They are intended to reduce risk, provide long-term financial stability for the plans and maintain funded levels which meet long-term plan obligations while preserving sufficient liquidity for near-term benefit payments. Our pension trust target asset allocation is 35% equity investments, 55% fixed income investments, and 10% private equity and real estate investments. The OPEB trusts' target asset allocations are 60% equity investments and 40% fixed income investments. Equity securities include investments in large-cap, mid-cap, and small-cap companies primarily located in the United States. Fixed income securities include corporate bonds of companies from diversified industries, mortgage and other asset backed securities, commercial paper, and United States Treasuries. Pension and OPEB plan investments are recorded at fair value. See Note 1(m), Fair Value Measurements, for more information regarding the fair value hierarchy and the classification of fair value measurements based on the types of inputs used. The following tables summarize the fair values of our investments by asset class: December 31, 2017 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ — $ 6.6 $ — $ 6.6 $ 2.1 $ 0.5 $ — $ 2.6 Equity securities: Unites States Equity 109.4 0.1 — 109.5 29.0 — — 29.0 International Equity 114.4 — — 114.4 32.2 — — 32.2 Fixed income securities: * United States Bonds 75.9 467.8 — 543.7 24.4 46.3 — 70.7 International Bonds 9.7 32.8 — 42.5 1.7 2.9 — 4.6 Private Equity and Real Estate — 20.6 55.3 75.9 — 1.4 3.8 5.2 $ 309.4 $ 527.9 $ 55.3 $ 892.6 $ 89.4 $ 51.1 $ 3.8 $ 144.3 Investments measured at net asset value $ 241.5 $ 75.8 Total $ 309.4 $ 527.9 $ 55.3 $ 1,134.1 $ 89.4 $ 51.1 $ 3.8 $ 220.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 1.1 $ 19.2 $ — $ 20.3 $ 6.5 $ 1.3 $ — $ 7.8 Equity securities: United States equity 85.5 0.1 — 85.6 10.5 — — 10.5 International equity 17.7 — — 17.7 1.3 — — 1.3 Fixed income securities: * United States bonds — 455.3 — 455.3 — 44.0 — 44.0 International bonds — 31.6 — 31.6 — 2.8 — 2.8 Private Equity and Real Estate — — 11.0 11.0 — — 0.7 0.7 $ 104.3 $ 506.2 $ 11.0 $ 621.5 $ 18.3 $ 48.1 $ 0.7 $ 67.1 Investments measured at net asset value $ 481.3 $ 138.0 Total $ 104.3 $ 506.2 $ 11.0 $ 1,102.8 $ 18.3 $ 48.1 $ 0.7 $ 205.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2017 $ 11.0 $ 0.7 Realized and unrealized gains 1.9 0.2 Purchases 22.3 1.5 Transfers into level 3 20.1 1.4 Ending balance at December 31, 2017 $ 55.3 $ 3.8 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2016 $ 4.5 $ 0.3 Purchases 6.5 0.4 Ending balance at December 31, 2016 $ 11.0 $ 0.7 Cash Flows We expect to contribute $3.9 million to the pension plans and $0.1 million to the OPEB plans in 2018 , dependent upon various factors affecting us, including our liquidity position and the effects of the new Tax Legislation. The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB: (in millions) Pension Costs OPEB Costs 2018 $ 92.4 $ 13.5 2019 90.1 14.2 2020 89.2 14.9 2021 86.0 15.7 2022 82.3 16.2 2023-2027 368.2 85.5 Savings Plans We sponsor 401(k) savings plans which allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with plan-specified guidelines. A percentage of employee contributions are matched by us through a contribution into the employee's savings plan account, up to certain limits. Total costs incurred under all of these plans were $11.7 million in 2017, $10.4 million in 2016, and $13.0 million in 2015. |
Investment in American Transmis
Investment in American Transmission Company | 12 Months Ended |
Dec. 31, 2017 | |
Equity Method Investments and Joint Ventures [Abstract] | |
INVESTMENT IN AMERICAN TRANSMISSION COMPANY | INVESTMENT IN AMERICAN TRANSMISSION COMPANY At December 31, 2016, we owned approximately 23% of ATC, a for-profit, transmission-only company regulated by the FERC for cost of service and certain state regulatory commissions for routing and siting of transmission projects. Effective January 1, 2017, based upon input we received from the PSCW, we transferred our investment in ATC to another subsidiary of WEC Energy Group. This transaction was a non-cash equity transfer between entities under common control, and therefore, did not result in the recognition of a gain or loss. The following table provides a reconciliation of our investment in ATC during the years ended December 31: (in millions) 2017 2016 2015 Balance at January 1 $ 402.0 $ 382.2 $ 372.9 Less: Transfer of ownership interest 402.0 — — Add: Earnings from equity method investment — 55.5 47.8 Add: Capital contributions — 16.1 4.6 Less: Distributions — 51.7 * 42.9 Less: Other — 0.1 0.2 Balance at December 31 $ — $ 402.0 $ 382.2 * Of this amount, $13.4 million was recorded as a receivable from ATC at December 31, 2016. See Note 4, Related Parties, for more information on transactions with ATC. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
SEGMENT INFORMATION | SEGMENT INFORMATION We use operating income to measure segment profitability and to allocate resources to our businesses. At December 31, 2017 , we reported two segments, which are described below. Our utility segment includes our electric and natural gas utility operations. Our electric utility operations are engaged in the generation, distribution, and sale of electricity in southeastern Wisconsin (including metropolitan Milwaukee), east central Wisconsin, northern Wisconsin, and the Upper Peninsula of Michigan. Effective January 1, 2017, we transferred all of our electric distribution assets and customers located in the Upper Peninsula of Michigan to UMERC, with the exception of Tilden. See Note 4, Related Parties , and Note 21, Regulatory Environment , for additional information. Our electric utility operations also include our steam operations, which produce, distribute, and sell steam to customers in metropolitan Milwaukee, Wisconsin. Our natural gas utility operations are engaged in the purchase, distribution, and sale of natural gas to retail customers and the transportation of customer-owned natural gas in our three service areas within southeastern, east central, and northern Wisconsin. Our other segment includes Bostco, our non-utility subsidiary that was originally formed to develop and invest in real estate. In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 3, Dispositions, for more information . Prior to January 1, 2017, our other segment also included our approximate 23% ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. Effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. See Note 16, Investment in American Transmission Company, for more information . All of our operations and assets are located within the United States. The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2017 , 2016 , and 2015 . 2017 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,711.7 $ — $ 3,711.7 Other operation and maintenance 1,358.5 — 1,358.5 Depreciation and amortization 331.6 — 331.6 Operating income 625.6 — 625.6 Interest expense 117.0 0.3 117.3 Capital expenditures 596.1 — 596.1 Total assets 13,121.6 — 13,121.6 2016 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,792.8 $ — $ 3,792.8 Other operation and maintenance 1,430.2 — 1,430.2 Depreciation and amortization 325.4 — 325.4 Operating income 629.5 — 629.5 Equity in earnings of transmission affiliate — 55.5 55.5 Interest expense 116.6 1.0 117.6 Capital expenditures 468.9 0.6 469.5 Total assets 12,945.1 426.4 13,371.5 2015 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,854.1 $ — $ 3,854.1 Other operation and maintenance 1,384.9 — 1,384.9 Depreciation and amortization 304.0 — 304.0 Operating income 648.9 — 648.9 Equity in earnings of transmission affiliate — 47.8 47.8 Interest expense 117.7 1.3 119.0 Capital expenditures 518.8 0.4 519.2 Total assets 12,727.6 412.0 13,139.6 |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2017 | |
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Determination Methodology and Factors [Abstract] | |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities. We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance. American Transmission Company As of December 31, 2016, we owned approximately 23% of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. However, effective January 1, 2017, we transferred our investment in ATC to another subsidiary of WEC Energy Group. ATC was a variable interest entity, but consolidation was not required since we were not ATC's primary beneficiary. We did not have the power to direct the activities that most significantly impacted ATC's economic performance. At December 31, 2016, we accounted for ATC as an equity method investment. See Note 16, Investment in American Transmission Company, for more information . Purchased Power Agreement We have 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 four years . We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is no residual guarantee associated with the purchased power agreement. We have approximately $71.4 million of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the years ended December 31, 2017 , 2016 , and 2015 were $18.0 million , $54.2 million , and $53.6 million , respectively. Our maximum exposure to loss is limited to the capacity payments under the contract. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, operating leases, environmental matters, and enforcement and litigation matters. Unconditional Purchase Obligations We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2017 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2018 2019 2020 2021 2022 Later Years Electric utility: Nuclear 2033 $ 9,184.5 $ 420.1 $ 445.4 $ 475.1 $ 501.1 $ 531.2 $ 6,811.6 Coal supply and transportation 2020 215.0 132.2 53.9 28.9 — — — Purchased power 2031 93.1 29.1 16.6 13.7 10.9 9.0 13.8 Natural gas utility supply and transportation 2048 462.3 65.6 54.8 43.6 30.3 22.6 245.4 Total $ 9,954.9 $ 647.0 $ 570.7 $ 561.3 $ 542.3 $ 562.8 $ 7,070.8 Operating Leases We lease property, plant, and equipment under various terms. The operating leases generally require us to pay property taxes, insurance premiums, and maintenance costs associated with the leased property. Many of our leases contain one of the following options upon the end of the lease term: (a) purchase the property at the current fair market value, or (b) exercise a renewal option, as set forth in the lease agreement. Rental expense attributable to operating leases was $4.0 million , $5.0 million , and $6.7 million in 2017 , 2016 , and 2015 , respectively. Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2018 $ 3.5 2019 3.4 2020 1.9 2021 1.4 2022 1.5 Later years 23.0 Total $ 34.7 Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, mercury, and GHGs; water intake and discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. We have continued to pursue a proactive strategy to manage our environmental compliance obligations, including: • the development of additional sources of renewable electric energy supply; • the addition of improvements for water quality matters such as treatment technologies to meet regulatory discharge limits and improvements to our cooling water intake systems; • the addition of emission control equipment to existing facilities to comply with ambient air quality standards and federal clean air rules; • the protection of wetlands and waterways, threatened and endangered species, and cultural resources associated with utility construction projects; • the retirement of old coal-fired power plants and conversion to modern, efficient, natural gas generation, super-critical pulverized coal generation, and/or replacement with renewable generation; • the beneficial use of ash and other products from coal-fired and biomass generating units; and • the remediation of former manufactured gas plant sites. Air Quality 8-Hour Ozone National Ambient Air Quality Standards After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. In December 2017, the EPA designated all the counties along Wisconsin's Lake Michigan shoreline, except Brown, Kewaunee, Marinette, and Oconto Counties, as either partial or full nonattainment. Waukesha and Washington counties were also included due to the counties being in the Milwaukee combined statistical area. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. Although we will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final, which is expected from the EPA in April 2018, and until the state prepares a draft attainment plan, we believe we are well positioned to meet the requirements associated with the ozone standard and do not expect to incur significant costs to comply. Climate Change In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the CPP, a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard one case in September 2016, and the other case is still pending. In April 2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking. The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of 41% and 39% , respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about two-thirds of the 2030 required reduction. In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In October 2017, the EPA issued a proposed rulemaking to repeal the CPP. In December 2017, the EPA issued an advanced notice of proposed rulemaking to solicit input on whether it is appropriate to replace the CPP. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan to implement the CPP. Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO 2 emissions by approximately 40% below 2005 levels by 2030. We have implemented and continue to evaluate numerous options in order to meet our CO 2 reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation. As a result of WEC Energy Group's generation reshaping plan, we expect to retire approximately 1,547 MW of coal generation by 2020, including Pleasant Prairie power plant and PIPP. See Note 6, Property, Plant, and Equipment, for more information . In addition, we are evaluating our goal, and possible subsequent actions, with respect to national and international efforts to reduce future GHG emissions in order to limit future global temperature increases to less than two degrees Celsius. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2016 , we reported aggregated CO 2 equivalent emissions of approximately 23.9 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 23.5 million metric tonnes to the EPA for 2017 . The level of CO 2 and other GHG emissions varies from year to year and is dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2016 , we reported aggregated CO 2 equivalent emissions of approximately 3.7 million metric tonnes to the EPA. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 3.8 million metric tonnes to the EPA for 2017 . Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities satisfy the IM BTA requirements. BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. Due to our plans to retire PIPP and Pleasant Prairie power plant, we do not believe that BTA determinations for EM will be necessary for these facilities. Although we currently believe that existing technologies at PWGS and OC 5 through OC 8 satisfy the EM BTA requirements, BTA determinations to address EM reduction requirements will not be made until discharge permits are renewed for these facilities. Until that time, we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at these other facilities. During 2018, we will continue to evaluate options to address the EM BTA requirements at these plants. We have also provided information to the WDNR and the MDEQ about planned unit retirements. Based on discussions with the MDEQ, if we submit a signed certification stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2023), the EM BTA requirements will be waived. We expect to submit the letter identifying the last operating date for PIPP to the MDEQ during 2018, ahead of when the agency begins processing our pending application for the National Pollutant Discharge Elimination System permit reissuance. We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation. Steam Electric Effluent Limitation Guidelines The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. Various petitions challenging the rule were consolidated and are pending in the United States Fifth Circuit Court of Appeals. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In September 2017, the EPA issued a final rule to postpone the earliest compliance dates for the bottom ash transport water and wet flue gas desulfurization wastewater requirements . This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023. After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every five years . Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the OCPP and ERGS. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7 and OC 8. We are beginning preliminary engineering for compliance with the rule and estimate approximately $50 million will be required to design and install these advanced treatment and bottom ash transport systems. This estimate reflects the planned retirements of certain of our generation plants as a result of WEC Energy Group's generation reshaping plan discussed in Climate Change above. Land Quality Manufactured Gas Plant Remediation We have identified sites at which we or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. We are responsible for the environmental remediation of these sites. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2017 2016 Regulatory assets $ 30.4 $ 29.9 Reserves for future remediation 18.5 19.0 Renewables, Efficiency, and Conservation Wisconsin Legislation In 2005, Wisconsin enacted Act 141, which established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. We have achieved a renewable energy percentage of 8.27% and met our compliance requirements by constructing various wind parks, a biomass facility, and by also relying on renewable energy purchases. We continue to review our renewable energy portfolio and acquire cost-effective renewables as needed to meet our requirements on an ongoing basis. The PSCW administers the renewable program related to Act 141, and we fund the program, along with other utilities, based on 1.2% of our annual operating revenues. Michigan Legislation In 2008, Michigan enacted Act 295, which required 10% of the state's electric energy to come from renewables by 2015 and energy optimization (efficiency) targets up to 1% annually by 2015. In December 2016, Michigan revised this legislation with Act 342, which requires additional renewable energy requirements beyond 2015. The new legislation retains the 10% renewable energy portfolio requirement for years 2017 through 2018, increases the requirement to 12.5% for years 2019 through 2020, and increases the requirement to 15.0% for 2021. We were in compliance with these requirements as of December 31, 2017 . The revised legislation continues to allow recovery of costs incurred to meet the standards and provides for ongoing review and revision to assure the measures taken are cost-effective. Enforcement and Litigation Matters We are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW INFORMATION | SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2017 2016 2015 Cash (paid) for interest, net of amount capitalized $ (115.1 ) $ (116.2 ) $ (116.2 ) Cash (paid) received for income taxes, net (71.7 ) 100.2 (58.5 ) Significant non-cash transactions: Accounts payable related to construction costs 13.2 9.1 11.7 Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) 415.4 — — Transfer of net assets to UMERC (1) 61.1 — — Equity settlement of a short-term note receivable between Bostco and our parent company 4.8 — — (1) See Note 4, Related Parties, for more information on these transactions. (2) The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. |
