DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Jan. 31, 2016 | Jun. 30, 2015 | |
Document and Entity Information | |||
Entity Registrant Name | WISCONSIN PUBLIC SERVICE CORP | ||
Entity Central Index Key | 107,833 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Public Float | $ 0 | ||
Entity Common Stock, Shares Outstanding | 23,896,962 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Statement [Abstract] | |||
Operating revenues | $ 1,483.3 | $ 1,683.6 | $ 1,580.5 |
Cost of sales | 599.8 | 771.1 | 721.5 |
Other operation and maintenance | 493.4 | 499.7 | 470.4 |
Depreciation and amortization | 121 | 116.8 | 109.4 |
Property and revenue taxes | 41 | 38.4 | 39.2 |
Total operating expenses | 1,255.2 | 1,426 | 1,340.5 |
Operating income | 228.1 | 257.6 | 240 |
Other income, net | 25.6 | 25.2 | 23.5 |
Interest expense | 53.5 | 57.4 | 43.7 |
Other expense | (27.9) | (32.2) | (20.2) |
Income before income taxes | 200.2 | 225.4 | 219.8 |
Income tax expense | 75 | 84.7 | 81.9 |
Net income | 125.2 | 140.7 | 137.9 |
Preferred stock dividend requirements | 2.7 | 3.1 | 3.1 |
Net income attributed to common shareholder | $ 122.5 | $ 137.6 | $ 134.8 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Assets | ||
Cash and cash equivalents | $ 6.1 | $ 5.4 |
Accounts receivable and unbilled revenues, net of reserves of $2.5 and $3.2, respectively | 164 | 203.1 |
Receivables from related parties | 3.1 | 1.3 |
Materials, supplies and inventories | ||
Fuel and gas | 104.5 | 85 |
Materials and supplies, at average cost | 40.5 | 39.2 |
Prepaid taxes | 48.1 | 65.7 |
Other current assets | 27 | 17.7 |
Current assets | 393.3 | 417.4 |
Property, plant, and equipment, net of accumulated depreciation of $1,565.7 and $1,542.5, respectively | 3,418.6 | 3,131 |
Regulatory assets | 462.5 | 457.1 |
Goodwill | 36.4 | 36.4 |
Pension and other postretirement benefit assets | 102.4 | 128.9 |
Other long-term assets | 91.9 | 98.5 |
Long-term assets | 4,111.8 | 3,851.9 |
Total assets | 4,505.1 | 4,269.3 |
Liabilities and Shareholders' Equity | ||
Short-term debt | 182.8 | 145.1 |
Current portion of long-term debt | 0 | 125 |
Current portion of long-term debt to parent | 2.9 | 2.5 |
Accounts payable | 181.8 | 161.6 |
Payables to related parties | 35.6 | 16.9 |
Other current liabilities | 50.2 | 71.6 |
Current liabilities | 453.3 | 522.7 |
Long-term debt to parent | 0 | 2.9 |
Long-term debt | 1,289.4 | 1,040.1 |
Deferred income taxes | 774.1 | 725.9 |
Deferred investment tax credits | 7.4 | 7.8 |
Regulatory liabilities | 290 | 318.4 |
Environmental remediation liabilities | 83.5 | 86.3 |
Pension and other postretirement benefit obligations | 24.4 | 37.6 |
Payables to related parties | 4.8 | 5.4 |
Other long-term liabilities | 92.3 | 71.6 |
Long-term liabilities | $ 2,565.9 | $ 2,296 |
Commitments and contingencies (Note 18) | ||
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively | $ 0 | $ 51.2 |
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares issued and outstanding | 95.6 | 95.6 |
Additional paid-in capital | 861.8 | 782 |
Retained earnings | 528.5 | 521.8 |
Total liabilities and shareholder's equity | $ 4,505.1 | $ 4,269.3 |
CONSOLIDATED BALANCE SHEETS (PA
CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Accounts receivable and unbilled revenues, reserves (in dollars) | $ 2.5 | $ 3.2 |
Property, plant, and equipment, accumulated depreciation (in dollars) | $ 1,565.7 | $ 1,542.5 |
Preferred stock, par value (in dollars per share) | $ 100 | $ 100 |
Preferred stock, shares authorized | 1,000,000 | 1,000,000 |
Preferred stock, shares issued | 0 | 511,882 |
Preferred stock, shares outstanding | 0 | 511,882 |
Common stock, par value (in dollars per share) | $ 4 | |
Common stock, shares authorized | 32,000,000 | |
Common stock, shares issued | 23,896,962 | 23,896,962 |
Common stock, shares outstanding | 23,896,962 | 23,896,962 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating Activities | |||
Net income | $ 125.2 | $ 140.7 | $ 137.9 |
Reconciliation to cash provided by operating activities | |||
Depreciation and amortization | 121 | 113.8 | 106.2 |
Pension and other postretirement (credit) expense | (2.7) | (6.2) | 22.2 |
Contributions to pension and OPEB plans | (2.4) | (49.5) | (43.5) |
Deferred income taxes and investment tax credits, net | 43.6 | 90.5 | 79.4 |
Termination of tolling agreement with Fox Energy Company LLC | 0 | 0 | (50) |
Change in – | |||
Collateral on deposit | (17.4) | (3.8) | 1.2 |
Accounts receivable and unbilled revenues | 38.6 | 13.4 | (14.6) |
Materials, supplies, and inventories | (16.1) | (28) | 19.6 |
Prepaid taxes | 17.6 | (2.1) | 21.1 |
Other current assets | 1.5 | 3.7 | (2.3) |
Accounts payable | 5 | 15.5 | (18) |
Other current liabilities | (3.3) | (14) | 6.5 |
Other, net | (5.9) | (10.5) | 7.4 |
Net cash provided by operating activities | 304.7 | 263.5 | 273.1 |
Investing activities | |||
Capital expenditures | (371) | (322) | (236.1) |
Acquisition of Fox Energy Company LLC | 0 | 0 | (391.6) |
Grant received related to Crane Creek wind project | 0 | 0 | 69 |
Other, net | (2.3) | 0.9 | 2.1 |
Net cash used for investing activities | (373.3) | (321.1) | (556.6) |
Financing activities | |||
Change in short-term debt | 37.7 | 119.5 | (69.8) |
Borrowing on term credit facility | 0 | 0 | 200 |
Repayment of term credit facility | 0 | 0 | (200) |
Repayment of long-term debt | (125.1) | 0 | (147) |
Repayment of long-term debt to parent | (2.5) | (0.9) | (0.9) |
Issuance of long-term debt | 250 | 0 | 450 |
Payments of dividend to parent | (115.1) | (111.8) | (108.6) |
Equity contribution from parent | 235 | 55 | 200 |
Return of capital to parent | (150) | 0 | (35) |
Preferred stock dividend requirements | (2.7) | (3.1) | (3.1) |
Redemption of preferred stock | (52.7) | 0 | 0 |
Other, net | (5.3) | (1.4) | (2.9) |
Net cash provided by financing activities | 69.3 | 57.3 | 282.7 |
Net change in cash and cash equivalents | 0.7 | (0.3) | (0.8) |
Cash and cash equivalents at beginning of year | 5.4 | 5.7 | 6.5 |
Cash and cash equivalents at end of year | $ 6.1 | $ 5.4 | $ 5.7 |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions | Total | Total Common Shareholder's Equity | Common Stock | Additional Paid in Capital | Retained Earnings |
Balance at Dec. 31, 2012 | $ 1,121.5 | $ 95.6 | $ 555.4 | $ 470.5 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income attributed to common shareholder | $ 134.8 | 134.8 | 0 | 0 | 134.8 |
Equity contribution from parent | 200 | 200 | 0 | 200 | 0 |