Regulatory Environment
Regulatory Environment | 12 Months Ended |
Dec. 31, 2017 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT Tax Cuts and Jobs Act of 2017 As ordered by the PSCW, we deferred for return to ratepayers, through future refunds, bill credits, or reductions in other regulatory assets, the estimated tax benefit of $1,065 million related to the Tax Legislation that was signed into law in December 2017. This tax benefit resulted from the revaluation of deferred taxes. See Note 12, Income Taxes , for more information. 2018 and 2019 Rates During April 2017, we, along with WG and WPS, filed an application with the PSCW for approval of a settlement agreement we made with several of our commercial and industrial customers regarding 2018 and 2019 base rates. In September 2017, the PSCW issued an order that approved the settlement agreement, which freezes base rates through 2019 for our electric and natural gas customers. Based on the PSCW order, our authorized ROE remains at 10.2% , and our current capital cost structure will remain unchanged through 2019. Various intervenors had filed requests for rehearing, all of which have been denied. In addition to freezing base rates, the settlement agreement extends and expands the electric real-time market pricing program options for large commercial and industrial customers and mitigates the continued growth of certain escrowed costs during the base rate freeze period by accelerating the recognition of certain tax benefits. Pursuant to the settlement agreement, we also agreed to keep our earnings sharing mechanism in place through 2019. Under this earnings sharing mechanism, if we earn above our authorized ROE, 50% of the first 50 basis points of additional utility earnings must be shared with customers. All utility earnings above the first 50 basis points must also be shared with customers. Natural Gas Storage Facilities in Michigan In January 2017, WEC Energy Group signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide a portion of the current storage needs for our natural gas utility operations. As a result of this agreement, we, along with WG and WPS, filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, we requested that the PSCW review and confirm the reasonableness and prudency of our potential long-term storage service agreement and interstate natural gas transportation contracts related to the storage facilities. We also requested approval to amend WEC Energy Group's AIA to ensure WBS and WEC Energy Group's other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and WEC Energy Group acquired Bluewater on June 30, 2017. In September 2017, we entered into the long-term service agreement for the natural gas storage, which was then approved by the PSCW in November 2017. Formation of Upper Michigan Energy Resources Corporation In December 2016, both the MPSC and the PSCW approved the operation of UMERC, a subsidiary of WEC Energy Group, as a stand - alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WPS and us, located in the Upper Peninsula of Michigan. In August 2016, WEC Energy Group entered into an agreement with Tilden, under which Tilden will purchase electric power from UMERC for its iron ore mine for 20 years , contingent upon UMERC's construction of approximately 180 MW of natural gas-fired generation in the Upper Peninsula of Michigan. In October 2017, the MPSC approved both the agreement with Tilden and UMERC's application for a certificate of necessity to begin construction of the proposed generation. The new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain our customer until this new generation begins commercial operation. 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 our retail electric customers of approximately $2.7 million ( 0.1% ) in 2015. This amount reflected the receipt of SSR payments from MISO that were higher than we anticipated when we filed our 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 Treasury Grant that we received in connection with our 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 our 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 our natural gas customers in 2015, with no rate adjustment in 2016. • A rate increase of approximately $0.5 million ( 2.0% ) for our 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 our Milwaukee County steam utility customers in 2015, with no rate adjustment in 2016. As a result of the sale of the MCPP, we no longer have any Milwaukee County steam utility customers. See Note 3, Dispositions, for more information about the sale of the MCPP. Our authorized ROE was set at 10.2% , and our common equity component remained at an average of 51% . The PSCW order reaffirmed the deferral of our transmission costs, and it verified that 2015 and 2016 fuel costs should continue to be monitored using a 2% tolerance window. 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 record SSR revenues 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 is expected to be recovered from customers with interest, in a future rate case. Earnings Sharing Agreement In May 2015, the PSCW approved the acquisition of Integrys subject to the condition of an earnings sharing mechanism for us. See Note 2, Acquisitions, for more information on this earnings sharing mechanism. |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (Unaudited) (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2017 Operating revenues $ 972.0 $ 855.4 $ 943.8 $ 940.5 $ 3,711.7 Operating income 185.1 142.8 163.4 134.3 625.6 Net income attributed to common shareholder 101.8 75.3 89.4 69.1 335.6 2016 Operating revenues $ 975.5 $ 877.2 $ 1,023.8 $ 916.3 $ 3,792.8 Operating income 181.5 146.9 196.4 104.7 629.5 Net income attributed to common shareholder 107.3 82.6 115.2 59.2 364.3 Due to various factors, the quarterly results of operations are not necessarily comparable. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2017 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Revenue Recognition In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers. We have completed the review of our contracts with customers and are finalizing the related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We have evaluated the nature of our operating revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition. Most of our revenues are from regulated tariff sales, which are in the scope of the new standard, excluding the revenue component related to alternative revenue programs. The revenues from these contracts are recorded at the amount of the electricity or natural gas delivered to the customer during the period. We adopted this standard for interim and annual periods beginning January 1, 2018, as required, and used the modified retrospective method of adoption. The most significant impact to the financial statements is expected to be in the form of additional disclosures. However, we do not expect to have a cumulative-effect adjustment to record on the balance sheet as of the beginning of 2018; and therefore, do not expect to include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance. We will include disaggregated revenue disclosures by segment, major products (electric and natural gas), and customer class in the combined notes to the financial statements, starting in the first quarter of 2018. Recognition and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. As required, we adopted this ASU for interim and annual periods beginning January 1, 2018. We do not believe the adoption of this guidance will have a significant impact on our financial statements. Leases In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements. Financial Instruments Credit Losses In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements. Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. As required, we adopted this ASU for interim and annual periods beginning January 1, 2018 and used a retrospective transition method. We do not believe the adoption of this guidance will have a significant impact on our financial statements. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. As required, we adopted this ASU for interim and annual periods beginning January 1, 2018. The amendments will be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. As a result of the application of accounting principles for rate regulated entities, a similar amount of net benefit cost (including non-service components) will be recognized in our financial statements consistent with the current rate-making treatment. The impacts of adoption will be limited to changes in classification of non-service costs in the income statements. |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts | 12 Months Ended |
Dec. 31, 2017 | |
Valuation and Qualifying Accounts [Abstract] | |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | SCHEDULE II WISCONSIN ELECTRIC POWER COMPANY VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of Period Transfer of Net Assets to UMERC (1) Expense (2) Deferral Net Write-offs (3) Balance at End of Period December 31, 2017 $ 40.9 $ (0.3 ) $ 31.2 $ (6.4 ) $ (25.9 ) $ 39.5 December 31, 2016 43.0 — 31.1 (5.7 ) (27.5 ) 40.9 December 31, 2015 46.8 — 30.6 0.3 (34.7 ) 43.0 (1) See Note 4, Related Parties, for more information . (2) Net of recoveries (3) Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
Summary of Significant Accoun32
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Nature of operations | On June 29, 2015, our parent company, Wisconsin Energy Corporation, acquired Integrys and changed its name to WEC Energy Group, Inc. See Note 2, Acquisitions, for more information on this acquisition. We are an electric, natural gas, and steam utility company that serves electric customers in Wisconsin and an iron ore mine owned by Tilden in the Upper Peninsula of Michigan, natural gas customers in Wisconsin, and steam customers in metropolitan Milwaukee, Wisconsin. |
Consolidation | As used in these notes, the term "financial statements" refers to the consolidated financial statements. This includes the income statements, balance sheets, statements of cash flows, statements of equity, and statements of capitalization, unless otherwise noted. |
Segment reporting | Through December 31, 2017 , we had one wholly owned subsidiary, Bostco. At December 31, 2016, Bostco had total assets of $24.4 million . In March 2017, we sold substantially all of the remaining assets of Bostco. See Note 3, Dispositions, for more information . The financial statements include our accounts and the accounts of our wholly owned subsidiary. |
Investments | The cost method of accounting is used for investments when we do not have significant influence over the operating and financial policies of the investee. Investments in companies not controlled by us, but over which we have significant influence regarding the operating and financial policies of the investee, are accounted for using the equity method. |
Use of estimates | We prepare our financial statements in conformity with GAAP. We make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates. |
Cash and cash equivalents | Cash and cash equivalents include marketable debt securities with an original maturity of three months or less. |
Revenues and customer receivables | We recognize revenues related to the sale of energy on the accrual basis and include estimated amounts for services provided but not yet billed to customers. We present revenues net of pass-through taxes on the income statements. Below is a summary of the significant mechanisms we had in place that allowed us to recover or refund changes in prudently incurred costs from rate case-approved amounts: • Fuel and purchased power costs were recovered from customers on a one-for-one basis by our Wisconsin wholesale electric operations and our Michigan retail electric operations. • Our retail electric rates in Wisconsin are established by the PSCW and include base amounts for fuel and purchased power costs. The electric fuel rules set by the PSCW allow us to defer, for subsequent rate recovery or refund, under- or over-collections of actual fuel and purchased power costs that exceed a 2% price variance from the costs included in the rates charged to customers. We monitor the deferral of under-collected costs to ensure that it does not cause us to earn a greater ROE than authorized by the PSCW. • We received payments from MISO under an SSR agreement for our PIPP units through February 1, 2015. We recorded revenue for these payments to recover costs for operating and maintaining these units. See Note 21, Regulatory Environment , for more information. • Our natural gas utility rates included a one-for-one recovery mechanism for natural gas commodity costs. We defer any difference between actual natural gas costs incurred and costs recovered through rates as a current asset or liability. The deferred balance is returned to or recovered from customers at intervals throughout the year. • Our residential rates included a mechanism for cost recovery or refund of uncollectible expense based on the difference between actual uncollectible write-offs and the amounts recovered in rates. Revenues are also impacted by other accounting policies related to our participation in the MISO Energy Markets. We sell and purchase power in the MISO Energy Markets, which operate under both day-ahead and real-time markets. We record energy transactions in the MISO Energy Markets on a net basis for each hour. If we were a net seller in a particular hour, the net amount was reported as operating revenues. If we were a net purchaser in a particular hour, the net amount was recorded as cost of sales on our income statements. We provide regulated electric, natural gas, and steam service to customers in Wisconsin and to Tilden located in the Upper Peninsula of Michigan, and provided electric service to other customers in the Upper Peninsula of Michigan through December 31, 2016. See Note 4, Related Parties , and Note 21, Regulatory Environment , for information regarding the transfer of our customers located in the Upper Peninsula of Michigan to UMERC as of January 1, 2017. The geographic concentration of our customers did not contribute significantly to our overall exposure to credit risk. We periodically review customers' credit ratings, financial statements, and historical payment performance and require them to provide collateral or other security as needed. Our credit risk exposure is mitigated by our recovery mechanism for uncollectible expense discussed above. As a result, we did not have any significant concentrations of credit risk at December 31, 2017 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2017 . |
Materials, supplies and inventories | Substantially all materials and supplies, fossil fuel, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
Regulatory assets and liabilities | The economic effects of regulation can result in regulated companies recording costs and revenues that have been or are expected to be allowed in the rate-making process in a period different from the period in which the costs or revenues would be recognized by a nonregulated company. When this occurs, regulatory assets and regulatory liabilities are recorded on the balance sheet. Regulatory assets represent probable future revenues associated with certain costs or liabilities that have been deferred and are expected to be recovered through rates charged to customers. Regulatory liabilities represent amounts that are expected to be refunded to customers in future rates or amounts that are collected in rates for future costs. Recovery or refund of regulatory assets and liabilities is based on specific periods determined by the regulators or occurs over the normal operating period of the assets and liabilities to which they relate. If at any reporting date a previously recorded regulatory asset is no longer probable of recovery, the regulatory asset is reduced to the amount considered probable of recovery with the reduction charged to expense in the reporting period the determination is made. |
Property, plant, and equipment | We record property, plant, and equipment at cost. Cost includes material, labor, overhead, and both debt and equity components of AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to other operation and maintenance expense. The cost of depreciable utility property less salvage value is charged to accumulated depreciation when property is retired. We record straight-line depreciation expense over the estimated useful life of utility property using depreciation rates approved by the PSCW and MPSC that include estimates for salvage value and removal costs. Depreciation as a percent of average depreciable utility plant was 2.95% , 3.00% , and 3.01% in 2017 , 2016 , and 2015 , respectively. We capitalize certain costs related to software developed or obtained for internal use and record these costs to amortization expense over the estimated useful life of the related software, which ranges from 5 to 15 years. If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. For assets other than our regulated assets and leased equipment, we accrue depreciation expense at straight-line rates over the estimated useful lives of the assets, or over the non-cancellable lease term for leased equipment. Third parties reimburse us for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs are recorded as a reduction to property, plant, and equipment. |