Return of capital to parent | 35 | (35) | 0 | (35) | 0 |
Dividends to parent | (108.6) | 0 | 0 | (108.6) | |
Other | 2.7 | 0 | 3.1 | (0.4) | |
Balance at Dec. 31, 2013 | 1,315.4 | 95.6 | 723.5 | 496.3 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income attributed to common shareholder | 137.6 | 137.6 | 0 | 0 | 137.6 |
Equity contribution from parent | 55 | 55 | 0 | 55 | 0 |
Return of capital to parent | 0 | ||||
Dividends to parent | (111.8) | 0 | 0 | (111.8) | |
Other | 3.2 | 0 | 3.5 | (0.3) | |
Balance at Dec. 31, 2014 | 1,399.4 | 1,399.4 | 95.6 | 782 | 521.8 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||
Net income attributed to common shareholder | 122.5 | 122.5 | 0 | 0 | 122.5 |
Equity contribution from parent | 235 | 235 | 0 | 235 | 0 |
Return of capital to parent | 150 | (150) | 0 | (150) | 0 |
Dividends to parent | (115.1) | 0 | 0 | (115.1) | |
Other | (5.9) | 0 | (5.2) | (0.7) | |
Balance at Dec. 31, 2015 | $ 1,485.9 | $ 1,485.9 | $ 95.6 | $ 861.8 | $ 528.5 |
CONSOLIDATED STATEMENTS OF CAPI
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Schedule of Capitalization | ||
Common stock – $4 par value; 32,000,000 shares authorized; 23,896,962 shares outstanding | $ 95.6 | $ 95.6 |
Additional paid-in capital | 861.8 | 782 |
Retained earnings | 528.5 | 521.8 |
Total common stock equity | 1,485.9 | 1,399.4 |
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively | 0 | 51.2 |
Notes payable to Integrys | 2.9 | 5.4 |
Current portion of long-term debt to parent | (2.9) | (2.5) |
Total long-term debt to parent | 0 | 2.9 |
Total First Mortgage Bonds and Senior Notes | 1,300 | 1,175.1 |
Unamortized Debt Issuance Expense | (9.9) | (9.4) |
Unamortized discount on long-term debt | (0.7) | (0.6) |
Total | 1,289.4 | 1,165.1 |
Current portion of long-term debt | 0 | (125) |
Total long-term debt | 1,289.4 | 1,040.1 |
Total capitalization | $ 2,775.3 | 2,493.6 |
Long Term debt to parent, 8.76% Series, Year Due, 2015 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 8.76% | |
Notes payable to Integrys | $ 0 | 2 |
Long Term debt to parent, 7.35% Series, Year Due, 2016 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 7.35% | |
Notes payable to Integrys | $ 2.9 | 3.4 |
Long Term debt, 7.125% Series, Year Due, 2023 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 7.125% | |
First Mortgage Bonds | $ 0 | 0.1 |
Long Term debt, 6.375% Series, Year Due, 2015 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 6.375% | |
Senior Notes | $ 0 | 125 |
Long Term debt, 5.65% Series, Year Due, 2017 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 5.65% | |
Senior Notes | $ 125 | 125 |
Long Term Debt 1.65% Series, Due 2018 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 1.65% | |
Senior Notes | $ 250 | 0 |
Long Term debt, 6.08% Series, Year Due, 2028 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 6.08% | |
Senior Notes | $ 50 | 50 |
Long Term debt, 5.55% Series, Year Due, 2036 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 5.55% | |
Senior Notes | $ 125 | 125 |
Long Term Debt 3.671% Series, Year Due, 2042 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 3.671% | |
Senior Notes | $ 300 | 300 |
Long Term debt 4.752% Series, Year Due 2044 | ||
Schedule of Capitalization | ||
Interest rate, (as a percent) | 4.752% | |
Senior Notes | $ 450 | $ 450 |
CONSOLIDATED STATEMENTS OF CAP8
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION | ||
Common stock, par value (in dollars per share) | $ 4 | |
Common stock, shares authorized | 32,000,000 | |
Common stock, shares outstanding | 23,896,962 | 23,896,962 |
Preferred stock, par value (in dollars per share) | $ 100 | $ 100 |
Preferred stock, shares authorized | 1,000,000 | 1,000,000 |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) General Information —On June 29, 2015, Wisconsin Energy Corporation acquired our parent company, Integrys, and changed its name to WEC Energy Group. See Note 2, Merger, for more information on the acquisition. We are an electric and natural gas utility company that services customers in northeastern Wisconsin and Michigan's Upper Peninsula. We are subject to the jurisdiction of, and regulation by, the PSCW and the MPSC, which have general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin and Michigan, respectively. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. 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. At December 31, 2015 , we had one wholly owned subsidiary, WPS Leasing. The financial statements include our accounts and the accounts of our wholly owned subsidiary. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. See Note 8, Jointly Owned Utility Facilities, for more information . 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. 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. (b) Reclassifications — As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below. Statements of Income • Certain amortizations of deferrals were reclassified from other operation and maintenance to cost of sales; depreciation and amortization; and other income, net. • Payroll taxes of $8.3 million and $8.9 million for the years ended December 31, 2014 and 2013, respectively, were reclassified from taxes other than income taxes to other operation and maintenance. The taxes other than income taxes line item was also renamed to property and revenue taxes. • Certain expenses in cost of sales were reclassified to operating revenues, other operation and maintenance, and depreciation and amortization. The amounts reclassified to other operation and maintenance were $5.9 million and $6.7 million for the years ended December 31, 2014 and 2013, respectively. • Certain expenses in other operation and maintenance were reclassified to cost of sales, and depreciation and amortization. The amounts reclassified to other cost of sales were $3.1 million and $5.6 million for the years ended December 31, 2014 and 2013, respectively. Balance Sheets • Current regulatory assets of $1.4 million and $23.6 million were reclassified to accounts receivable and long-term regulatory assets, respective ly, at December 31, 2014. • Current regulatory liabilities of $6.1 million and $15.1 million were recl assified to other current liabilities and long-t erm regulatory liabilities, respectivel y, at December 31, 2014. • During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $0.6 million and $8.8 million , previously reported as other current assets and other long-term assets, respectively, were reclassified to offset long-term debt on the December 31, 2014 balance sheet. • During the fourth quarter of 2015, we also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $3.8 million , previously reported as a component of other current liabilities, to long-term deferred income tax liabilities on the December 31, 2014 balance sheet. Statements of Cash Flows • Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections. (c) Cash and Cash Equivalents —Cash and cash equivalents include marketable debt securities acquired three months or less from maturity. (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 return on common equity than authorized by the PSCW. • 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. 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 revenue. 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 and natural gas service to customers in northeastern Wisconsin and Michigan's Upper Peninsula. 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. As a result, we did not have any significant concentrations of credit risk at December 31, 2015 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015 . (e) Materials, Supplies, and Inventories —Our inventory as of December 31 consisted of: (in millions) 2015 2014 Fossil fuel $ 76.4 $ 48.9 Materials and supplies 40.5 39.2 Natural gas in storage 28.1 36.1 Total $ 145.0 $ 124.2 Substantially all fossil fuels, materials and supplies, 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 revenue 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 6, Regulatory Assets and Liabilities, for more information . (g) Property, Plant, and Equipment —We record property, plant, and equipment at cost. Cost includes material, labor, and overhead. Utility property also includes AFUDC – Equity. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to 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 applicable regulators. Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2015 2014 2013 Electric 2.70 % 2.73 % 2.79 % Natural gas 2.15 % 2.17 % 2.19 % 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 is three years . If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense. See Note 7, 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 stockholders' 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 7.92% , 8.08% , and 8.61% for 2015, 2014, and 2013, respectively. Our average AFUDC wholesale rates were 5.10% , 6.99% , and 2.64% for 2015, 2014, and 2013, respectively. We recorded the following AFUDC for the years ended December 31: (in millions) 2015 2014 2013 AFUDC – Debt $ 6.1 $ 4.6 $ 3.8 AFUDC – Equity 15.1 11.0 9.9 (i) Emission Allowances —We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers. (j) Goodwill —Goodwill is subject to an annual impairment test. Our natural gas utility reporting unit contains goodwill and performed its annual goodwill impairment test as of April 1, 2015. Interim impairment tests are performed when impairment indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. (k) 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. A 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 AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is 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 9, Asset Retirement Obligations, for more information . (l) 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 18, Commitments and Contingencies, for more information . We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of possible losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potential 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 applicable state's Commission'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. (m) Income Taxes — We and our subsidiary are included in the consolidated United States income tax return filed by Integrys for all tax periods up to and including the tax year ended June 29, 2015. For all tax periods after June 29, 2015, we and our subsidiary are included within the WEC Energy Group consolidated return. Similarly, we and our subsidiary are party to a tax allocation arrangement with Integrys and its consolidated subsidiaries for all tax periods up to and including June 29, 2015, and are a party to a tax allocation arrangement with WEC Energy Group and its consolidated subsidiaries for tax periods ending after June 29, 2015. Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. We defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments. We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset. We report interest and penalties accrued, related to income taxes, as a component of income tax expense in our income statements. We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards. See Note 15, Income Taxes, for more information regarding our accounting for income taxes. (n) Guarantees —We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. See Note 21, Regulatory Environment, for more information . (o) Employee Benefits —The costs of pension and OPEB are expensed over the periods during which employees render service. The benefit costs associated with employee benefit plans are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP. See Note 17, Employee Benefits, for more information . (p) 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. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input. Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available. We recognize transfers at the value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount for each such item approximates fair value. The fair values of long-term debt, including the current portion of long-term debt, are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis. See Note 19, Fair Value Measurements, for more information . (q) 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. Regulated hedging programs are approved by the PSCW and the MPSC. We record derivative instruments on our balance sheets as an asset or liability measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. 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. See Note 20, Derivative Instruments, for more information . (r) Customer Deposits and Credit Balances —When utility customers apply for new service, they may be required to provide a deposit for the service. 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 accounts payable on our balance sheets. |
MERGER
MERGER | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