AFUDC | AFUDC is included in utility plant accounts and represents the cost of borrowed funds (AFUDC – Debt) used during plant construction, and a return on shareholders' capital (AFUDC – Equity) used for construction purposes. AFUDC – Debt is recorded as a reduction of interest expense, and AFUDC – Equity is recorded in other income, net. |
Asset retirement obligations | We recognize, at fair value, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development, and normal operation of the assets. An ARO liability is recorded, when incurred, for these obligations as long as the fair value can be reasonably estimated, even if the timing or method of settling the obligation is unknown. The associated retirement costs are capitalized as part of the related long-lived asset and are depreciated over the useful life of the asset. The ARO liabilities are accreted each period using the credit-adjusted risk-free interest rates associated with the expected settlement dates of the AROs. These rates are determined when the obligations are incurred. Subsequent changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease to the carrying amount of the liability and the associated retirement costs. We recognize regulatory assets or liabilities for the timing differences between when we recover an ARO in rates and when we recognize the associated retirement costs. |
Asset impairment | We periodically assess the recoverability of certain long-lived assets when factors indicate the carrying value of such assets may be impaired or such assets are planned to be sold. These assessments require significant assumptions and judgments by management. The long-lived assets assessed for impairment generally include certain assets within regulated operations that may not be fully recovered from our customers as a result of regulatory decisions that will be made in the future. When it becomes probable that a generating unit will be retired before the end of its useful life, we assess whether the generating unit meets the criteria for abandonment accounting. Generating units that are considered probable of abandonment are expected to cease operations in the near term, significantly before the end of their original estimated useful lives. If a generating unit meets applicable criteria to be considered probable of abandonment, we assess the likelihood of recovery of the remaining carrying value of that generating unit at the end of each reporting period. If it becomes probable that regulators will not allow full recovery as well as a return on the remaining net book value of the abandoned generating unit, an impairment charge may be required. An impairment charge would be recorded if the remaining carrying value of the abandoned generating unit is greater than the present value of the amount expected to be recovered from ratepayers. |
Stock-based compensation | Our employees participate in the WEC Energy Group stock-based compensation plans. In accordance with the WEC Energy Group shareholder approved Omnibus Stock Incentive Plan, WEC Energy Group provides long-term incentives through its equity interests to its non-employee directors, selected officers, and other key employees. The plan provides for the granting of stock options, restricted stock, performance shares, and other stock-based awards. Awards may be paid in WEC Energy Group common stock, cash, or a combination thereof. The number of shares of WEC Energy Group common stock authorized for issuance under the plan is 34.3 million . Stock-based compensation expense is allocated to us based on the outstanding awards held by our employees and our allocation of labor costs. Awards classified as equity awards are measured based on their grant-date fair value. Awards classified as liability awards are recorded at fair value each reporting period. In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and excess tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded an $11.9 million cumulative-effect adjustment to increase retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. As we did not record any excess tax benefits in 2017, adoption of ASU 2016-09 had no impact on our financial statements other than the cumulative-effect adjustment discussed above. Stock Options Our employees are granted WEC Energy Group non-qualified stock options that generally vest on a cliff-basis after a three -year period. The exercise price of a stock option under the plan cannot be less than 100% of the fair market value of WEC Energy Group common stock on the grant date. Historically, all stock options have been granted with an exercise price equal to the fair market value of WEC Energy Group common stock on the date of the grant. Options may not be exercised within six months of the grant date except in the event of a change in control. Options expire no later than 10 years from the date of grant. WEC Energy Group stock options are classified as equity awards. The fair value of each stock option was calculated using a binomial option-pricing model. The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2017 2016 2015 Stock options granted * 80,770 92,880 495,550 Estimated weighted-average fair value per stock option $ 7.12 $ 4.92 $ 5.29 Assumptions used to value the options: Risk-free interest rate 0.7% – 2.5% 0.5% – 2.2% 0.1% – 2.1% Dividend yield 3.5 % 4.0 % 3.7 % Expected volatility 19.0 % 18.0 % 18.0 % Expected life (years) 6.2 5.8 5.8 * Effective January 1, 2016, certain employees were transferred into WBS. See Note 4, Related Parties, for more information . The risk-free interest rate was based on the United States Treasury interest rate with a term consistent with the expected life of the stock options. The dividend yield was based on WEC Energy Group's dividend rate at the time of the grant and historical stock prices. Expected volatility and expected life assumptions were based on WEC Energy Group's historical experience. Restricted Shares WEC Energy Group restricted shares granted to our employees have a three -year vesting period with one-third of the award vesting on each anniversary of the grant date. The restricted shares are classified as equity awards. Performance Units Officers and other key employees are granted performance units under the WEC Energy Group Performance Unit Plan. Under the plan, the ultimate number of units that will be awarded is dependent on WEC Energy Group's total shareholder return (stock price appreciation plus dividends) as compared to the total shareholder return of a peer group of companies over a three -year period, and beginning in 2017, other performance metrics as determined by the Compensation Committee. Participants may earn between 0% and 175% of the base performance unit award, as adjusted pursuant to the terms of the plan. Performance units granted on or after January 1, 2016 also accrue forfeitable dividend equivalents in the form of additional performance units. All grants of performance units are settled in cash and are accounted for as liability awards accordingly. The fair value of the performance units reflects our estimate of the final expected value of the awards, which is based on WEC Energy Group's stock price and performance achievement under the terms of the award. Stock-based compensation costs are recorded over the three -year performance period. |
Stock-based compensation - forfeitures | As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating potential future forfeitures and recording them over the vesting period. |
Income taxes | We follow the liability method in accounting for income taxes. Accounting guidance for income taxes requires the recording of deferred assets and liabilities to recognize the expected future tax consequences of events that have been reflected in our financial statements or tax returns and the adjustment of deferred tax balances to reflect tax rate changes. We are required to assess the likelihood that our deferred tax assets would expire before being realized. If we conclude that certain deferred tax assets are likely to expire before being realized, a valuation allowance would be established against those assets. GAAP requires that, if we conclude in a future period that it is more likely than not that some or all of the deferred tax assets would be realized before expiration, we reverse the related valuation allowance in that period. Any change to the allowance, as a result of a change in judgment about the realization of deferred tax assets, is reported in income tax expense. Investment tax credits associated with regulated operations are deferred and amortized over the life of the assets. We are included in WEC Energy Group's consolidated Federal and state income tax returns. In accordance with our tax allocation agreement with WEC Energy Group, we are allocated income tax payments and refunds based upon our separate tax computation. See Note 12, Income Taxes, for more information . We recognize interest and penalties accrued related to unrecognized tax benefits in income tax expense in our income statements. |
Fair value measurements | Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our derivative assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs. We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term debt, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same or similar issues. The fair values of long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy. |
Derivative instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Our regulated hedging programs are approved by the PSCW. We record derivative instruments on our balance sheets as assets or liabilities measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy related physical and financial contracts in our regulated operations that qualify as derivatives, the PSCW allows the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. Realized gains and losses on derivative instruments are primarily recorded in cost of sales on our income statements. Cash flows from derivative activities are presented in the same category as the item being hedged within operating activities on our statements of cash flows. Derivative accounting rules provide the option to present certain asset and liability derivative positions net on the balance sheets and to net the related cash collateral against these net derivative positions. We elected not to net these items. On our balance sheets, cash collateral provided to others is reflected in other current assets, and cash collateral received is reflected in other current liabilities. |
Employee benefits | The costs of pension and OPEB plans are expensed over the periods during which employees render service. These costs are distributed among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for our net periodic benefit cost calculated under GAAP. |
Customer deposits and credit balances | When utility customers apply for new service, they may be required to provide a deposit for the service. Customer deposits are recorded within other current liabilities on our balance sheets. Utility customers can elect to be on a budget plan. Under this type of plan, a monthly installment amount is calculated based on estimated annual usage. During the year, the monthly installment amount is reviewed by comparing it to actual usage. If necessary, an adjustment is made to the monthly amount. Annually, the budget plan is reconciled to actual annual usage. Payments in excess of actual customer usage are recorded within other current liabilities on our balance sheets. |
Environmental remediation costs | We are subject to federal and state environmental laws and regulations that in the future may require us to pay for environmental remediation at sites where we have been, or may be, identified as a potentially responsible party. Loss contingencies may exist for the remediation of hazardous substances at various potential sites, including coal combustion product landfill sites and manufactured gas plant sites. See Note 7, Asset Retirement Obligations, for more information regarding coal combustion product landfill sites and Note 19, Commitments and Contingencies , for more information regarding manufactured gas plant sites. We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potentially responsible parties or the government. When possible, we estimate costs using site-specific information but also consider historical experience for costs incurred at similar sites. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, potentially affecting the cost of remediation. We have received approval to defer certain environmental remediation costs, as well as estimated future costs, through a regulatory asset. The recovery of deferred costs is subject to the PSCW's approval. We review our estimated costs of remediation annually for our manufactured gas plant sites and coal combustion product landfill sites. We adjust the liabilities and related regulatory assets, as appropriate, to reflect the new cost estimates. Any material changes in cost estimates are adjusted throughout the year. |
Summary of Significant Accoun33
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of inventory | Our inventory as of December 31 consisted of: (in millions) 2017 2016 Materials and supplies $ 140.7 $ 148.1 Fossil fuel 74.8 91.1 Natural gas in storage 35.2 31.8 Total $ 250.7 $ 271.0 |
Allowance for funds used during construction | We recorded the following AFUDC for the years ended December 31: (in millions) 2017 2016 2015 AFUDC – Debt $ 1.2 $ 1.7 $ 2.2 AFUDC – Equity $ 3.1 $ 4.2 $ 5.7 |
Schedule of assumptions used to estimate the fair value of stock options granted | The following table shows the estimated weighted-average fair value per stock option granted to our employees along with the weighted-average assumptions used in the valuation models: 2017 2016 2015 Stock options granted * 80,770 92,880 495,550 Estimated weighted-average fair value per stock option $ 7.12 $ 4.92 $ 5.29 Assumptions used to value the options: Risk-free interest rate 0.7% – 2.5% 0.5% – 2.2% 0.1% – 2.1% Dividend yield 3.5 % 4.0 % 3.7 % Expected volatility 19.0 % 18.0 % 18.0 % Expected life (years) 6.2 5.8 5.8 * Effective January 1, 2016, certain employees were transferred into WBS. See Note 4, Related Parties, for more information . |
Related Parties (Tables)
Related Parties (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Schedule of related party transactions balance sheet information | Our balance sheets included the following receivables and payables related to transactions entered into with ATC: (in millions) 2017 2016 Accounts receivable Services provided to ATC $ 0.8 $ 1.1 Accounts payable Services received from ATC 22.2 20.0 |
Schedule of activity associated with related party transactions | The following table shows activity associated with our related party transactions for the years ended December 31: (in millions) 2017 2016 2015 Lease agreements Lease payments to We Power (1) $ 420.5 $ 412.2 $ 410.5 CWIP billed to We Power 57.3 37.9 58.8 Transactions with WBS (2) Billings to WBS (3) 255.7 213.8 11.1 Billings from WBS (4) 215.4 310.6 1.3 Transactions with WPS (2) Natural gas purchases from WPS 1.6 1.9 0.4 Billings to WPS 28.2 9.0 13.4 Billings from WPS 4.5 4.2 4.9 Transactions with WG Natural gas purchases from WG 5.3 5.3 5.3 Billings to WG 64.0 60.6 79.4 Billings from WG 23.1 21.5 23.5 Transactions with UMERC (5) Electric sales to UMERC 30.8 — — Billings to UMERC (2) 125.5 — — Transactions with Bluewater (6) Storage service fees 2.7 — — Transactions with ATC Charges to ATC for services and construction 10.9 10.0 9.7 Charges from ATC for network transmission services 241.4 247.8 238.5 Refund from ATC per FERC ROE order (19.4 ) — — (1) We make lease payments to We Power, another subsidiary of WEC Energy Group, for PWGS Units 1 and 2 and ERGS Units 1 and 2. (2) Includes amounts billed for services, pass through costs, and other items in accordance with the approved AIAs. (3) Includes $1.2 million , for the transfer of certain benefit-related liabilities from WBS for the year ended December 31, 2017 . For the year ended December 31, 2016 , includes $13.1 million for the transfer of certain software assets to WBS. There were no transfers of assets to WBS during the year ended December 31, 2017 , and there were no transfers of liabilities from WBS for the year ended December 31, 2016 . (4) For the year ended December 31, 2017 and 2016 , includes $1.5 million and $116.0 million , respectively, for the transfer of certain benefit-related liabilities to WBS. (5) UMERC became operational effective January 1, 2017. See below for more information. (6) The acquisition of Bluewater was completed on June 30, 2017. See below for more information. |
Regulatory Assets and Liabili35