MERGER | MERGER On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of Wisconsin Energy Corporation. Wisconsin Energy Corporation then changed its name to WEC Energy Group. The merger 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 requires that 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 Wisconsin Electric filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time. We have been authorized to recover the costs we have recorded at December 31, 2015 related to the proposed construction. We do not believe that the conditions set forth in the various regulatory orders approving the WEC Merger will have a material impact on our operations or financial results. In 2015, we recorded $4.6 million of severance expense that resulted from employee reductions related to the post-merger integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $4.3 million were made during 2015, leaving an insignificant severance accrual on our balance sheet at December 31, 2015 . Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments: (in millions) 2015 Electric utility segment $ 3.6 Natural gas utility segment 1.0 Total severance expense $ 4.6 ACQUISITION In March 2013, we acquired all of the equity interests in Fox Energy Company LLC for $391.6 million . Fox Energy Company LLC was dissolved immediately after the purchase. The purchase included the Fox Energy Center, a 593 MW combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives us a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers. The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows: (in millions) Assets acquired (1) Inventories – materials and supplies $ 3.0 Other current assets 0.4 Property, plant, and equipment 374.4 Other long-term assets (2) 15.6 Total assets acquired $ 393.4 Liabilities assumed Accounts payable $ 1.8 Total liabilities assumed $ 1.8 (1) Relates to the electric utility segment. (2) Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information . Prior to the purchase, we supplied natural gas for the facility and purchased 500 MWs of capacity and the associated energy output under a tolling arrangement. We paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as we are authorized recovery by the PSCW. The amount is being amortized over a nine -year period that began on January 1, 2014 . Our 2015 retail electric rate increase included the recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. See Note 21, Regulatory Environment, for more information . Our rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center. Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by us. The plant is now part of our regulated fleet, used to serve our customers. |
ACQUISITION
ACQUISITION | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
ACQUISITION OF FOX ENERGY CENTER | MERGER On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of Wisconsin Energy Corporation. Wisconsin Energy Corporation then changed its name to WEC Energy Group. The merger 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 requires that 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 Wisconsin Electric filed a joint integrated resource plan with the PSCW for our combined loads, which indicated that there is no need to proceed with the proposed construction of a new generating unit at the Fox Energy Center site at this time. We have been authorized to recover the costs we have recorded at December 31, 2015 related to the proposed construction. We do not believe that the conditions set forth in the various regulatory orders approving the WEC Merger will have a material impact on our operations or financial results. In 2015, we recorded $4.6 million of severance expense that resulted from employee reductions related to the post-merger integration. This expense is included in the other operation and maintenance line item on the income statement. Severance payments of $4.3 million were made during 2015, leaving an insignificant severance accrual on our balance sheet at December 31, 2015 . Severance costs to be incurred after December 31, 2015 are not expected to be material. The severance expense was recorded in the following segments: (in millions) 2015 Electric utility segment $ 3.6 Natural gas utility segment 1.0 Total severance expense $ 4.6 ACQUISITION In March 2013, we acquired all of the equity interests in Fox Energy Company LLC for $391.6 million . Fox Energy Company LLC was dissolved immediately after the purchase. The purchase included the Fox Energy Center, a 593 MW combined-cycle electric generating facility located in Wisconsin, along with associated contracts. Fox Energy Center is a dual-fuel facility, equipped to use fuel oil, but being run primarily on natural gas. This plant gives us a more balanced mix of owned electric generation, including coal, natural gas, hydroelectric, wind, and other renewable sources. In giving its approval for the purchase, the PSCW stated that the purchase price was reasonable and will benefit ratepayers. The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows: (in millions) Assets acquired (1) Inventories – materials and supplies $ 3.0 Other current assets 0.4 Property, plant, and equipment 374.4 Other long-term assets (2) 15.6 Total assets acquired $ 393.4 Liabilities assumed Accounts payable $ 1.8 Total liabilities assumed $ 1.8 (1) Relates to the electric utility segment. (2) Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information . Prior to the purchase, we supplied natural gas for the facility and purchased 500 MWs of capacity and the associated energy output under a tolling arrangement. We paid $50.0 million for the early termination of the tolling arrangement. This amount was recorded as a regulatory asset, as we are authorized recovery by the PSCW. The amount is being amortized over a nine -year period that began on January 1, 2014 . Our 2015 retail electric rate increase included the recovery of 2013 deferred costs related to the acquisition of the Fox Energy Center. See Note 21, Regulatory Environment, for more information . Our rate order effective January 1, 2014, included the costs of owning and operating the Fox Energy Center. Pro forma adjustments to our revenues and earnings prior to the date of acquisition would not be meaningful or material. Prior to the acquisition, the Fox Energy Center was a nonregulated plant and sold all of its output to third parties, with most of the output purchased by us. The plant is now part of our regulated fleet, used to serve our customers. |