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets | The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2017 2016 See Note Regulatory assets (1) (2) Plant related – capital leases $ 801.3 $ 724.8 11 Unrecognized pension and OPEB costs (3) 484.4 520.3 15 SSR 298.9 188.1 21 Electric transmission costs 220.7 231.9 21 We Power generation (4) 71.3 54.1 AROs 41.4 39.7 7 Environmental remediation costs (5) 30.4 29.9 19 Energy efficiency programs (6) 28.2 38.5 Income tax related items — 200.8 12 Other, net 8.3 8.5 Total regulatory assets $ 1,984.9 $ 2,036.6 (1) Based on prior and current rate treatment, we believe it is probable that we will continue to recover from customers the regulatory assets in the table. (2) As of December 31, 2017 , we had $11.4 million of regulatory assets not earning a return and $254.0 million of regulatory assets earning a return based on short-term interest rates. The regulatory assets not earning a return relate to certain environmental remediation costs, the recovery of which depends on the timing of the actual expenditures. The other regulatory assets in the table either earn a return or the cash has not yet been expended, in which case the regulatory assets are offset by liabilities. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. We are authorized recovery of this regulatory asset over the average remaining service life of each plan. (4) Represents amounts recoverable from customers related to our costs of the generating units leased from We Power, including subsequent capital additions. See Note 11, Long-Term Debt and Capital Lease Obligations, for more information on the Tax Legislation impacts on the lease payments. (5) As of December 31, 2017 , we had not yet made cash expenditures for $18.5 million of these environmental remediation costs. (6) Represents amounts recoverable from customers related to programs designed to meet energy efficiency standards. |
Schedule of regulatory liabilities | The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2017 2016 See Note Regulatory liabilities 2017 Tax Legislation impact and income tax related $ 849.1 $ — 12 Removal costs (1) 730.0 722.9 Mines deferral (2) 95.1 70.2 Other, net 46.9 71.0 Total regulatory liabilities $ 1,721.1 $ 864.1 Balance Sheet Presentation Current liabilities $ 13.1 $ 10.2 Regulatory liabilities 1,708.0 853.9 Total regulatory liabilities $ 1,721.1 $ 864.1 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents the deferral of revenues less the associated cost of sales related to the mines, which were not included in the 2015 rate order. We intend to request that this deferral be applied for the benefit of Wisconsin retail electric customers in a future rate proceeding. |
Property, Plant, and Equipment
Property, Plant, and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Schedule of property, plant, and equipment | Property, plant, and equipment consisted of the following utility and non-utility and other assets at December 31: (in millions) 2017 2016 Utility property, plant, and equipment (1) $ 9,870.7 $ 11,232.9 Less: Accumulated depreciation 2,970.3 3,606.9 Net 6,900.4 7,626.0 CWIP 159.5 111.5 Plant to be retired, net 872.7 — Net utility property, plant, and equipment 7,932.6 7,737.5 Property under capital leases 3,009.1 2,898.0 Less: Accumulated amortization 945.9 837.8 Net leased facilities 2,063.2 2,060.2 Non-utility and other property, plant, and equipment 11.9 46.4 Less: Accumulated depreciation — 12.7 Net (2) 11.9 33.7 CWIP — 0.9 Net non-utility and other property, plant, and equipment 11.9 34.6 Total property, plant, and equipment $ 10,007.7 $ 9,832.3 (1) Effective January 1, 2017, we transferred 2,500 miles of electric distribution lines and related electric distribution substations in the Upper Peninsula of Michigan to UMERC. The net book value of the property, plant, and equipment we transferred to UMERC was $61.1 million . See Note 4, Related Parties, for more information . (2) In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes to asset retirement obligations | The following table shows changes to our AROs during the years ended December 31: (in millions) 2017 2016 2015 Balance as of January 1 $ 61.5 $ 58.7 $ 40.5 Accretion 3.2 3.0 2.3 Additions 5.5 (1) — 15.9 (2) Liabilities settled (1.9 ) (0.2 ) — Balance as of December 31 $ 68.3 $ 61.5 $ 58.7 (1) During 2017, an ARO was recorded related to the removal and dismantlement of the Rothschild Biomass Plant. (2) During 2015, an ARO was recorded for the fly-ash landfills located at our generation facilities. |
Common Equity (Tables)
Common Equity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation expense and related deferred tax benefit recognized in income | The following table summarizes our pre-tax stock-based compensation expense and the related tax benefit recognized in income for the years ended December 31: (in millions) 2017 2016 2015 Stock options $ 1.3 $ 1.8 $ 3.2 Restricted stock 0.8 1.8 2.1 Performance units 9.9 3.9 7.5 Stock-based compensation expense $ 12.0 $ 7.5 $ 12.8 Related tax benefit $ 4.8 $ 3.0 $ 5.1 |
Schedule of stock option activity | The following is a summary of our employees' WEC Energy Group stock option activity during 2017 : Stock Options Number of Options Weighted-Average Exercise Price Weighted-Average Remaining Contractual Life (in years) Aggregate Intrinsic Value (in millions) Outstanding as of January 1, 2017 1,285,806 $ 33.41 Granted 80,770 $ 58.31 Exercised (300,064 ) $ 25.54 Transferred 129,635 $ 35.48 Outstanding as of December 31, 2017 1,196,147 $ 37.29 4.6 $ 34.9 Exercisable as of December 31, 2017 971,547 $ 33.43 3.8 $ 32.1 |
Schedule of restricted stock activity | The following is a summary of our employees' WEC Energy Group restricted stock activity during 2017 : Restricted Shares Number of Shares Weighted-Average Grant Date Fair Value Outstanding as of January 1, 2017 16,261 $ 50.39 Granted 8,001 $ 58.10 Released (8,018 ) $ 48.78 Transferred (379 ) $ 57.77 Forfeited (582 ) $ 53.83 Outstanding as of December 31, 2017 15,283 $ 54.96 |
Preferred Stock (Tables)
Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Class of Stock Disclosures [Abstract] | |
Schedule of stock by class | The following table shows preferred stock authorized and outstanding at December 31, 2017 and 2016 : (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Six Per Cent. Preferred Stock 45,000 44,498 — $ 4.4 $100 par value, Serial Preferred Stock 2,286,500 3.60% Series 260,000 $ 101 26.0 $25 par value, Serial Preferred Stock 5,000,000 — — — Total $ 30.4 |
Short-Term Debt and Lines of 40
Short-Term Debt and Lines of Credit (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Short-term Debt [Abstract] | |
Short-term notes payable balances and their corresponding weighted-average interest rates | The following table shows our short-term borrowings and their corresponding weighted-average interest rates as of December 31: (in millions, except percentages) 2017 2016 Commercial paper Amount outstanding at December 31 $ 210.9 $ 159.0 Average interest rate on amounts outstanding at December 31 1.81 % 0.87 % |
Schedule of Revolving Credit Facilities | The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 : (in millions) Maturity 2017 Revolving credit facility October 2022 $ 500.0 Less: Letters of credit issued inside credit facility $ 1.2 Commercial paper outstanding 210.9 Available capacity under existing agreement $ 287.9 |
Long-Term Debt and Capital Le41
Long-Term Debt and Capital Lease Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Long-term Debt and Capital Lease Obligations [Abstract] | |
Long-term debt outstanding maturities | The following table shows the future maturities of our long-term debt outstanding (excluding obligations under capital leases) as of December 31, 2017 : (in millions) 2018 $ 250.0 2019 250.0 2020 — 2021 300.0 2022 — Thereafter 1,885.0 Total $ 2,685.0 |
Capital lease payments | We paid the following lease payments during 2017 , 2016 , and 2015 : (in millions) 2017 2016 2015 Long-term power purchase commitment $ 7.2 $ 37.6 $ 36.2 PWGS 85.0 82.4 103.8 ERGS 335.5 329.8 306.7 Total $ 427.7 $ 449.8 $ 446.7 |
Summary of capitalized leased facilities | The following table summarizes our capitalized leased facilities as of December 31: (in millions) 2017 2016 Long-term power purchase commitment Under capital lease $ 140.3 $ 140.3 Accumulated amortization (115.2 ) (109.5 ) Total long-term power purchase commitment $ 25.1 $ 30.8 PWGS Under capital lease $ 727.4 $ 704.2 Accumulated amortization (305.1 ) (274.7 ) Total PWGS $ 422.3 $ 429.5 ERGS Under capital lease $ 2,141.4 $ 2,053.5 Accumulated amortization (525.6 ) (453.6 ) Total ERGS $ 1,615.8 $ 1,599.9 Total leased facilities $ 2,063.2 $ 2,060.2 |
Future minimum lease payments under capital lease and present value of net minimum lease payments | Future minimum lease payments under our capital leases and the present value of our net minimum lease payments as of December 31, 2017 are as follows: (in millions) Power Purchase Commitment PWGS ERGS Total 2018 $ 14.7 $ 96.3 $ 287.7 $ 398.7 2019 15.5 96.3 287.7 399.5 2020 16.4 96.3 287.7 400.4 2021 17.2 96.3 287.7 401.2 2022 7.6 96.3 287.6 391.5 Thereafter — 857.3 5,029.5 5,886.8 Total minimum lease payments 71.4 1,338.8 6,467.9 7,878.1 Less: Estimated executory costs (33.1 ) — — (33.1 ) Net minimum lease payments 38.3 1,338.8 6,467.9 7,845.0 Less: Interest (11.3 ) (694.1 ) (4,273.3 ) (4,978.7 ) Present value of minimum lease payments 27.0 644.7 2,194.6 2,866.3 Less: Due currently (3.7 ) (19.4 ) (19.4 ) (42.5 ) Long-term obligations under capital lease $ 23.3 $ 625.3 $ 2,175.2 $ 2,823.8 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Summary of income tax expense | The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2017 2016 2015 Current tax expense $ 81.5 $ 4.8 $ 33.1 Deferred income taxes, net 110.6 207.3 180.0 Investment tax credit, net (0.9 ) (1.1 ) (1.1 ) Total income tax expense $ 191.2 $ 211.0 $ 212.0 |
Statutory rate reconciliation | The provision for income taxes for each of the years ended December 31 differs from the amount of income tax determined by applying the applicable United States statutory federal income tax rate to income before income taxes and preferred dividend as a result of the following: 2017 2016 2015 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 184.4 35.0 % $ 201.4 35.0 % $ 205.7 35.0 % State income taxes net of federal tax benefit 27.9 5.3 % 31.8 5.5 % 31.0 5.3 % Production tax credits (17.6 ) (3.3 )% (16.5 ) (2.8 )% (17.8 ) (3.0 )% Domestic production activities deduction (7.8 ) (1.5 )% (7.8 ) (1.4 )% (7.8 ) (1.3 )% AFUDC – Equity (1.1 ) (0.2 )% (1.5 ) (0.3 )% (2.0 ) (0.3 )% Investment tax credit restored (0.9 ) (0.2 )% (1.1 ) (0.2 )% (1.1 ) (0.2 )% Other, net 6.3 1.1 % 4.7 0.8 % 4.0 0.5 % Total income tax expense $ 191.2 36.2 % $ 211.0 36.6 % $ 212.0 36.0 % |
Components of deferred income taxes | The components of deferred income taxes as of December 31 were as follows: (in millions) 2017 2016 Deferred tax assets Tax gross up – regulatory items $ 240.1 $ — Future tax benefits 133.1 143.7 Deferred revenues 128.8 207.2 Employee benefits and compensation 50.2 77.6 Construction advances 15.0 20.0 Uncollectible account expense 12.5 16.1 Emission allowances 0.1 0.2 Other 54.8 70.9 Total deferred tax assets 634.6 535.7 Deferred tax liabilities Property-related 1,487.0 2,257.3 Employee benefits and compensation 117.4 179.3 Deferred transmission costs 60.1 93.1 Prepaid tax, insurance, and other 33.8 50.2 Investment in transmission affiliate — 195.1 Other 91.8 94.0 Total deferred tax liabilities 1,790.1 2,869.0 Deferred tax liability, net $ 1,155.5 $ 2,333.3 |
Reconciliation of unrecognized tax benefits | We previously adopted accounting guidance related to uncertainty in income taxes. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: (in millions) 2017 2016 Balance as of January 1 $ 5.1 $ 6.1 Reductions for tax positions of prior years (5.1 ) (1.0 ) Balance as of December 31 $ — $ 5.1 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair value of assets and liabilities measured on recurring basis, by level within the fair value hierarchy | The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2017 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.5 $ 0.1 $ — $ 0.6 Petroleum products contracts 0.9 — — 0.9 FTRs — — 2.4 2.4 Coal contracts — 0.7 — 0.7 Total derivative assets $ 1.4 $ 0.8 $ 2.4 $ 4.6 Derivative liabilities Natural gas contracts $ 2.0 $ 0.1 $ — $ 2.1 Coal contracts — 0.3 — 0.3 Total derivative liabilities $ 2.0 $ 0.4 $ — $ 2.4 December 31, 2016 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 6.0 $ 0.8 $ — $ 6.8 Petroleum products contracts 0.2 — — 0.2 FTRs — — 3.1 3.1 Coal contracts — 1.9 — 1.9 Total derivative assets $ 6.2 $ 2.7 $ 3.1 $ 12.0 Derivative liabilities Natural gas contracts $ 0.1 $ — $ — $ 0.1 Petroleum products contracts 0.1 — — 0.1 Coal contracts — 0.5 — 0.5 Total derivative liabilities $ 0.2 $ 0.5 $ — $ 0.7 |
Reconcilation of changes in the FV of items categorized as level 3 measurements | The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: (in millions) 2017 2016 2015 Balance at the beginning of the period $ 3.1 $ 1.6 $ 7.0 Purchases 6.9 8.1 3.9 Settlements (7.6 ) (6.6 ) (9.3 ) Balance at the end of the period $ 2.4 $ 3.1 $ 1.6 |
Carrying amount and estimated fair value of certain financial instruments | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2017 December 31, 2016 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Preferred stock $ 30.4 $ 30.5 $ 30.4 $ 28.8 Long-term debt, including current portion 2,662.3 2,976.3 2,661.1 2,923.4 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative assets and derivative liabilities | The following table shows our derivative assets and derivative liabilities: December 31, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Other current Natural gas contracts $ 0.6 $ 1.9 $ 6.3 $ 0.1 Petroleum products contracts 0.9 — 0.2 0.1 FTRs 2.4 — 3.1 — Coal contracts 0.6 0.1 1.5 0.5 Total other current $ 4.5 $ 2.0 $ 11.1 $ 0.7 Other long-term Natural gas contracts $ — $ 0.2 $ 0.5 $ — Coal contracts 0.1 0.2 0.4 — Total other long-term $ 0.1 $ 0.4 $ 0.9 $ — Total $ 4.6 $ 2.4 $ 12.0 $ 0.7 |
Estimated notional volumes and gain (losses) | Our estimated notional sales volumes and realized gains (losses) were as follows: December 31, 2017 December 31, 2016 December 31, 2015 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains (Losses) Natural gas contracts 26.9 Dth $ (1.0 ) 35.3 Dth $ (12.3 ) 24.0 Dth $ (12.6 ) Petroleum products contracts 16.7 gallons (1.4 ) 10.3 gallons (2.6 ) 4.0 gallons (0.2 ) FTRs 27.1 MWh 7.6 25.3 MWh 7.3 22.8 MWh 3.2 Total $ 5.2 $ (7.6 ) $ (9.6 ) |
Offsetting Assets and Liabilities | The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets: December 31, 2017 December 31, 2016 (in millions) Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Gross amount recognized on the balance sheet $ 4.6 $ 2.4 $ 12.0 $ 0.7 Gross amount not offset on the balance sheet (1.3 ) (2.0 ) (1) (3.6 ) (2) (0.2 ) Net amount $ 3.3 $ 0.4 $ 8.4 $ 0.5 (1) Includes cash collateral posted of $0.7 million at December 31, 2017 . (2) Includes cash collateral received of $3.4 million at December 31, 2016 . |
Employee Benefits (Tables)
Employee Benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Reconciliation of the changes in the plans' benefit obligations and fair value of assets | The following tables provide a reconciliation of the changes in our plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2017 2016 2017 2016 Change in benefit obligation Obligation at January 1 $ 1,177.0 $ 1,290.6 $ 298.5 $ 313.8 Service cost 12.2 10.5 7.0 7.3 Interest cost 47.0 49.7 12.1 13.2 Participant contributions — — 5.7 8.8 Plan amendments — (2.6 ) (6.8 ) — Net transfer to/from affiliates (13.4 ) (1) (121.1 ) (2) (3.3 ) (1) (17.0 ) (2) Actuarial loss (gain) 53.1 25.3 5.1 (9.7 ) Benefit payments (82.0 ) (75.4 ) (16.5 ) (19.0 ) Federal subsidy on benefits paid N/A N/A 1.7 1.1 Obligation at December 31 $ 1,193.9 $ 1,177.0 $ 303.5 $ 298.5 Change in fair value of plan assets Fair value at January 1 $ 1,102.8 $ 1,179.3 $ 205.1 $ 216.1 Actual return on plan assets 121.9 73.0 25.9 13.5 Employer contributions 5.1 5.3 3.2 2.7 Participant contributions — — 5.7 8.8 Net transfer to/from affiliates (13.7 ) (1) (79.4 ) (2) (3.3 ) (1) (17.0 ) (2) Benefit payments (82.0 ) (75.4 ) (16.5 ) (19.0 ) Fair value at December 31 $ 1,134.1 $ 1,102.8 $ 220.1 $ 205.1 Funded status at December 31 $ (59.8 ) $ (74.2 ) $ (83.4 ) $ (93.4 ) (1) Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities, primarily a result of our customer service employees being transferred to WBS. (2) Benefit obligations and plan assets were moved along with our employees who were transferred to/from affiliated entities. See Note 4, Related Parties, for more information . |
Amounts recognized on the balance sheets at December 31 related to the funded status of the benefit plans | The amounts recognized on our balance sheets at December 31 related to the funded status of the benefit plans were as follows: Pension Costs OPEB Costs (in millions) 2017 2016 2017 2016 Pension and OPEB obligations $ (59.8 ) $ (74.2 ) $ (83.4 ) $ (93.4 ) |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for the pension plans for which we have an accumulated benefit obligation in excess of plan assets. Amounts presented are as of December 31: (in millions) 2017 2016 Projected benefit obligation $ 1,193.9 $ 1,177.0 Accumulated benefit obligation 1,192.4 1,175.8 Fair value of plan assets 1,134.1 1,102.8 |
Amounts that had not yet been recognized in the entity's net periodic benefit cost | The following table shows the amounts that have not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2017 2016 2017 2016 Net regulatory assets Net actuarial loss (gain) $ 485.4 $ 518.5 $ (1.6 ) $ 4.6 Prior service costs (credits) (1.0 ) 0.2 (8.4 ) (3.0 ) Total $ 484.4 $ 518.7 $ (10.0 ) $ 1.6 |
Estimated amounts that will be amortized into net periodic benefit cost | The following table shows the estimated amounts that will be amortized into net periodic benefit cost during 2018: (in millions) Pension Costs OPEB Costs Net actuarial loss $ 37.5 $ — Prior service costs (credits) 0.9 (2.3 ) Total 2018 – estimated amortization $ 38.4 $ (2.3 ) |
Schedule of the components of net periodic benefit cost | The components of net periodic benefit cost (including amounts capitalized to our balance sheets) for the years ended December 31 were as follows: Pension Costs OPEB Costs (in millions) 2017 2016 2015 2017 2016 2015 Service cost $ 12.2 $ 10.5 $ 14.7 $ 7.0 $ 7.3 $ 9.0 Interest cost 47.0 49.7 52.9 12.1 13.2 13.4 Expected return on plan assets (76.6 ) (77.7 ) (83.6 ) (14.7 ) (14.0 ) (16.0 ) Plan settlement 4.1 — — — — — Amortization of prior service cost (credit) 1.1 1.6 2.0 (1.4 ) (1.1 ) (1.1 ) Amortization of net actuarial loss 35.4 32.4 35.6 — 1.0 1.0 Net periodic benefit cost $ 23.2 $ 16.5 $ 21.6 $ 3.0 $ 6.4 $ 6.3 |