RELATED PARTIES
RELATED PARTIES | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
RELATED PARTIES | RELATED PARTIES We and our subsidiary, WPS Leasing, routinely enter into transactions with related parties, including WEC Energy Group, its subsidiaries, and other entities in which we have material interests. We provide and receive services, property, and other items of value to and from our ultimate parent, WEC Energy Group, and other subsidiaries of WEC Energy Group. Following the WEC Merger on June 29, 2015, Integrys Business Support, LLC (IBS) changed its name to WBS, and a new affiliated interest agreement (Non-WBS AIA) went into effect. The new Non-WBS AIA includes the former Wisconsin Energy Corporation and its subsidiaries. It governs the provision and receipt of services by WEC Energy Group's subsidiaries, except that WBS will continue to provide services to Integrys and its subsidiaries only under the existing WBS affiliated interest agreements (WBS AIAs). WBS will provide services to WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries under new interim WBS affiliated interest agreements (interim WBS AIAs). The Non-WBS AIA includes no other significant changes from the prior Non-IBS affiliated interest agreement. The PSCW and all other relevant state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA. Services under the Non-WBS AIA are subject to various pricing methodologies. All services provided by any regulated subsidiary to another regulated subsidiary are priced at cost. All services provided by any regulated subsidiary to any nonregulated subsidiary are priced at the greater of cost or fair market value. All services provided by any nonregulated subsidiary to any regulated subsidiary are priced at the lesser of cost or fair market value. All services provided by any regulated or nonregulated subsidiary to WBS are priced at cost. WBS provides 15 categories of services (including financial, human resource, and administrative services) to us pursuant to the WBS AIAs, which have been approved, or from which we have been 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 WBS AIAs. Other modifications or amendments to the WBS AIAs would require PSCW approval. Recovery of allocated costs is addressed in our rate cases. The PSCW orders approving the Non-WBS AIA and the interim WBS AIAs include an April 1, 2016, sunset date for WEC Energy Group and the former Wisconsin Energy Corporation subsidiaries. These companies may request one extension of the sunset date. Prior to the sunset date, we, along with WEC Energy Group, will file new or modified Non-WBS and WBS AIAs for approval with the PSCW and other state commissions. We provide services to and receive services from ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under these agreements at our fully allocated cost. We provide services to WRPC under an operating agreement approved by the PSCW. We are also under a service agreement with WRPC under which either party may be a service provider. Services are billed to and from WRPC under these agreements at a fully allocated cost. The table below includes information summarizing other transactions entered into with related parties: (in millions) December 31, 2015 December 31, 2014 Accounts receivable Service provided to ATC $ 0.5 $ 0.9 Notes payable * Integrys 2.9 5.4 Accounts payable Network transmission services from ATC 8.5 8.2 Liability related to income tax allocation Integrys 5.4 6.1 * WPS Leasing, our consolidated subsidiary, has a note payable to Integrys. At December 31, 2015 and 2014 , the current portion of the note payable was $2.9 million and $2.5 million , respectively. The following table shows activity associated with our other related party transactions for the years ended December 31: (in millions) 2015 2014 2013 Electric transactions Sales to UPPCO (1) $ — $ 15.3 $ 22.8 Sales to ITF (2) — 0.1 — Sales to Wisconsin Electric 0.1 — — Natural gas transactions Sales to Wisconsin Electric 0.4 — — Sales to IES (3) — 0.6 0.5 Purchases from IES (3) — 2.5 0.9 Interest expense (4) Integrys 0.3 0.5 0.5 Transactions with equity-method investees Charges from ATC for network transmission services 101.3 99.0 98.4 Charges to ATC for services and construction 10.3 8.6 9.5 Purchases of energy from WRPC 3.8 3.7 3.7 Charges to WRPC for operations 1.1 1.4 0.9 Equity earnings from WPS Investments, LLC (5) 7.7 9.5 10.2 Sales of electricity to AMP Trillium, LLC (6) 0.1 — — (1) Integrys sold UPPCO in August 2014. (2) In February 2016, an agreement was entered into to sell ITF. This sale is scheduled to close in the first quarter of 2016. (3) Integrys sold IES's retail energy business in November 2014. (4) WPS Leasing has a note payable to Integrys. (5) WPS Investments, LLC is an indirect wholly-owned subsidiary of WEC Energy Group that is jointly owned by Integrys and us. WPS Investments, LLC invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015 , we had an 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC. (6) In November 2015, ITF, an indirect wholly-owned subsidiary of Integrys, sold its ownership interest in AMP Trillium, LLC, a joint venture between ITF and AMP Americas, LLC. This joint venture owned and operated compressed natural gas fueling stations. |
SUPPLEMENTAL CASH FLOW INFORMAT
SUPPLEMENTAL CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
CASH AND CASH EQUIVALENTS | SUPPLEMENTAL CASH FLOW INFORMATION (in millions) 2015 2014 2013 Cash paid for interest, net of amount capitalized $ 58.1 $ 56.8 $ 43.9 Cash paid (received) for income taxes, net of refunds 14.5 (6.2 ) (27.3 ) Significant non-cash transactions: Construction costs funded through accounts payable 70.5 54.0 37.3 |
REGULATORY ASSETS AND LIABILITI
REGULATORY ASSETS AND LIABILITIES | 12 Months Ended |
Dec. 31, 2015 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