Weighted-average assumptions used to determine benefit obligations and net periodic benefit cost for the plans | The weighted-average assumptions used to determine the benefit obligations for the plans were as follows for the years ended December 31: Pension OPEB 2017 2016 2017 2016 Discount rate 3.65% 4.15% 3.65% 4.20% Rate of compensation increase 3.20% 3.20% N/A N/A Assumed medical cost trend rate (pre 65) N/A N/A 6.50% 7.00% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2024 2021 Assumed medical cost trend rate (post 65) N/A N/A 6.18% 7.00% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2028 2021 The weighted-average assumptions used to determine the net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2017 2016 2015 Discount rate 4.12% 4.45% 4.15% Expected return on plan assets 7.00% 7.00% 7.00% Rate of compensation increase 3.20% 3.50% 4.00% OPEB Costs 2017 2016 2015 Discount rate 4.10% 4.45% 4.20% Expected return on plan assets 7.25% 7.25% 7.25% Assumed medical cost trend rate (Pre 65/Post 65) 7.00% 7.50% 7.50% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2021 2021 2021 |
Effects of a one-percentage-point change in assumed health care cost trend rates | For the year ended December 31, 2017 , a one-percentage-point change in assumed health care cost trend rates would have had the following effects: (in millions) 1% Increase 1% Decrease Effect on total of service and interest cost components of net periodic postretirement health care benefit cost $ 2.9 $ (2.3 ) Effect on the health care component of the accumulated postretirement benefit obligation 29.3 (24.2 ) |
Investments recorded at fair value, by asset class | The following tables summarize the fair values of our investments by asset class: December 31, 2017 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ — $ 6.6 $ — $ 6.6 $ 2.1 $ 0.5 $ — $ 2.6 Equity securities: Unites States Equity 109.4 0.1 — 109.5 29.0 — — 29.0 International Equity 114.4 — — 114.4 32.2 — — 32.2 Fixed income securities: * United States Bonds 75.9 467.8 — 543.7 24.4 46.3 — 70.7 International Bonds 9.7 32.8 — 42.5 1.7 2.9 — 4.6 Private Equity and Real Estate — 20.6 55.3 75.9 — 1.4 3.8 5.2 $ 309.4 $ 527.9 $ 55.3 $ 892.6 $ 89.4 $ 51.1 $ 3.8 $ 144.3 Investments measured at net asset value $ 241.5 $ 75.8 Total $ 309.4 $ 527.9 $ 55.3 $ 1,134.1 $ 89.4 $ 51.1 $ 3.8 $ 220.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. December 31, 2016 Pension Plan Assets OPEB Assets (in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Asset Class Cash and cash equivalents $ 1.1 $ 19.2 $ — $ 20.3 $ 6.5 $ 1.3 $ — $ 7.8 Equity securities: United States equity 85.5 0.1 — 85.6 10.5 — — 10.5 International equity 17.7 — — 17.7 1.3 — — 1.3 Fixed income securities: * United States bonds — 455.3 — 455.3 — 44.0 — 44.0 International bonds — 31.6 — 31.6 — 2.8 — 2.8 Private Equity and Real Estate — — 11.0 11.0 — — 0.7 0.7 $ 104.3 $ 506.2 $ 11.0 $ 621.5 $ 18.3 $ 48.1 $ 0.7 $ 67.1 Investments measured at net asset value $ 481.3 $ 138.0 Total $ 104.3 $ 506.2 $ 11.0 $ 1,102.8 $ 18.3 $ 48.1 $ 0.7 $ 205.1 * This category represents investment grade bonds of United States and foreign issuers denominated in United States dollars from diverse industries. |
Reconciliation of changes in the fair value of plan assets categorized as Level 3 measurements | The following tables set forth a reconciliation of changes in the fair value of pension and OPEB plan assets categorized as Level 3 in the fair value hierarchy: Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2017 $ 11.0 $ 0.7 Realized and unrealized gains 1.9 0.2 Purchases 22.3 1.5 Transfers into level 3 20.1 1.4 Ending balance at December 31, 2017 $ 55.3 $ 3.8 Private Equity and Real Estate (in millions) Pension OPEB Beginning balance at January 1, 2016 $ 4.5 $ 0.3 Purchases 6.5 0.4 Ending balance at December 31, 2016 $ 11.0 $ 0.7 |
Schedule of expected future benefit payments | The following table shows the payments, reflecting expected future service, that we expect to make for pension and OPEB: (in millions) Pension Costs OPEB Costs 2018 $ 92.4 $ 13.5 2019 90.1 14.2 2020 89.2 14.9 2021 86.0 15.7 2022 82.3 16.2 2023-2027 368.2 85.5 |
Investment in American Transm46
Investment in American Transmission Company (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
ATC | |
Investment in ATC | |
Schedule of changes to our investment in ATC | The following table provides a reconciliation of our investment in ATC during the years ended December 31: (in millions) 2017 2016 2015 Balance at January 1 $ 402.0 $ 382.2 $ 372.9 Less: Transfer of ownership interest 402.0 — — Add: Earnings from equity method investment — 55.5 47.8 Add: Capital contributions — 16.1 4.6 Less: Distributions — 51.7 * 42.9 Less: Other — 0.1 0.2 Balance at December 31 $ — $ 402.0 $ 382.2 * Of this amount, $13.4 million was recorded as a receivable from ATC at December 31, 2016. |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Schedule of information concerning our reportable segments | The following tables show summarized financial information related to our reportable segments for the years ended December 31, 2017 , 2016 , and 2015 . 2017 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,711.7 $ — $ 3,711.7 Other operation and maintenance 1,358.5 — 1,358.5 Depreciation and amortization 331.6 — 331.6 Operating income 625.6 — 625.6 Interest expense 117.0 0.3 117.3 Capital expenditures 596.1 — 596.1 Total assets 13,121.6 — 13,121.6 2016 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,792.8 $ — $ 3,792.8 Other operation and maintenance 1,430.2 — 1,430.2 Depreciation and amortization 325.4 — 325.4 Operating income 629.5 — 629.5 Equity in earnings of transmission affiliate — 55.5 55.5 Interest expense 116.6 1.0 117.6 Capital expenditures 468.9 0.6 469.5 Total assets 12,945.1 426.4 13,371.5 2015 (in millions) Utility Other Wisconsin Electric Power Company Consolidated Operating revenues $ 3,854.1 $ — $ 3,854.1 Other operation and maintenance 1,384.9 — 1,384.9 Depreciation and amortization 304.0 — 304.0 Operating income 648.9 — 648.9 Equity in earnings of transmission affiliate — 47.8 47.8 Interest expense 117.7 1.3 119.0 Capital expenditures 518.8 0.4 519.2 Total assets 12,727.6 412.0 13,139.6 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum future commitments related to purchase obligations | The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2017 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2018 2019 2020 2021 2022 Later Years Electric utility: Nuclear 2033 $ 9,184.5 $ 420.1 $ 445.4 $ 475.1 $ 501.1 $ 531.2 $ 6,811.6 Coal supply and transportation 2020 215.0 132.2 53.9 28.9 — — — Purchased power 2031 93.1 29.1 16.6 13.7 10.9 9.0 13.8 Natural gas utility supply and transportation 2048 462.3 65.6 54.8 43.6 30.3 22.6 245.4 Total $ 9,954.9 $ 647.0 $ 570.7 $ 561.3 $ 542.3 $ 562.8 $ 7,070.8 |
Schedule of future minimum payments under noncancelable operating leases | Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2018 $ 3.5 2019 3.4 2020 1.9 2021 1.4 2022 1.5 Later years 23.0 Total $ 34.7 |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2017 2016 Regulatory assets $ 30.4 $ 29.9 Reserves for future remediation 18.5 19.0 |
Supplemental Cash Flow Inform49
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information | (in millions) 2017 2016 2015 Cash (paid) for interest, net of amount capitalized $ (115.1 ) $ (116.2 ) $ (116.2 ) Cash (paid) received for income taxes, net (71.7 ) 100.2 (58.5 ) Significant non-cash transactions: Accounts payable related to construction costs 13.2 9.1 11.7 Transfer of investment in ATC to another subsidiary of WEC Energy Group (1) (2) 415.4 — — Transfer of net assets to UMERC (1) 61.1 — — Equity settlement of a short-term note receivable between Bostco and our parent company 4.8 — — (1) See Note 4, Related Parties, for more information on these transactions. (2) The amount transferred includes a $13.4 million receivable for distributions approved and recorded in December 2016. |
Quarterly Financial Informati50
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information (unaudited) | (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2017 Operating revenues $ 972.0 $ 855.4 $ 943.8 $ 940.5 $ 3,711.7 Operating income 185.1 142.8 163.4 134.3 625.6 Net income attributed to common shareholder 101.8 75.3 89.4 69.1 335.6 2016 Operating revenues $ 975.5 $ 877.2 $ 1,023.8 $ 916.3 $ 3,792.8 Operating income 181.5 146.9 196.4 104.7 629.5 Net income attributed to common shareholder 107.3 82.6 115.2 59.2 364.3 |
Summary of Significant Accoun51
Summary of Significant Accounting Policies General Information (Details) $ in Millions | Dec. 31, 2017USD ($)wholly_owned_subsidiaries | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Condensed Financial Statements, Captions | |||
Assets | $ 13,121.6 | $ 13,371.5 | $ 13,139.6 |
Subsidiaries | |||
Condensed Financial Statements, Captions | |||
Number of wholly owned subsidiaries | wholly_owned_subsidiaries | 1 | ||
Assets | $ 24.4 |
Summary of Significant Accoun52
Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Maximum term of original maturity to classify instrument as cash equivalent | 3 months |
Summary of Significant Accoun53
Summary of Significant Accounting Policies Revenues and Customer Receivables (Details) | 12 Months Ended |
Dec. 31, 2017customer | |
Revenues from external customers | |
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% |
Customer concentration risk | |
Revenues from external customers | |
Number of customers that account for more than 10% if revenues | 0 |
Threshold percentage of revenues from major customers | 10.00% |
Summary of Significant Accoun54
Summary of Significant Accounting Policies Materials, Supplies, and Inventories (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Accounting Policies [Abstract] | ||
Materials and supplies | $ 140.7 | $ 148.1 |
Fossil fuel | 74.8 | 91.1 |
Natural gas in storage | 35.2 | 31.8 |
Total | $ 250.7 | $ 271 |
Summary of Significant Accoun55
Summary of Significant Accounting Policies Property, Plant, and Equipment (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Property, plant, and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.95% | 3.00% | 3.01% |
Software | Minimum | |||
Property, plant, and equipment | |||
Estimated useful life | 5 years | ||
Software | Maximum | |||
Property, plant, and equipment | |||
Estimated useful life | 15 years |
Summary of Significant Accoun56
Summary of Significant Accounting Policies Allowance for Funds Used During Construction (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Allowance for funds used during construction | |||
Percentage of retail jurisdictional construction work in progress expenditure subject to public utilities allowance for funds used during construction calculation | 50.00% | ||
AFUDC - Debt | $ 1.2 | $ 1.7 | $ 2.2 |
AFUDC - Equity | $ 3.1 | $ 4.2 | $ 5.7 |
Retail operations | |||
Allowance for funds used during construction | |||
Interest rate on accrued AFUDC | 8.45% | 8.45% | 8.45% |
Wholesale operations | |||
Allowance for funds used during construction | |||
Interest rate on accrued AFUDC | 5.94% | 2.73% | 1.72% |
Summary of Significant Accoun57
Summary of Significant Accounting Policies Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares of WEC Energy Group common stock authorized for issuance | 34,300,000 | ||
Cumulative-effect from adoption of ASU 2016-09 | $ 11.9 | ||
Other impacts from adoption of ASU 2016-09 | $ 0 | ||
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Minimum Exercise Price of Stock Option as a Percent of Common Stock Fair Value on the Grant Date | 100.00% | ||
Period after the grant date during which stock options can't be exercised (in months) | 6 months | ||
Maximum term of awards (in years) | 10 years | ||
Stock options granted (in shares) | 80,770 | 92,880 | 495,550 |
Estimated weighted-average fair value per stock option (in dollars per share) | $ 7.12 | $ 4.92 | $ 5.29 |
Risk-free interest rate, minimum (as a percent) | 0.70% | 0.50% | 0.10% |
Risk-free interest rate, maximum (as a percent) | 2.50% | 2.20% | 2.10% |
Dividend yield (as a percent) | 3.50% | 4.00% | 3.70% |
Expected volatility (as a percent) | 19.00% | 18.00% | 18.00% |
Expected life (years) | 6 years 2 months | 5 years 9 months | 5 years 9 months |
Restricted stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Percentage to vest each year after the grant date | 33.00% | ||
Performance units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period (in years) | 3 years | ||
Performance units | Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance units, payout ratio (as a percent) | 0.00% | ||
Performance units | Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Performance units, payout ratio (as a percent) | 175.00% |
Acquisitions Acquisitions - Blu
Acquisitions Acquisitions - Bluewater Acquisition (Details) $ in Millions | 1 Months Ended |
Jun. 30, 2017USD ($) | |
WEC Energy Group | Bluewater | |
Business Acquisition [Line Items] | |
Business Combination, Consideration Transferred | $ 226 |
Acquisitions - Integrys Acquisi
Acquisitions - Integrys Acquisition (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Jun. 30, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jun. 29, 2015 | |
Severance | |||||
Severance expense | $ 25.8 | ||||
Integrys | |||||
PSCW Conditions of Approval - Earnings Sharing Mechanism | |||||
Duration of earnings cap condition imposed by the PSCW (in years) | 3 years | ||||
Percentage of first 50 basis points to be shared with customers | 50.00% | ||||
ROE in excess of authorized amount (as a percent) | 0.50% | ||||
Severance | |||||
Severance expense | $ 6.6 | ||||
Severance payments | $ 4.6 | $ 1.2 | |||
Integrys | WEC Energy Group | |||||
Business Acquisition [Line Items] | |||||
Percentage of Integrys common shares acquired | 100.00% | ||||
Integrys | Earnings sharing mechanism | |||||
PSCW Conditions of Approval - Earnings Sharing Mechanism | |||||
Expense for earnings sharing mechanism | $ 0.1 | $ 21.1 |
Dispositions (Details)
Dispositions (Details) - Utility $ in Millions | 3 Months Ended |
Jun. 30, 2016USD ($) | |
Dispositions | |
After-tax gain on sale | $ 6.5 |
Other operation and maintenance | |
Dispositions | |
Pre-tax gain on sale | $ 10.9 |
Related Parties (Details)
Related Parties (Details) - USD ($) $ in Millions | Jan. 01, 2017 | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Wispark LLC | ||||
Related parties | ||||
Notes receivable, from buyer | $ 7 | |||
Bostco | WEC Energy Group | ||||
Related parties | ||||
Subsidiary note payable to WEC Energy Group | $ 18.5 | |||
Bostco | Wispark LLC | ||||
Related parties | ||||
Accounts receivable, related parties, current | $ 7 | |||
ATC | ||||
Related parties | ||||
Accounts receivable, related parties, current | $ 0.8 | 1.1 | ||
Equity method investment and related receivable for distributions transfer to affiliated company | $ 415.4 | |||
Transfer of deferred income tax related to ATC to affiliated company | $ 186.8 | |||
Accounts payable, related parties, current | $ 22.2 | $ 20 |
Related Parties - Other Transac
Related Parties - Other Transactions (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Related parties | |||
Proceeds from assets transferred to WBS | $ 0 | $ 13.1 | $ 0 |
Payments for liabilities transferred to WBS | 0.3 | 116 | 0 |
We Power LLC | |||
Related parties | |||
Lease Payments Paid To Related Party | 420.5 | 412.2 | 410.5 |
Construction Work In Progress Billed To Related Party | 57.3 | 37.9 | 58.8 |
WBS | |||
Related parties | |||
Charges to related party for services and billings | 255.7 | 213.8 | 11.1 |
Charges from related party for services and billings | 215.4 | 310.6 | 1.3 |
Proceeds from liabilities transferred from WBS | 1.2 | ||
Proceeds from assets transferred to WBS | 13.1 | ||
Payments for liabilities transferred to WBS | 1.5 | 116 | |
WPS | |||
Related parties | |||
Charges to related party for services and billings | 28.2 | 9 | 13.4 |
Charges from related party for services and billings | 4.5 | 4.2 | 4.9 |
Natural gas purchases | 1.6 | 1.9 | 0.4 |
WG | |||
Related parties | |||
Charges to related party for services and billings | 64 | 60.6 | 79.4 |
Charges from related party for services and billings | 23.1 | 21.5 | 23.5 |
Natural gas purchases | 5.3 | 5.3 | 5.3 |
UMERC | |||
Related parties | |||
Charges to related party for services and billings | 125.5 | 0 | 0 |
Electric sales to UMERC | 30.8 | 0 | 0 |
Bluewater | |||
Related parties | |||
Charges to related party for services and billings | 2.7 | 0 | 0 |
ATC | |||
Related parties | |||
Charges to related party for services and billings | 10.9 | 10 | 9.7 |
Charges from related party for services and billings | 241.4 | 247.8 | 238.5 |
Refund from ATC per FERC ROE order | $ (19.4) | $ 0 | $ 0 |
Related Parties - UMERC (Detail
Related Parties - UMERC (Details) - UMERC transfer $ in Millions | Jan. 01, 2017USD ($)milecustomer | Dec. 31, 2017USD ($) |
Related parties | ||
Miles of electric distribution lines transferred | mile | 2,500 | |
Transfer of net assets to affiliate | $ | $ 61.1 | $ 61.1 |
Utility | ||
Related parties | ||
Number of customers | 27,500 | |
Electric distribution | ||
Related parties | ||
Number of customers | 50 |
Regulatory Assets and Liabili64
Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Regulatory Assets | ||
Total regulatory assets | $ 1,984.9 | $ 2,036.6 |
Other Disclosures | ||
Regulatory assets not earning a return | 11.4 | |
Regulatory assets earning a return based on short-term interest rates | 254 | |
Plant related - capital leases | ||
Regulatory Assets | ||
Total regulatory assets | 801.3 | 724.8 |
Unrecognized pension and OPEB costs | ||
Regulatory Assets | ||
Total regulatory assets | 484.4 | 520.3 |
SSR | ||
Regulatory Assets | ||
Total regulatory assets | 298.9 | 188.1 |
Electric transmission costs | ||
Regulatory Assets | ||
Total regulatory assets | 220.7 | 231.9 |
We Power generation | ||
Regulatory Assets | ||
Total regulatory assets | 71.3 | 54.1 |
AROs | ||
Regulatory Assets | ||
Total regulatory assets | 41.4 | 39.7 |
Environmental remediation costs | ||
Regulatory Assets | ||
Total regulatory assets | 30.4 | 29.9 |
Energy efficiency programs | ||
Regulatory Assets | ||
Total regulatory assets | 28.2 | 38.5 |
Income tax related items | ||
Regulatory Assets | ||
Total regulatory assets | 0 | 200.8 |
Other, net | ||