REGULATORY ASSETS AND LIABILITIES | REGULATORY ASSETS AND LIABILITIES The following regulatory assets were reflected on our balance sheets as of December 31: (in millions) 2015 2014 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 176.6 $ 185.6 17 Environmental remediation costs (4) 104.4 103.8 18 Income tax related items (5) 40.8 32.7 Termination of a tolling agreement with Fox Energy Company LLC 39.1 44.6 3 Crane Creek production tax credits (6) 30.9 32.2 De Pere Energy Center (7) 19.0 21.4 Energy costs recoverable through rate adjustments (8) 12.0 12.6 Other 39.9 25.6 Total regulatory assets $ 462.7 $ 458.5 Balance Sheet Presentation Current assets (9) $ 0.2 $ 1.4 Regulatory assets 462.5 457.1 Total regulatory assets $ 462.7 $ 458.5 (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 above. (2) As of December 31, 2015 , we had $21.0 million of regulatory assets not earning a return. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. (4) As of December 31, 2015, we had not yet made cash expenditures for $83.5 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures. (5) Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years. (6) In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12 -year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits and are authorized recovery of this net regulatory asset through 2039. (7) Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023. (8) Represents energy costs that will be recovered from customers in the future. (9) Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets. The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2015 2014 See Note Regulatory liabilities Removal costs (1) $ 243.7 $ 243.9 Energy costs refundable through rate adjustments (2) 29.4 6.0 Crane Creek depreciation deferral (3) 8.3 8.7 Unrecognized pension and OPEB costs (4) 1.0 42.4 17 Decoupling — 12.3 21 Other 11.2 11.2 Total regulatory liabilities $ 293.6 $ 324.5 Balance Sheet Presentation Other current liabilities $ 3.6 $ 6.1 Regulatory liabilities 290.0 318.4 Total regulatory liabilities $ 293.6 $ 324.5 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents energy costs that will be refunded to customers in the future. (3) Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above. (4) Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan. |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2015 | |
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 assets at December 31: (in millions) 2015 2014 Electric utility $ 3,722.8 $ 3,587.4 Natural gas utility 818.4 773.1 Total utility plant 4,541.2 4,360.5 Less: Accumulated depreciation 1,559.6 1,495.9 Net 2,981.6 2,864.6 CWIP 434.2 248.7 Plant to be retired, net * — 12.5 Net utility plant 3,415.8 3,125.8 Non-utility plant 8.9 15.2 Less: Accumulated depreciation 6.1 10.0 Net non-utility plant 2.8 5.2 Total property, plant, and equipment $ 3,418.6 $ 3,131.0 * In connection with the Consent Decree with the EPA, we retired Weston 1 and Pulliam Units 5 and 6 on June 1, 2015. See Note 18, Commitments and Contingencies, for more information regarding the Consent Decree. |
JOINTLY OWNED UTILITY FACILITIE
JOINTLY OWNED UTILITY FACILITIES | 12 Months Ended |
Dec. 31, 2015 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
JOINTLY OWNED UTILITY FACILITIES | JOINTLY OWNED UTILITY FACILITIES We hold a joint ownership interest in certain electric generating facilities. We are entitled to our share of generating capability and output of each facility equal to our respective ownership interest. We also pay our ownership share of additional construction costs, fuel inventory purchases, and operating expenses, unless specific agreements have been executed to limit our maximum exposure to additional costs. We record our proportionate share of significant jointly owned electric generating facilities as property, plant, and equipment on the balance sheets. The amounts were as follows at December 31, 2015 : (in millions, except for percentages and MWs) Weston 4 Columbia Energy Center Units 1 and 2 Edgewater Unit 4 Ownership 70.0 % 31.8 % 31.8 % Our share of rated capacity (MWs) * 374.5 352.9 96.3 In-service date 2008 1975 and 1978 1969 Utility plant $ 591.5 $ 404.6 $ 47.6 Accumulated depreciation $ (150.5 ) $ (122.6 ) $ (30.6 ) CWIP $ 5.9 $ 23.4 $ 0.4 * Based on expected capacity ratings for summer 2016. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. Our proportionate share of direct expenses for the joint operation of these plants is recorded in operating expenses in the income statements. We have supplied our own financing for all jointly owned projects. See Note 18, Commitments and Contingencies , for information related to the requirement to refuel, repower, or retire Edgewater Unit 4. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | ASSET RETIREMENT OBLIGATIONS We have recorded AROs primarily for asbestos abatement at certain generation facilities, office buildings, and service centers; the dismantling of wind generation projects; the disposal of polychlorinated biphenyls-contaminated transformers; and the closure of fly-ash landfills at certain generation facilities. We establish regulatory assets and liabilities to record the differences between ongoing expense recognition under the ARO accounting rules and the ratemaking 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: (in millions) 2015 2014 2013 Balance as of January 1 $ 20.3 $ 18.0 $ 16.7 Accretion 1.2 1.0 0.9 Additions and revisions to estimated cash flows (1) 11.4 (1 ) 1.5 (2 ) 0.5 Liabilities settled (0.2 ) (0.2 ) (0.1 ) Balance as of December 31 $ 32.7 $ 20.3 $ 18.0 (1) An ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates. (2) We revised the AROs recorded for the asbestos at our electric generation facilities primarily due to changes in estimated settlement dates. |
GOODWILL AND OTHER INTANGIBLE A
GOODWILL AND OTHER INTANGIBLE ASSETS | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
GOODWILL AND OTHER INTANGIBLE ASSETS | GOODWILL AND OTHER INTANGIBLE ASSETS We had no changes to the carrying amount of goodwill during the years ended December 31, 2015 and 2014 . In the second quarter of 2015 , we completed our annual goodwill impairment test, and no impairment resulted from this test. The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets. December 31, 2015 December 31, 2014 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 15.6 $ (7.5 ) $ 8.1 $ 15.6 $ (4.3 ) $ 11.3 Unamortized intangible assets 0.4 — 0.4 — — — Total intangible assets $ 16.0 $ (7.5 ) $ 8.5 $ 15.6 $ (4.3 ) $ 11.3 * Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2015 , was approximately three years . |
COMMON EQUITY
COMMON EQUITY | 12 Months Ended |