Regulatory Assets | ||
Total regulatory assets | $ 8.3 | $ 8.5 |
Regulatory Assets and Liabili65
Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Regulatory Liabilities | ||
Current liabilities | $ 13.1 | $ 10.2 |
Regulatory liabilities | 1,708 | 853.9 |
Total regulatory liabilities | 1,721.1 | 864.1 |
2017 Tax Legislation impact and income tax related | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 849.1 | 0 |
Removal costs | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 730 | 722.9 |
Mines deferral | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 95.1 | 70.2 |
Other, net | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 46.9 | $ 71 |
Utility operations | ||
Regulatory Liabilities | ||
Increase (decrease) in deferred income taxes | $ 1,065 |
Property, Plant, and Equipmen66
Property, Plant, and Equipment (Details) $ in Millions | Jan. 01, 2017USD ($)mile | Oct. 31, 2017MW | Aug. 31, 2016MW | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Property, plant, and equipment | |||||
Accumulated depreciation and amortization | $ 3,741.8 | $ 3,619.6 | |||
Net property, plant, and equipment | 10,007.7 | 9,832.3 | |||
Severance expense | 25.8 | ||||
UMERC | |||||
Property, plant, and equipment | |||||
Capacity of natural gas-fired generation facility (in megawatts) | MW | 180 | 180 | |||
Pleasant Prairie power plant | |||||
Property, plant, and equipment | |||||
Plant to be retired, net | 681.3 | ||||
Presque Isle power plant | |||||
Property, plant, and equipment | |||||
Plant to be retired, net | 191.4 | ||||
UMERC transfer | |||||
Property, plant, and equipment | |||||
Miles of electric distribution lines transferred | mile | 2,500 | ||||
Book value of net assets transferred (including the related deferred income tax liabilities) | $ 61.1 | ||||
Utility operations | |||||
Property, plant, and equipment | |||||
Property, plant, and equipment | 9,870.7 | 11,232.9 | |||
Accumulated depreciation and amortization | 2,970.3 | 3,606.9 | |||
Net | 6,900.4 | 7,626 | |||
CWIP | 159.5 | 111.5 | |||
Plant to be retired, net | 872.7 | 0 | |||
Net property, plant, and equipment | 7,932.6 | 7,737.5 | |||
Utility operations | Capital leases | |||||
Property, plant, and equipment | |||||
Property, plant, and equipment | 3,009.1 | 2,898 | |||
Accumulated depreciation and amortization | 945.9 | 837.8 | |||
Net property, plant, and equipment | 2,063.2 | 2,060.2 | |||
Non-utility operations | |||||
Property, plant, and equipment | |||||
Property, plant, and equipment | 11.9 | 46.4 | |||
Accumulated depreciation and amortization | 0 | 12.7 | |||
Net | 11.9 | 33.7 | |||
CWIP | 0 | 0.9 | |||
Net property, plant, and equipment | $ 11.9 | $ 34.6 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Changes to asset retirement obligations | |||
Balance as of January 1 | $ 61.5 | $ 58.7 | $ 40.5 |
Accretion | 3.2 | 3 | 2.3 |
Additions | 5.5 | 0 | 15.9 |
Liabilities settled | (1.9) | (0.2) | 0 |
Balance as of December 31 | $ 68.3 | $ 61.5 | $ 58.7 |
Common Equity - Stock-Based Com
Common Equity - Stock-Based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 12 | $ 7.5 | $ 12.8 |
Related Tax Benefit | 4.8 | 3 | 5.1 |
Stock options | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 1.3 | 1.8 | 3.2 |
Restricted stock | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | 0.8 | 1.8 | 2.1 |
Performance units | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 9.9 | $ 3.9 | $ 7.5 |
Common Equity - Stock Options (
Common Equity - Stock Options (Details) - Stock options - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Options Activity | ||||
Outstanding, shares, beginning balance | 1,196,147 | 1,285,806 | ||
Granted, shares | 80,770 | 92,880 | 495,550 | |
Exercised, shares | (300,064) | |||
Transferred, shares | 129,635 | |||
Outstanding, shares, ending balance | 1,196,147 | 1,285,806 | ||
Options - Weighted Average Exercise Price | ||||
Outstanding, Weighted-Average Exercise Price, Beginning | $ 37.29 | $ 33.41 | ||
Granted, Weighted-Average Exercise Price | 58.31 | |||
Exercised, Weighted-Average Exercise Price | 25.54 | |||
Transferred, Weighted-Average Exercise Price | 35.48 | |||
Outstanding, Weighted-Average Exercise Price, Ending | $ 37.29 | $ 33.41 | ||
Options - Additional Disclosures | ||||
Outstanding, Weighted-Average Remaining Contractual Life (Years) | 4 years 7 months | |||
Outstanding, Aggregate Intrinsic Value | $ 34.9 | |||
Exercisable, shares | 971,547 | |||
Exercisable, Weighted-Average Exercise Price | $ 33.43 | |||
Exercisable, Weighted-Average Remaining Contractual Life (Years) | 3 years 9 months | |||
Exercisable, Aggregate Intrinsic Value | $ 32.1 | |||
Intrinsic value of options exercised | 11.2 | $ 14.1 | $ 34.6 | |
Tax benefit from option exercises | 4.5 | $ 5.6 | $ 14 | |
Compensation cost not yet recognized | $ 0.9 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 8 months | |||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 7.12 | $ 4.92 | $ 5.29 | |
Subsequent event | ||||
Options Activity | ||||
Granted, shares | 81,730 | |||
Options - Weighted Average Exercise Price | ||||
Granted, Weighted-Average Exercise Price | $ 66.02 | |||
Options - Additional Disclosures | ||||
Estimated weighted-average fair value per stock option (in dollars per share) | $ 7.26 | |||
WEC Energy Group | ||||
Options - Additional Disclosures | ||||
Cash received by WEC Energy Group from options exercised by WE employees | $ 7.7 | $ 12.1 | $ 29.2 |
Common Equity - Restricted Shar
Common Equity - Restricted Shares (Details) - Restricted stock - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restricted Stock Activity | ||||
Outstanding, shares, beginning of period | 15,283 | 16,261 | ||
Granted, shares | 8,001 | |||
Released, shares | (8,018) | |||
Transferred, shares | (379) | |||
Forfeited, shares | (582) | |||
Outstanding, shares, end of period | 15,283 | 16,261 | ||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Outstanding, weighted-average grant date fair value, beginning of period | $ 54.96 | $ 50.39 | ||
Granted, weighted-average grant date fair value | 58.10 | |||
Released, weighted-average grant date fair value | 48.78 | |||
Transferred, weighted-average grant date fair value | 57.77 | |||
Forfeited, weighted-average grant date fair value | 53.83 | |||
Outstanding, weighted-average grant date fair value, end of period | $ 54.96 | $ 50.39 | ||
Restricted Stock - Additional Disclosures | ||||
Intrinsic value of released restricted shares | $ 0.5 | $ 0.4 | $ 2.7 | |
Tax benefit from released restricted shares | 0.2 | $ 0.2 | $ 1.1 | |
Compensation cost not yet recognized | $ 1.2 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 8 months | |||
Subsequent event | ||||
Restricted Stock Activity | ||||
Granted, shares | 7,518 | |||
Restricted Stock Weighted-Average Grant Date Fair Value | ||||
Granted, weighted-average grant date fair value | $ 64.99 |
Common Equity - Performance Uni
Common Equity - Performance Units (Details) - Performance units - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Granted, shares | 34,765 | 35,700 | 187,450 | |
Transferred, shares | 573,499 | |||
Intrinsic value of settled performance units | $ 1.4 | $ 3.4 | $ 11.6 | |
Tax benefit from distribution of performance units | $ 0.4 | $ 0.5 | $ 4.2 | |
Outstanding, shares | 96,577 | |||
Liability recorded on balance sheet | $ 4.9 | |||
Compensation cost not yet recognized | $ 3.6 | |||
Weighted-average period over which unrecognized compensation cost is expected to be recognized | 1 year 5 months | |||
Subsequent event | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Granted, shares | 32,650 | |||
Intrinsic value of settled performance units | $ 1.8 | |||
Tax benefit from distribution of performance units | $ 0.4 |
Common Equity - Dividend Restri
Common Equity - Dividend Restrictions (Details) - USD ($) $ in Billions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Dividend Payment Restrictions [Line Items] | ||
Restricted retained earnings | $ 2.2 | |
$100 par value, Serial Preferred Stock, 3.60% Series | ||
Dividend Payment Restrictions [Line Items] | ||
Preferred Stock, dividend rate (as a percent) | 3.60% | 3.60% |
$100 par value, Serial Preferred Stock, 3.60% Series | Common stock equity to total capitalization is less than 25% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of common equity to total capitalization required to be maintained | 25.00% | |
$100 par value, Serial Preferred Stock, 3.60% Series | Common stock equity to total capitalization is less than 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of common equity to total capitalization required to be maintained | 20.00% | |
Maximum | $100 par value, Serial Preferred Stock, 3.60% Series | Common stock equity to total capitalization is less than 25% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of net income for which dividends can be declared | 75.00% | |
Maximum | $100 par value, Serial Preferred Stock, 3.60% Series | Common stock equity to total capitalization is less than 20% | ||
Dividend Payment Restrictions [Line Items] | ||
Percentage of net income for which dividends can be declared | 50.00% | |
Public Service Commission of Wisconsin | Minimum | ||
Dividend Payment Restrictions [Line Items] | ||
Common equity ratio required to be maintained (as a percent) | 51.00% |
Preferred Stock (Details)
Preferred Stock (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Class of Stock | ||
Total preferred stock value issued | $ 30.4 | $ 30.4 |
$100 par value, Six Per Cent. Preferred Stock | ||
Class of Stock | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percentage) | 6.00% | 6.00% |
Shares authorized | 45,000 | 45,000 |
Shares outstanding | 44,498 | 44,498 |
Total preferred stock value issued | $ 4.4 | $ 4.4 |
$100 par value, Serial Preferred Stock | ||
Class of Stock | ||
Par or stated value per share | $ 100 | $ 100 |
Shares authorized | 2,286,500 | 2,286,500 |
$100 par value, Serial Preferred Stock, 3.60% Series | ||
Class of Stock | ||
Par or stated value per share | $ 100 | $ 100 |
Dividend rate (as a percentage) | 3.60% | 3.60% |
Shares outstanding | 260,000 | 260,000 |
Redemption price per share | $ 101 | $ 101 |
Total preferred stock value issued | $ 26 | $ 26 |
$25 par value, Serial Preferred Stock | ||
Class of Stock | ||
Par or stated value per share | $ 25 | $ 25 |
Shares authorized | 5,000,000 | 5,000,000 |
Shares outstanding | 0 | 0 |
Total preferred stock value issued | $ 0 | $ 0 |
Short-Term Debt and Lines of 74
Short-Term Debt and Lines of Credit Outstanding (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Short-term Debt [Line Items] | ||
Maximum debt to capitalization ratio required to be maintained (as a percent) | 65.00% | |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Commercial paper outstanding | $ 210.9 | $ 159 |
Average interest rate on amounts outstanding | 1.81% | 0.87% |
Average amounts outstanding during year | $ 53.3 | |
Weighted average interest rate | 1.38% |
Short-Term Debt and Lines of 75
Short-Term Debt and Lines of Credit - Credit Facilities (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($)extension | Dec. 31, 2016USD ($) | |
Line of Credit Facility [Line Items] | ||
Letters of credit issued inside credit facilities | $ 1.2 | |
Available capacity under existing agreements | $ 287.9 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
Credit facility maturing October 2022 [Member] | ||
Line of Credit Facility [Line Items] | ||
Short-term credit capacity | $ 500 | |
Commercial Paper | ||
Line of Credit Facility [Line Items] | ||
Commercial paper outstanding | $ 210.9 | $ 159 |
Long-Term Debt and Capital Le76
Long-Term Debt and Capital Lease Obligations (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)Megawatt | Dec. 31, 2016USD ($) | Aug. 01, 2016USD ($) | |
Long-term debt outstanding maturities | |||
2,018 | $ 250 | ||
2,019 | 250 | ||
2,020 | 0 | ||
2,021 | 300 | ||
2,022 | 0 | ||
Thereafter | 1,885 | ||
Total | 2,685 | ||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Long-term pollution control bond | 80 | $ 67 | |
Total capital lease obligation | 2,866.3 | $ 2,785 | |
Present value of minimum lease payments | $ 2,866.3 | ||
Purchase power agreement | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Period of power purchase contract with an unaffiliated independent power producer | 25 years | ||
Power capacity from a gas-fired cogeneration facility under capital lease (MW) | Megawatt | 236 | ||
Minimum energy requirement in gas-fired cogeneration facility | 0 | ||
Power purchase contract expiration year | Dec. 31, 2022 | ||
Power purchase contract expected future renewable period | 10 years | ||
Increase In regulatory asset due to minimum lease payment | $ 78.5 | ||
Regulatory asset value at the end of life of contract | 0 | ||
Total capital lease obligation | $ 27 | ||
PWGS Units 1 and 2 | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Period of power purchase contract with an unaffiliated independent power producer | 25 years | ||
Power capacity from a gas-fired cogeneration facility under capital lease (MW) | Megawatt | 545 | ||
Regulatory asset value at the end of life of contract | $ 0 | ||
Number of PWGS natural gas-fired generation units | 2 | ||
Capital lease obligation at the end of life of contract | $ 0 | ||
Capital lease asset | 727.4 | 704.2 | |
Present value of minimum lease payments | 644.7 | ||
Power Purchase Commitment | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Capital lease asset | 140.3 | 140.3 | |
Present value of minimum lease payments | 27 | ||
PWGS 1 | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract | $ 129.1 | ||
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase | Dec. 31, 2021 | ||
PWGS 2 | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract | $ 124.4 | ||
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase | Dec. 31, 2023 | ||
ERGS Units 1 and 2 | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Period of power purchase contract with an unaffiliated independent power producer | 30 years | ||
Regulatory asset value at the end of life of contract | $ 0 | ||
Capital lease obligation at the end of life of contract | 0 | ||
Capital lease asset | 2,141.4 | $ 2,053.5 | |
Present value of minimum lease payments | 2,194.6 | ||
ER 1 | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract | $ 517.9 | ||
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase | May 31, 2028 | ||
ER 2 | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Estimated Total Increase In Regulatory Asset due to Minimum Lease Payment, Over Life of Contract | $ 425 | ||
Increase In Regulatory Asset Due To Minimum Lease Payment, End Date of Increase | Jan. 31, 2029 | ||
Combined PWGS Units 1 and 2 and ERGS | |||
Long-Term Debt and Capital Lease Obligations (Textuals) [Abstract] | |||
Total decrease in annual lease payments to related parties | $ 50 |
Long-Term Debt and Capital Le77
Long-Term Debt and Capital Lease Obligations - Capital Lease Payments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Total lease payment | $ 427.7 | $ 449.8 | $ 446.7 |
Power Purchase Commitment | |||
Debt Instrument [Line Items] | |||
Total lease payment | 7.2 | 37.6 | 36.2 |
PWGS Units 1 and 2 | |||
Debt Instrument [Line Items] | |||
Total lease payment | 85 | 82.4 | 103.8 |
ERGS Units 1 and 2 | |||
Debt Instrument [Line Items] | |||
Total lease payment | $ 335.5 | $ 329.8 | $ 306.7 |
Long-Term Debt and Capital Le78
Long-Term Debt and Capital Lease Obligations - Summary of Capital Leased Facilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Total leased facilities | $ 2,063.2 | $ 2,060.2 |
Power Purchase Commitment | ||
Debt Instrument [Line Items] | ||
Capital leased assets, gross | 140.3 | 140.3 |
Accumulated amortization | (115.2) | (109.5) |
Total leased facilities | 25.1 | 30.8 |
PWGS Units 1 and 2 | ||
Debt Instrument [Line Items] | ||
Capital leased assets, gross | 727.4 | 704.2 |
Accumulated amortization | (305.1) | (274.7) |
Total leased facilities | 422.3 | 429.5 |
ERGS Units 1 and 2 | ||
Debt Instrument [Line Items] | ||
Capital leased assets, gross | 2,141.4 | 2,053.5 |
Accumulated amortization | (525.6) | (453.6) |
Total leased facilities | $ 1,615.8 | $ 1,599.9 |
Long-Term Debt and Capital Le79
Long-Term Debt and Capital Lease Obligations - Future Minimum Lease Payments (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
2,018 | $ 398.7 | |
2,019 | 399.5 | |
2,020 | 400.4 | |
2,021 | 401.2 | |
2,022 | 391.5 | |
Thereafter | 5,886.8 | |
Total minimum lease payments | 7,878.1 | |
Less: Estimated executory costs | (33.1) | |
Net minimum lease payments | 7,845 | |
Less: Interest | (4,978.7) | |
Present value of minimum lease payments | 2,866.3 | |
Less: Due currently | (42.5) | $ (28.5) |
Long-term obligations under capital lease | 2,823.8 | $ 2,756.5 |
Power Purchase Commitment | ||
Debt Instrument [Line Items] | ||
2,018 | 14.7 | |
2,019 | 15.5 | |
2,020 | 16.4 | |
2,021 | 17.2 | |
2,022 | 7.6 | |
Thereafter | 0 | |
Total minimum lease payments | 71.4 | |
Less: Estimated executory costs | (33.1) | |
Net minimum lease payments | 38.3 | |
Less: Interest | (11.3) | |
Present value of minimum lease payments | 27 | |
Less: Due currently | (3.7) | |
Long-term obligations under capital lease | 23.3 | |
PWGS Units 1 and 2 | ||
Debt Instrument [Line Items] | ||
2,018 | 96.3 | |
2,019 | 96.3 | |
2,020 | 96.3 | |
2,021 | 96.3 | |
2,022 | 96.3 | |
Thereafter | 857.3 | |
Total minimum lease payments | 1,338.8 | |
Less: Estimated executory costs | 0 | |
Net minimum lease payments | 1,338.8 | |
Less: Interest | (694.1) | |
Present value of minimum lease payments | 644.7 | |
Less: Due currently | (19.4) | |
Long-term obligations under capital lease | 625.3 | |
ERGS Units 1 and 2 | ||
Debt Instrument [Line Items] | ||
2,018 | 287.7 | |
2,019 | 287.7 | |
2,020 | 287.7 | |
2,021 | 287.7 | |
2,022 | 287.6 | |
Thereafter | 5,029.5 | |
Total minimum lease payments | 6,467.9 | |
Less: Estimated executory costs | 0 | |
Net minimum lease payments | 6,467.9 | |
Less: Interest | (4,273.3) | |
Present value of minimum lease payments | 2,194.6 | |
Less: Due currently | (19.4) | |
Long-term obligations under capital lease | $ 2,175.2 |
Income Taxes - Summary of incom
Income Taxes - Summary of income tax expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Current tax expense | $ 81.5 | $ 4.8 | $ 33.1 |
Deferred income taxes, net | 110.6 | 207.3 | 180 |
Investment tax credit, net | (0.9) | (1.1) | (1.1) |
Total income tax expense | $ 191.2 | $ 211 | $ 212 |
Income Taxes - Statutory rate r
Income Taxes - Statutory rate reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | |||
Expected tax at statutory federal tax rates | $ 184.4 | $ 201.4 | $ 205.7 |
State income taxes net of federal tax benefit | 27.9 | 31.8 | 31 |
Production tax credits | (17.6) | (16.5) | (17.8) |
Domestic production activities deduction | (7.8) | (7.8) | (7.8) |
AFUDC - Equity | (1.1) | (1.5) | (2) |
Investment tax credit restored | (0.9) | (1.1) | (1.1) |
Other, net | 6.3 | 4.7 | 4 |
Total income tax expense | $ 191.2 | $ 211 | $ 212 |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | |||
Expected tax at statutory federal tax rates | 35.00% | 35.00% | 35.00% |
State income taxes net of federal tax benefit | 5.30% | 5.50% | 5.30% |
Production tax credits | (3.30%) | (2.80%) | (3.00%) |
Domestic production activities deduction | (1.50%) | (1.40%) | (1.30%) |
AFUDC - Equity | (0.20%) | (0.30%) | (0.30%) |
Investment tax credit restored | (0.20%) | (0.20%) | (0.20%) |
Other, net | 1.10% | 0.80% | 0.50% |
Total income tax expense | 36.20% | 36.60% | 36.00% |
Income Taxes - Components of de
Income Taxes - Components of deferred tax assets and liabilities (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Income Taxes | ||||
Expected tax at statutory federal tax rates | 35.00% | 35.00% | 35.00% | |
Estimated tax benefit related to the remeasurement of deferred taxes from tax legislation | $ 1,065 | |||
Non-current | ||||
Tax gross up - regulatory items | 240.1 | $ 0 | ||
Future tax benefits | 133.1 | 143.7 | ||
Deferred revenues | 128.8 | 207.2 | ||
Employee benefits and compensation | 50.2 | 77.6 | ||
Construction advances | 15 | 20 | ||
Uncollectible account expense | 12.5 | 16.1 | ||
Emission allowances | 0.1 | 0.2 | ||
Other | 54.8 | 70.9 | ||
Total deferred tax assets | 634.6 | 535.7 | ||
Non-current | ||||
Property-related | 1,487 | 2,257.3 | ||
Employee benefits and compensation | 117.4 | 179.3 | ||
Deferred transmission costs | 60.1 | 93.1 | ||
Prepaid tax, insurance, and other | 33.8 | 50.2 | ||
Investment in transmission affiliate | 0 | 195.1 | ||
Other | 91.8 | 94 | ||
Total deferred tax liabilities | 1,790.1 | 2,869 | ||
Deferred tax liability, net | $ 1,155.5 | $ 2,333.3 | ||
Federal tax rate change due to tax legislation | ||||
Income Taxes | ||||
Expected tax at statutory federal tax rates | 21.00% |
Income Taxes - Components of ne
Income Taxes - Components of net deferred tax assets (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Domestic tax authority | ||
Income Taxes | ||
Charitable contribution | $ 4 | |
Tax credit carryforward | 125.6 | $ 107.2 |
Net operating loss carryforward | 82.8 | |
Charitable contribution carryforwards, deferred tax asset | 0.8 | |
Tax credit carryforward, deferred tax asset | 125.6 | 107.2 |
Operating loss carryforward, deferred tax asset | 29 | |
State and local jurisdiction | ||
Income Taxes | ||
Charitable contribution | 31.9 | |
Net operating loss carryforward | 74.7 | 149.9 |
Charitable contribution carryforwards, deferred tax asset | 2 | |
State net operating loss carryforwards, deferred tax asset | $ 4.7 | $ 7.5 |
Income Taxes - Unrecognized Tax
Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | |||
Balance, January 1 | $ 5.1 | $ 6.1 | |
Reductions for tax positions of prior years | (5.1) | (1) | |
Balance, December 31 | 0 | 5.1 | $ 6.1 |
Income Taxes | |||
Deferred tax assets, uncertainty in income taxes | 0 | 5.1 | |
Net amount of unrecognized tax benefits having impact on the effective tax rate | 0 | 0 | |
Interest income in the consolidated income statements | 0.7 | 0.1 | |
Interest expense in the consolidated income statements | 0.2 | ||
Accrued penalties in the consolidated income statements | 0 | 0 | $ 0 |
Accrued interest on the consolidated balance sheets | 0 | 0.7 | |
Accrued penalties on the consolidated balance sheets | $ 0 | $ 0 |
Fair Value Measurements - Asset
Fair Value Measurements - Assets and liabilities measured on a recurring basis (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Assets | ||
Derivative asset | $ 4.6 | $ 12 |
Liabilities | ||
Derivative liability | 2.4 | 0.7 |
Fair value measurements on a recurring basis | ||
Assets | ||
Derivative asset | 4.6 | 12 |
Liabilities | ||
Derivative liability | 2.4 | 0.7 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative asset | 1.4 | 6.2 |
Liabilities | ||
Derivative liability | 2 | 0.2 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative asset | 0.8 | 2.7 |
Liabilities | ||
Derivative liability | 0.4 | 0.5 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative asset | 2.4 | 3.1 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | ||
Assets | ||
Derivative asset | 0.6 | 6.8 |
Liabilities | ||
Derivative liability | 2.1 | 0.1 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative asset | 0.5 | 6 |
Liabilities | ||
Derivative liability | 2 | 0.1 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative asset | 0.1 | 0.8 |
Liabilities | ||
Derivative liability | 0.1 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Petroleum products contracts | ||
Assets | ||
Derivative asset | 0.9 | 0.2 |
Liabilities | ||
Derivative liability | 0.1 | |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 1 | ||
Assets | ||
Derivative asset | 0.9 | 0.2 |
Liabilities | ||
Derivative liability | 0.1 | |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 2 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | |
Fair value measurements on a recurring basis | Petroleum products contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | |
Fair value measurements on a recurring basis | FTRs | ||
Assets | ||
Derivative asset | 2.4 | 3.1 |
Fair value measurements on a recurring basis | FTRs | Level 1 | ||
Assets | ||
Derivative asset | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | Level 2 | ||
Assets | ||
Derivative asset | 0 | 0 |
Fair value measurements on a recurring basis | FTRs | Level 3 | ||
Assets | ||
Derivative asset | 2.4 | 3.1 |
Fair value measurements on a recurring basis | Coal contracts | ||
Assets | ||
Derivative asset | 0.7 | 1.9 |
Liabilities | ||
Derivative liability | 0.3 | 0.5 |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | 0 | 0 |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Assets | ||
Derivative asset | 0.7 | 1.9 |
Liabilities | ||
Derivative liability | 0.3 | 0.5 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Assets | ||
Derivative asset | 0 | 0 |
Liabilities | ||
Derivative liability | $ 0 | $ 0 |
Fair Value Measurements - Level
Fair Value Measurements - Level 3 Reconciliation (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Level 3 Rollforward [Abstract] | |||
Balance at the beginning of the period | $ 3.1 | $ 1.6 | $ 7 |
Purchases | 6.9 | 8.1 | 3.9 |
Settlements | (7.6) | (6.6) | (9.3) |
Balance at the end of the period | $ 2.4 | $ 3.1 | $ 1.6 |
Fair Value Measurements, Financ
Fair Value Measurements, Financial Instruments not recorded at Fair Value (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Carrying value and estimated fair value of financial instruments | ||
Preferred stock | $ 30.4 | $ 30.4 |
Long-term debt including current portion | 2,412.3 | 2,661.1 |
Carrying Amount | ||
Carrying value and estimated fair value of financial instruments | ||
Preferred stock | 30.4 | 30.4 |
Long-term debt including current portion | 2,662.3 | 2,661.1 |
Fair Value | ||
Carrying value and estimated fair value of financial instruments | ||
Preferred stock | 30.5 | 28.8 |
Long-term debt including current portion | $ 2,976.3 | $ 2,923.4 |
Derivative Instruments - Deriva
Derivative Instruments - Derivative Assets and Derivative Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative Asset | ||
Other current derivative assets | $ 4.5 | $ 11.1 |
Other long-term derivative assets | 0.1 | 0.9 |
Derivative asset | 4.6 | 12 |
Derivative Liability | ||
Other current derivative liabilities | 2 | 0.7 |
Other long-term derivative liabilities | 0.4 | 0 |
Derivative liability | 2.4 | 0.7 |
Natural gas contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.6 | 6.3 |
Other long-term derivative assets | 0 | 0.5 |
Derivative Liability | ||
Other current derivative liabilities | 1.9 | 0.1 |
Other long-term derivative liabilities | 0.2 | 0 |
Petroleum products contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.9 | 0.2 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0.1 |
FTRs | ||
Derivative Asset | ||
Other current derivative assets | 2.4 | 3.1 |
Derivative Liability | ||
Other current derivative liabilities | 0 | 0 |
Coal contracts | ||
Derivative Asset | ||
Other current derivative assets | 0.6 | 1.5 |
Other long-term derivative assets | 0.1 | 0.4 |
Derivative Liability | ||
Other current derivative liabilities | 0.1 | 0.5 |
Other long-term derivative liabilities | $ 0.2 | $ 0 |
Derivative Instruments - Gains
Derivative Instruments - Gains (Losses) and Notional Volumes (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)MWhMMBTUgal | Dec. 31, 2016USD ($)MWhMMBTUgal | Dec. 31, 2015USD ($)MWhMMBTUgal | |
Realized gain (loss) on derivative | |||
Gains (losses) | $ 5.2 | $ (7.6) | $ (9.6) |
Natural gas contracts | |||
Realized gain (loss) on derivative | |||
Gains (losses) | $ (1) | $ (12.3) | $ (12.6) |
Notional sales disclosures | |||
Notional sales volumes (Dth or MWh) | MMBTU | 26.9 | 35.3 | 24 |
Petroleum products contracts | |||
Realized gain (loss) on derivative | |||
Gains (losses) | $ (1.4) | $ (2.6) | $ (0.2) |
Notional sales disclosures | |||
Notional sales volumes (gallons) | gal | 16.7 | 10.3 | 4 |
FTRs | |||
Realized gain (loss) on derivative | |||
Gains (losses) | $ 7.6 | $ 7.3 | $ 3.2 |
Notional sales disclosures | |||
Notional sales volumes (Dth or MWh) | MWh | 27.1 | 25.3 | 22.8 |
Derivative Instruments - Offset
Derivative Instruments - Offsetting Table (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Cash collateral | ||
Cash collateral in margin account | $ 4.9 | |
Cash collateral received | $ 3.4 | |
Offsetting Derivative Assets | ||
Gross amount recognized on balance sheet | 4.6 | 12 |
Gross amount not offset on the balance sheet | (1.3) | (3.6) |
Net amount | 3.3 | 8.4 |
Cash collateral received | 3.4 | |
Offsetting Derivative Liabilities | ||
Gross amount recognized on the balance sheet | 2.4 | 0.7 |
Gross amount not offset on the balance sheet | (2) | (0.2) |
Net amount | 0.4 | $ 0.5 |
Cash collateral posted | $ 0.7 |
Employee Benefits - Change in B
Employee Benefits - Change in Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Contribution Benefit Plans | |||
Company contribution to 401(k) savings plan for management employees hired after December 31, 2014 (percentage) | 6.00% | ||
Pension Costs | |||
Change in benefit obligation | |||
Obligation at January 1 | $ 1,177 | $ 1,290.6 | |
Service cost | 12.2 | 10.5 | $ 14.7 |
Interest cost | 47 | 49.7 | 52.9 |
Participant contributions | 0 | 0 | |
Plan amendments | 0 | (2.6) | |
Net transfer to/from affiliates | (13.4) | (121.1) | |
Actuarial loss (gain) | 53.1 | 25.3 | |
Benefit payments | (82) | (75.4) | |
Obligation at December 31 | 1,193.9 | 1,177 | 1,290.6 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 1,102.8 | 1,179.3 | |
Actual return on plan assets | 121.9 | 73 | |
Employer contributions | 5.1 | 5.3 | |
Participant contributions | 0 | 0 | |
Net transfer to/from affiliates | (13.7) | (79.4) | |
Benefit payments | (82) | (75.4) | |
Ending balance at December 31 | 1,134.1 | 1,102.8 | 1,179.3 |
Funded status at December 31 | (59.8) | (74.2) | |
OPEB Costs | |||
Change in benefit obligation | |||
Obligation at January 1 | 298.5 | 313.8 | |
Service cost | 7 | 7.3 | 9 |
Interest cost | 12.1 | 13.2 | 13.4 |
Participant contributions | 5.7 | 8.8 | |
Plan amendments | (6.8) | 0 | |
Net transfer to/from affiliates | (3.3) | (17) | |
Actuarial loss (gain) | 5.1 | (9.7) | |
Benefit payments | (16.5) | (19) | |
Federal subsidy on benefits paid | 1.7 | 1.1 | |
Obligation at December 31 | 303.5 | 298.5 | 313.8 |
Change in fair value of plan assets | |||
Beginning balance at January 1 | 205.1 | 216.1 | |
Actual return on plan assets | 25.9 | 13.5 | |
Employer contributions | 3.2 | 2.7 | |
Participant contributions | 5.7 | 8.8 | |
Net transfer to/from affiliates | (3.3) | (17) | |
Benefit payments | (16.5) | (19) | |
Ending balance at December 31 | 220.1 | 205.1 | $ 216.1 |
Funded status at December 31 | $ (83.4) | $ (93.4) |
Employee Benefits - Amounts Rec
Employee Benefits - Amounts Recognized on the Balance Sheets (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB obligations | $ (143.2) | $ (167.6) |
Pension Costs | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB obligations | (59.8) | (74.2) |
OPEB Costs | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension and OPEB obligations | $ (83.4) | $ (93.4) |
Employee Benefits - Accumulated
Employee Benefits - Accumulated Benefit Obligations (Details) - Pension Plan - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plan Disclosure [Line Items] | ||
Accumulated benefit obligation | $ 1,192.4 | $ 1,175.8 |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | ||
Projected benefit obligation | 1,193.9 | 1,177 |
Accumulated benefit obligation | 1,192.4 | 1,175.8 |
Fair value of plan assets | $ 1,134.1 | $ 1,102.8 |
Employee Benefits - Amounts Not
Employee Benefits - Amounts Not Yet Recognized in Net Periodic Benefit Cost (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Pension Costs | ||
Net regulatory assets | ||
Net actuarial loss (gain) | $ 485.4 | $ 518.5 |
Prior service costs (credits) | (1) | 0.2 |
Total | 484.4 | 518.7 |
Estimated amounts that will be amortized into net periodic benefit cost next year | ||
Net actuarial loss | 37.5 | |
Prior service costs (credits) | 0.9 | |
Total 2018 – estimated amortization | 38.4 | |
OPEB Costs | ||
Net regulatory assets | ||
Net actuarial loss (gain) | (1.6) | 4.6 |
Prior service costs (credits) | (8.4) | (3) |
Total | (10) | $ 1.6 |
Estimated amounts that will be amortized into net periodic benefit cost next year | ||
Net actuarial loss | 0 | |
Prior service costs (credits) | (2.3) | |
Total 2018 – estimated amortization | $ (2.3) |
Employee Benefits - Net Periodi
Employee Benefits - Net Periodic Benefit Cost (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Costs | |||
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | |||
Service cost | $ 12.2 | $ 10.5 | $ 14.7 |
Interest cost | 47 | 49.7 | 52.9 |
Expected return on plan assets | (76.6) | (77.7) | (83.6) |
Plan settlement | 4.1 | 0 | 0 |
Amortization of prior service cost (credit) | 1.1 | 1.6 | 2 |
Amortization of net actuarial loss | 35.4 | 32.4 | 35.6 |
Net periodic benefit cost | 23.2 | 16.5 | 21.6 |
OPEB Costs | |||
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | |||
Service cost | 7 | 7.3 | 9 |
Interest cost | 12.1 | 13.2 | 13.4 |
Expected return on plan assets | (14.7) | (14) | (16) |
Plan settlement | 0 | 0 | 0 |
Amortization of prior service cost (credit) | (1.4) | (1.1) | (1.1) |
Amortization of net actuarial loss | 0 | 1 | 1 |
Net periodic benefit cost | $ 3 | $ 6.4 | $ 6.3 |
Employee Benefits - Assumptions
Employee Benefits - Assumptions (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 3.65% | 4.15% | ||
Rate of compensation increase | 3.20% | 3.20% | ||
Pension Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 4.12% | 4.45% | 4.15% | |
Expected return on plan assets | 7.00% | 7.00% | 7.00% | |
Rate of compensation increase | 3.20% | 3.50% | 4.00% | |
Pension Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 7.00% | |||
OPEB Plan | Benefit obligation assumptions | ||||
Weighted average assumptions - benefit obligations | ||||
Discount rate | 3.65% | 4.20% | ||
OPEB Plan | Benefit obligation assumptions | Pre 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.50% | 7.00% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2,024 | 2,021 | ||
OPEB Plan | Benefit obligation assumptions | Post 65 | ||||
Medical cost trend rates | ||||
Assumed medical cost trend rate | 6.18% | 7.00% | ||
Ultimate trend rate | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2,028 | 2,021 | ||
OPEB Plan | Net periodic benefit cost assumptions | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Discount rate | 4.10% | 4.45% | 4.20% | |
Expected return on plan assets | 7.25% | 7.25% | 7.25% | |
Medical cost trend rates | ||||
Assumed medical cost trend rate | 7.00% | 7.50% | 7.50% | |
Ultimate trend rate | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2,021 | 2,021 | 2,021 | |
Effects of a one-percentage-point change in assumed health care cost trend rates | ||||
Effect of one-percentage-point increase on total of service and interest cost components of net periodic postretirement health care benefit cost | $ 2.9 | |||
Effect of one-percentage-point increase on the health care component of the accumulated postretirement benefit obligation | 29.3 | |||
Effect of one-percentage-point decrease on total of service and interest cost components of net periodic postretirement health care benefit cost | (2.3) | |||
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation | $ (24.2) | |||
OPEB Plan | Net periodic benefit cost assumptions | Subsequent event | ||||
Weighted average assumptions - net periodic benefit cost | ||||
Expected return on plan assets | 7.25% |
Employee Benefits - Target Asse
Employee Benefits - Target Asset Allocations (Details) | Dec. 31, 2017 |
Pension Plan | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 35.00% |
Pension Plan | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 55.00% |
Pension Plan | Private equity and real estate | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 10.00% |
OPEB Plan | Equity securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 60.00% |
OPEB Plan | Fixed income securities | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations (as a percent) | 40.00% |
Employee Benefits - Plan Assets
Employee Benefits - Plan Assets (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 1,134.1 | $ 1,102.8 | $ 1,179.3 |
Pension Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 892.6 | 621.5 | |