Dec. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation Our employees were granted awards under Integrys’s stock-based compensation plans. Pursuant to the Merger Agreement, immediately prior to completion of the merger, all outstanding stock-based compensation awards became fully vested and were settled in exchange for the right to be paid out in cash to award recipients. See Note 2, Merger, for more information regarding the merger. The intrinsic values of the awards settled due to the merger were $1.5 million and $5.2 million for performance stock rights and restricted stock units, respectively. The intrinsic value of stock options settled was not significant. Compensation cost associated with stock-based compensation awards was allocated to us based on the percentages used for allocation of the award recipients’ labor costs. The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31 : (in millions) 2015 2014 2013 Stock options $ — $ 1.0 $ 0.7 Performance stock rights 1.3 6.3 1.1 Restricted share units 3.5 3.8 3.4 Total stock-based compensation expense $ 4.8 $ 11.1 $ 5.2 Deferred income tax benefit $ 1.9 $ 4.4 $ 2.1 A summary of the activity for our stock-based compensation awards for the year ended December 31, 2015 , is presented below: Stock Options Performance Stock Rights Restricted Stock Units Outstanding as of January 1, 2015 5,714 13,937 70,544 Granted — — 30,174 Dividend equivalents N/A N/A 1,267 Transferred — — (166 ) Exercised/Distributed/Vested and Released * (2,752 ) (2,229 ) (28,428 ) Settled as a result of WEC Merger (2,962 ) (21,263 ) (73,391 ) Adjustment for performance stock rights distributed or settled N/A 9,555 N/A Outstanding as of December 31, 2015 — — — * The intrinsic value of restricted stock unit awards vested and released was $2.2 million . The intrinsic value of stock options exercised and shares distributed for performance stock rights was not significant. Restrictions Various laws, regulations, and financial covenants impose restrictions on our ability to pay dividends to the sole holder of our common stock, Integrys. 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. See Note 13, Short-Term Debt and Lines of Credit , for discussion of certain financial covenants related to short-term debt obligations. As of December 31, 2015 , restricted retained earnings totaled $528.5 million . Our equity in undistributed earnings of investees accounted for by the equity method was $32.3 million at December 31, 2015 . Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions. Integrys may provide equity contributions to us or request a return of capital from us in order to maintain utility common equity levels consistent with those allowed by the PSCW. Wisconsin law prohibits us from making loans to or guaranteeing obligations of WEC Energy Group, Integrys, or their other subsidiaries. |
PREFERRED STOCK
PREFERRED STOCK | 12 Months Ended |
Dec. 31, 2015 | |
Class of Stock Disclosures [Abstract] | |
PREFERRED STOCK | PREFERRED STOCK The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014 : 2015 Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Preferred Stock 1,000,000 — N/A N/A 2014 (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Preferred Stock 1,000,000 5.00% Series 131,916 $ 107.50 $ 13.2 5.04% Series 29,983 102.81 3.0 5.08% Series 49,983 101.00 5.0 6.76% Series 150,000 103.35 15.0 6.88% Series 150,000 100.00 15.0 Total $ 51.2 On November 13, 2015, we redeemed all 511,882 outstanding shares of our five series of preferred stock: (i) 131,916 shares of 5.00% Series; (ii) 29,983 shares of 5.04% Series; (iii) 49,983 shares of 5.08% Series; (iv) 150,000 shares of 6.76% Series; and, (v) 150,000 shares of 6.88% Series. The aggregate redemption price was $52.7 million , plus accumulated and unpaid dividends. |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 12 Months Ended |
Dec. 31, 2015 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | Our short-term borrowings and their corresponding weighted-average interest rates as of December 31 were as follows: (in millions, except percentages) 2015 2014 Commercial paper Amount outstanding at December 31 $ 182.8 $ 145.1 Average interest rate on amounts outstanding at December 31 0.66% 0.32 % Average amount outstanding during the year * $ 145.0 $ 43.3 * Based on daily outstanding balances during the year. 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% . 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 2015 Revolving credit facility * December 2016 $ 250.0 Total short-term credit capacity $ 250.0 Less: commercial paper outstanding 182.8 Available capacity under existing agreement $ 67.2 * We plan to request approval from the PSCW to extend the maturity through December 2020. In December 2015, we terminated our prior credit facilities and entered into a new credit facility maturing in 2016. The lenders under this facility have agreed that its maturity can be extended to December 2020, subject to our receipt of PSCW approval. This $250.0 million 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
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
LONG-TERM DEBT | LONG-TERM DEBT See our statements of capitalization for details on our long-term debt. In November 2015, we redeemed all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7.125% Series due July 1, 2023 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest to the date of redemption. Following the redemption, we discharged our mortgage indenture and do not intend to issue additional first mortgage bonds. All of our senior notes outstanding are now senior unsecured obligations and rank equally with all of our other unsecured obligations. In December 2015, our $125.0 million of 6.375% Senior Notes matured, and the outstanding principal balance was repaid. In December 2015, we issued $250.0 million of 1.65% Senior Notes due December 4, 2018. The proceeds were used to repay short-term debt that we incurred to repay all of our $125.0 million of 6.375% Senior Notes at maturity, and for working capital and other general corporate purposes. A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to our parent, is as follows: (in millions) Payments 2016 $ — 2017 125.0 2018 250.0 2019 — 2020 — Thereafter 925.0 Total $ 1,300.0 We amortize debt premiums, discounts, and debt issuance costs over the life of the debt and we include the costs in interest expense. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2015 | |