Pension Plan | Level 1, 2, and 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 6.6 | 20.3 | |
Pension Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 109.5 | 85.6 | |
Pension Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 114.4 | 17.7 | |
Pension Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 543.7 | 455.3 | |
Pension Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 42.5 | 31.6 | |
Pension Plan | Level 1, 2, and 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 75.9 | 11 | |
Pension Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 309.4 | 104.3 | |
Pension Plan | Level 1 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 1.1 | |
Pension Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 109.4 | 85.5 | |
Pension Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 114.4 | 17.7 | |
Pension Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 75.9 | 0 | |
Pension Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 9.7 | 0 | |
Pension Plan | Level 1 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 527.9 | 506.2 | |
Pension Plan | Level 2 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 6.6 | 19.2 | |
Pension Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.1 | 0.1 | |
Pension Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 467.8 | 455.3 | |
Pension Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 32.8 | 31.6 | |
Pension Plan | Level 2 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 20.6 | 0 | |
Pension Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 55.3 | 11 | |
Pension Plan | Level 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
Pension Plan | Level 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 55.3 | 11 | |
Pension Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 241.5 | 481.3 | |
OPEB Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 220.1 | 205.1 | $ 216.1 |
OPEB Plan | Level 1, 2, and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 144.3 | 67.1 | |
OPEB Plan | Level 1, 2, and 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 2.6 | 7.8 | |
OPEB Plan | Level 1, 2, and 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 29 | 10.5 | |
OPEB Plan | Level 1, 2, and 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 32.2 | 1.3 | |
OPEB Plan | Level 1, 2, and 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 70.7 | 44 | |
OPEB Plan | Level 1, 2, and 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 4.6 | 2.8 | |
OPEB Plan | Level 1, 2, and 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 5.2 | 0.7 | |
OPEB Plan | Level 1 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 89.4 | 18.3 | |
OPEB Plan | Level 1 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 2.1 | 6.5 | |
OPEB Plan | Level 1 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 29 | 10.5 | |
OPEB Plan | Level 1 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 32.2 | 1.3 | |
OPEB Plan | Level 1 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 24.4 | 0 | |
OPEB Plan | Level 1 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 1.7 | 0 | |
OPEB Plan | Level 1 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 51.1 | 48.1 | |
OPEB Plan | Level 2 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0.5 | 1.3 | |
OPEB Plan | Level 2 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 2 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 46.3 | 44 | |
OPEB Plan | Level 2 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 2.9 | 2.8 | |
OPEB Plan | Level 2 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 1.4 | 0 | |
OPEB Plan | Level 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 3.8 | 0.7 | |
OPEB Plan | Level 3 | Cash and cash equivalents | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | United States equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International equity | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | United States bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | International bonds | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 0 | 0 | |
OPEB Plan | Level 3 | Private equity and real estate | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | 3.8 | 0.7 | |
OPEB Plan | Investments measured at net asset value per share | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair Value of Plan Assets | $ 75.8 | $ 138 |
Employee Benefits - Changes in
Employee Benefits - Changes in the Fair Value of Plan Assets Categorized as Level 3 (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Pension Plan | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | $ 1,102.8 | $ 1,179.3 |
Realized and unrealized gains | 121.9 | 73 |
Ending balance at December 31 | 1,134.1 | 1,102.8 |
Pension Plan | Level 3 | Private equity and real estate | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 11 | 4.5 |
Realized and unrealized gains | 1.9 | |
Purchases | 22.3 | 6.5 |
Transfers into level 3 | 20.1 | |
Ending balance at December 31 | 55.3 | 11 |
OPEB Plan | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 205.1 | 216.1 |
Realized and unrealized gains | 25.9 | 13.5 |
Ending balance at December 31 | 220.1 | 205.1 |
OPEB Plan | Level 3 | Private equity and real estate | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0.7 | 0.3 |
Realized and unrealized gains | 0.2 | |
Purchases | 1.5 | 0.4 |
Transfers into level 3 | 1.4 | |
Ending balance at December 31 | $ 3.8 | $ 0.7 |
Employee Benefits - Cash Flows
Employee Benefits - Cash Flows (Details) $ in Millions | Dec. 31, 2017USD ($) |
Pension Costs | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | $ 3.9 |
2,018 | 92.4 |
2,019 | 90.1 |
2,020 | 89.2 |
2,021 | 86 |
2,022 | 82.3 |
2023 through 2027 | 368.2 |
OPEB Costs | |
Defined Benefit Plan Disclosure [Line Items] | |
Expected contributions to the plans during the next year | 0.1 |
2,018 | 13.5 |
2,019 | 14.2 |
2,020 | 14.9 |
2,021 | 15.7 |
2,022 | 16.2 |
2023 through 2027 | $ 85.5 |
Employee Benefits - Defined Con
Employee Benefits - Defined Contribution Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Contribution Benefit Plans | |||
Total costs incurred for defined contribution benefit plans | $ 11.7 | $ 10.4 | $ 13 |
Investment in American Trans102
Investment in American Transmission Company - Changes to Investment in ATC (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Changes to investment in ATC | |||
Earnings from equity method investment | $ 0 | $ 55.5 | $ 47.8 |
Capital contributions | $ 0 | $ 16.1 | 4.6 |
ATC | |||
Investment in ATC | |||
Ownership interest in ATC (as a percent) | 23.00% | 23.00% | |
Changes to investment in ATC | |||
Investment in ATC, balance at beginning of period | $ 402 | $ 382.2 | 372.9 |
Equity Method Investment Transfer | 402 | 0 | 0 |
Earnings from equity method investment | 0 | 55.5 | 47.8 |
Capital contributions | 0 | 16.1 | 4.6 |
Distributions | 0 | 51.7 | 42.9 |
Other | 0 | 0.1 | 0.2 |
Investment in ATC, balance at end of period | $ 0 | 402 | $ 382.2 |
Dividends not received | |||
Dividends receivable | $ 13.4 |
Segment Information (Details)
Segment Information (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Jun. 30, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2017USD ($)areasegment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Segment information | |||||||||||
Number of reportable segments | segment | 2 | ||||||||||
Number of areas serviced by our natural gas utility segment | area | 3 | ||||||||||
Operating revenues | $ 940.5 | $ 943.8 | $ 855.4 | $ 972 | $ 916.3 | $ 1,023.8 | $ 877.2 | $ 975.5 | $ 3,711.7 | $ 3,792.8 | $ 3,854.1 |
Other operation and maintenance | 1,358.5 | 1,430.2 | 1,384.9 | ||||||||
Depreciation and amortization | 331.6 | 325.4 | 304 | ||||||||
Operating income | 134.3 | $ 163.4 | $ 142.8 | $ 185.1 | 104.7 | $ 196.4 | $ 146.9 | $ 181.5 | 625.6 | 629.5 | 648.9 |
Equity in earnings of transmission affiliate | 0 | 55.5 | 47.8 | ||||||||
Interest expense | 117.3 | 117.6 | 119 | ||||||||
Capital expenditures | 596.1 | 469.5 | 519.2 | ||||||||
Assets | 13,121.6 | 13,371.5 | 13,121.6 | 13,371.5 | 13,139.6 | ||||||
Utility | |||||||||||
Segment information | |||||||||||
Operating revenues | 3,711.7 | 3,792.8 | 3,854.1 | ||||||||
Other operation and maintenance | 1,358.5 | 1,430.2 | 1,384.9 | ||||||||
Depreciation and amortization | 331.6 | 325.4 | 304 | ||||||||
Operating income | 625.6 | 629.5 | 648.9 | ||||||||
Equity in earnings of transmission affiliate | 0 | 0 | |||||||||
Interest expense | 117 | 116.6 | 117.7 | ||||||||
Capital expenditures | 596.1 | 468.9 | 518.8 | ||||||||
Assets | 13,121.6 | 12,945.1 | 13,121.6 | 12,945.1 | 12,727.6 | ||||||
Other | |||||||||||
Segment information | |||||||||||
Operating revenues | 0 | 0 | 0 | ||||||||
Other operation and maintenance | 0 | 0 | 0 | ||||||||
Depreciation and amortization | 0 | 0 | 0 | ||||||||
Operating income | 0 | 0 | 0 | ||||||||
Equity in earnings of transmission affiliate | 55.5 | 47.8 | |||||||||
Interest expense | 0.3 | 1 | 1.3 | ||||||||
Capital expenditures | 0 | 0.6 | 0.4 | ||||||||
Assets | $ 0 | $ 426.4 | 0 | 426.4 | 412 | ||||||
ATC | |||||||||||
Segment information | |||||||||||
Equity in earnings of transmission affiliate | $ 0 | $ 55.5 | $ 47.8 | ||||||||
Equity Method Investment, Ownership Percentage | 23.00% | 23.00% | 23.00% | 23.00% |
Variable Interest Entities (Det
Variable Interest Entities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)MW | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
ATC | |||
Variable interest entities | |||
Ownership interest in ATC (as a percent) | 23.00% | ||
Purchase power agreement | |||
Variable interest entities | |||
Firm capacity from purchase 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) | 4 years | ||
Residual guarantee associated with purchased power agreement | $ 0 | ||
Required payments over remaining term of purchased power agreement | 71.4 | ||
Total capacity and lease payments under purchased power agreement | $ 18 | $ 54.2 | $ 53.6 |
Commitments and Contingencies -
Commitments and Contingencies - Unconditional Purchase Obligations (Details) $ in Millions | Dec. 31, 2017USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 9,954.9 |
2,018 | 647 |
2,019 | 570.7 |
2,020 | 561.3 |
2,021 | 542.3 |
2,022 | 562.8 |
Later Years | 7,070.8 |
Nuclear | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 9,184.5 |
2,018 | 420.1 |
2,019 | 445.4 |
2,020 | 475.1 |
2,021 | 501.1 |
2,022 | 531.2 |
Later Years | 6,811.6 |
Coal supply and transportation | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 215 |
2,018 | 132.2 |
2,019 | 53.9 |
2,020 | 28.9 |
2,021 | 0 |
2,022 | 0 |
Later Years | 0 |
Purchased power | Electric | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 93.1 |
2,018 | 29.1 |
2,019 | 16.6 |
2,020 | 13.7 |
2,021 | 10.9 |
2,022 | 9 |
Later Years | 13.8 |
Natural gas utility supply and transportation | Natural gas | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 462.3 |
2,018 | 65.6 |
2,019 | 54.8 |
2,020 | 43.6 |
2,021 | 30.3 |
2,022 | 22.6 |
Later Years | $ 245.4 |
Commitments and Contingencie106
Commitments and Contingencies - Operating Leases (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Leases [Abstract] | |||
Rental expense attributable to operating leases | $ 4 | $ 5 | $ 6.7 |
Future minimum payments under noncancelable operating leases | |||
2,018 | 3.5 | ||
2,019 | 3.4 | ||
2,020 | 1.9 | ||
2,021 | 1.4 | ||
2,022 | 1.5 | ||
Later years | 23 | ||
Total | $ 34.7 |
Commitments and Contingencie107
Commitments and Contingencies - Environmental Matters (Details) T in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Oct. 31, 2014compliance_option | Dec. 31, 2017USD ($)TMW | Dec. 31, 2016USD ($)T | Dec. 31, 2015 | Sep. 30, 2016Case | |
Climate Change | Electric | |||||
Air Quality | |||||
Number of legal cases heard by a court | Case | 1 | ||||
Percentage of nationwide greenhouse gas emissions reduction | 32.00% | ||||
Interim goal for greenhouse gas emissions reduction (fraction) | 0.667 | ||||
Company goal for percentage of carbon dioxide emissions reduction | 40.00% | ||||
Capacity of coal generation expected to be retired by 2020 | MW | 1,547 | ||||
Carbon dioxide emissions | T | 23.5 | 23.9 | |||
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 | 3.8 | 3.7 | |||
Clean Water Act Cooling Water Intake Structure Rule | Electric | |||||
Water Quality | |||||
Number of compliance options available to meet standard | compliance_option | 7 | ||||
Steam Electric Effluent Guidelines | Electric | |||||
Water Quality | |||||
Renewal period for facility permits | 5 years | ||||
Expected cost to achieve required emissions reduction | $ 50 | ||||
Manufactured Gas Plant Remediation | Natural gas | |||||
Manufactured Gas Plant Remediation | |||||
Regulatory assets recorded for remediation of manufactured gas plant sites | 30.4 | $ 29.9 | |||
Reserves recorded for remediation of manufactured gas plant sites | $ 18.5 | $ 19 | |||
Renewables, Efficiency, and Conservation | Electric | Wisconsin | |||||
Renewables, Efficiency, and Conservation | |||||
State renewable portfolio requirement for years 2016 through 2018, as a percent | 10.00% | ||||
Renewable energy percent | 8.27% | ||||
Percent of annual operating revenues used to fund renewable program | 1.20% | ||||
Renewables, Efficiency, and Conservation | Electric | Michigan | |||||
Renewables, Efficiency, and Conservation | |||||
State renewable portfolio requirement for years 2016 through 2018, as a percent | 10.00% | ||||
State renewable portfolio requirement for years 2019 through 2020, as a percent | 12.50% | ||||
State renewable portfolio requirement for 2021, as a percent | 15.00% | ||||
Renewables, Efficiency, and Conservation | Electric | Michigan | Maximum | |||||
Renewables, Efficiency, and Conservation | |||||
Energy optimization target, as a percent | 1.00% |
Supplemental Cash Flow Infor108
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental cash flow information | |||
Cash (paid) for interest, net of amount capitalized | $ (115.1) | $ (116.2) | $ (116.2) |
Cash (paid) received for income taxes, net | (71.7) | 100.2 | (58.5) |
Accounts payable related to construction costs | 13.2 | 9.1 | 11.7 |
ATC | |||
Supplemental cash flow information | |||
Transfer of investment in ATC to another subsidiary of WEC Energy Group | 415.4 | 0 | 0 |
Distributions receivable | 13.4 | ||
UMERC | |||
Supplemental cash flow information | |||
Transfer of net assets to UMERC | 61.1 | 0 | 0 |
Equity settlement of Bostco intercompany note receivable | |||
Supplemental cash flow information | |||
Equity settlement of a short-term note receivable between Bostco and our parent company | $ 4.8 | $ 0 | $ 0 |
Regulatory Environment (Details
Regulatory Environment (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||||
Dec. 31, 2017USD ($) | Oct. 31, 2017MW | Sep. 30, 2017 | Aug. 31, 2016MW | Dec. 31, 2014USD ($) | Dec. 31, 2017USD ($) | |
UMERC | ||||||
Regulatory environment | ||||||
Term of electric power purchase agreement (in years) | 20 years | |||||
Capacity of natural gas-fired generation facility (in megawatts) | MW | 180 | 180 | ||||
Public Service Commission of Wisconsin (PSCW) | 2018 and 2019 Rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.20% | |||||
Percentage of first 50 basis points of additional utility earnings shared with customers | 50.00% | |||||
Return on equity in excess of authorized amount (as a percent) | 0.50% | |||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ 26.6 | |||||
Approved rate increase (decrease), percentage | 0.90% | |||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ 0 | |||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | 0 | |||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Steam rates | Milwaukee County steam customers | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ 0 | |||||
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% | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | ||||||
Regulatory environment | ||||||
Refund related to prior fuel costs and the remainder of 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% | |||||
SSR revenues | $ 90.7 | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | Non-fuel costs | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ 2.7 | |||||
Approved rate increase (decrease), percentage | 0.10% | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | Fuel costs | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ (13.9) | |||||
Approved rate increase (decrease), percentage | (0.50%) | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ (10.7) | |||||
Approved rate increase (decrease), percentage | (2.40%) | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Steam rates | Downtown Milwaukee (Valley) steam customers | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ 0.5 | |||||
Approved rate increase (decrease), percentage | 2.00% | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Steam rates | Milwaukee County steam customers | ||||||
Regulatory environment | ||||||
Approved rate increase (decrease) | $ 1.2 | |||||
Approved rate increase (decrease), percentage | 7.30% | |||||
Utility operations | ||||||
Regulatory environment | ||||||
Change in deferred income taxes from tax legislation | $ 1,065 | |||||
Utility operations | Tax Cuts and Jobs Act of 2017 | ||||||
Regulatory environment | ||||||
Change in deferred income taxes from tax legislation | $ 1,065 |
Quarterly Financial Informat110
Quarterly Financial Information (Unaudited) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 940.5 | $ 943.8 | $ 855.4 | $ 972 | $ 916.3 | $ 1,023.8 | $ 877.2 | $ 975.5 | $ 3,711.7 | $ 3,792.8 | $ 3,854.1 |
Operating income | 134.3 | 163.4 | 142.8 | 185.1 | 104.7 | 196.4 | 146.9 | 181.5 | 625.6 | 629.5 | 648.9 |
Net income attributed to common shareholder | $ 69.1 | $ 89.4 | $ 75.3 | $ 101.8 | $ 59.2 | $ 115.2 | $ 82.6 | $ 107.3 | $ 335.6 | $ 364.3 | $ 375.7 |
Schedule II - Valuation and 111
Schedule II - Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Valuation and qualifying accounts | |||
Balance at beginning of period | $ 40.9 | $ 43 | $ 46.8 |
Transfer of net assets to UMERC | (0.3) | 0 | 0 |
Expense | 31.2 | 31.1 | 30.6 |
Deferral | (6.4) | (5.7) | 0.3 |
Net write-offs | (25.9) | (27.5) | (34.7) |
Balance at end of period | $ 39.5 | $ 40.9 | $ 43 |