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) 2015 2014 2013 Current tax expense $ 31.4 $ (6.1 ) $ 2.1 Deferred income taxes, net 44.0 91.1 80.1 Investment tax credit, net (0.4 ) (0.3 ) (0.3 ) Total income tax expense $ 75.0 $ 84.7 $ 81.9 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 U.S. statutory federal income tax rate to income before income taxes as a result of the following: 2015 2014 2013 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 70.1 35.0 % $ 78.9 35.0 % $ 76.9 35.0 % State income taxes net of federal tax benefit 9.9 5.0 10.9 4.8 10.5 4.8 AFUDC – Equity (5.3 ) (2.6 ) (3.8 ) (1.7 ) (3.5 ) (1.6 ) Other, net 0.3 0.1 (1.3 ) (0.5 ) (2.0 ) (0.9 ) Total income tax expense $ 75.0 37.5 % $ 84.7 37.6 % $ 81.9 37.3 % Deferred Income Tax Assets and Liabilities The components of deferred income taxes as of December 31 are as follows: (in millions) 2015 2014 Total deferred tax assets $ 23.9 $ 4.4 Deferred tax liabilities Plant-related 639.1 591.0 Employee benefits and compensation 91.7 83.9 Regulatory deferrals 52.0 42.4 Other 15.2 13.0 Total deferred tax liabilities 798.0 730.3 Deferred tax liability, net $ 774.1 $ 725.9 Consistent with rate-making treatment, deferred taxes in the table above are offset for temporary differences that have related regulatory assets and liabilities. Deferred tax credit carryforwards at December 31, 2015 , included $2.0 million of alternative minimum tax credits, which can be carried forward indefinitely. Other deferred tax credit carryforwards included $3.0 million of general business credits, which have a carryback period of one year and a carryforward period of 20 years . The majority of the general business credit carryforwards will expire in 2033. At December 31, 2015, we had deferred income tax assets of $16.1 million reflecting federal operating loss carryforwards, which have a carryback period of two years and a carryforward period of 20 years and will expire in 2034. Unrecognized Tax Benefits We had no unrecognized tax benefits at December 31, 2015, and 2014. We had no accrued interest and penalties related to unrecognized tax benefits at December 31, 2015 , and 2014 . We do not expect any unrecognized tax benefits to affect our effective tax rate in periods after December 31, 2015 . We file income tax returns in the United States federal jurisdiction and in our major state operating jurisdictions as a part of Integrys filings up to June 29, 2015, and as a part of WEC Energy Group filings for periods after June 29, 2015. With a few exceptions, we are no longer subject to federal income tax examinations by the IRS for years prior to 2012. We file state tax returns based on income in our major state operating jurisdictions of Wisconsin and Michigan. We are no longer subject to state and local tax examinations for years prior to 2008. As of December 31, 2015 , we were subject to examination by the Wisconsin taxing authority for tax years 2011 through 2015 and the Michigan taxing authority for tax years 2008 through 2015. During 2015, the Michigan taxing authority continued its examination of tax years 2008 through 2011. In the next 12 months, we do not expect to significantly change the amount of unrecognized tax benefits. |
GUARANTEES
GUARANTEES | 12 Months Ended |
Dec. 31, 2015 | |
Guarantees [Abstract] | |
GUARANTEES | GUARANTEES The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at December 31, 2015 Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 9.5 $ — $ 9.5 $ — Surety bonds (2) 1.1 1.1 — — Other guarantee (3) 20.3 20.0 — 0.3 Total guarantees $ 30.9 $ 21.1 $ 9.5 $ 0.3 (1) At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts are not reflected on our balance sheets. (2) Primarily for obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (3) Consists of (a) $20.0 million not reflected on our balance sheet for an interconnection agreement between us and ATC and (b) $0.3 million reflected on our balance sheet related to workers compensation. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFITS Pension and Other Postretirement Employee Benefits We participate in the Integrys retirement plan, a noncontributory, qualified pension plan sponsored by WBS. We are responsible for our share of the plan assets and obligations. We serve as plan sponsor and administrator for certain OPEB plans. The benefits 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. Integrys also offers medical, dental, and life insurance benefits to our active employees and their dependents. We expense the allocated costs of these benefits as incurred. The defined benefit pension plans are closed to all new hires. In addition, the service accruals for the defined benefit pension plans were frozen for non-union employees as of January 1, 2013. These employees receive an annual company contribution to their 401(k) plan, which is calculated based on age, wages, and full years of vesting service as of December 31 each year. In March 2014, we remeasured the obligations of certain OPEB plans as a result of a plan design change to move participants age 65 and older to a Medicare Advantage plan starting January 1, 2015. The following tables provide a reconciliation of the changes in our share of the plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2015 2014 2015 2014 Change in benefit obligation Obligation at January 1 $ 791.8 $ 717.5 $ 252.5 $ 292.7 Service cost 10.7 8.6 8.7 7.7 Interest cost 31.7 34.4 10.4 11.5 Plan amendments — — — (74.4 ) Transfer to affiliates * (130.5 ) (12.1 ) — — Actuarial loss (gain), net (36.4 ) 73.0 (31.7 ) 24.0 Participant contributions — — 0.3 0.5 Benefit payments (33.3 ) (29.6 ) (8.6 ) (10.4 ) Federal subsidy on benefits paid — — — 0.9 Plan curtailment (0.1 ) $ — — $ — Obligation at December 31 $ 633.9 $ 791.8 $ 231.6 $ 252.5 Change in fair value of plan assets Fair value of plan assets at January 1 $ 897.4 $ 839.1 $ 236.6 $ 236.5 Actual return on plan assets (29.4 ) 53.1 (5.1 ) 7.4 Employer contributions 1.1 46.9 1.3 2.6 Participant contributions — — 0.3 0.5 Benefit payments (33.3 ) (29.6 ) (8.6 ) (10.4 ) Transfer to affiliates * (116.8 ) (12.1 ) — — Fair value at December 31 $ 719.0 $ 897.4 $ 224.5 $ 236.6 * Benefit obligations and plan assets were moved along with our employees who were transferred to affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries. 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) 2015 2014 2015 2014 Pension and other postretirement benefit assets $ 93.8 $ 128.9 $ 8.6 $ — Current liabilities — 1.5 — 0.1 Pension and other postretirement benefit liabilities 8.7 21.8 15.7 15.8 Total net assets (liabilities) $ 85.1 $ 105.6 $ (7.1 ) $ (15.9 ) The accumulated benefit obligation for the defined benefit pension plans was $569.6 million and $717.4 million at December 31, 2015 , and 2014 , respectively. The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2015 2014 Projected benefit obligation $ 8.7 $ 23.3 Accumulated benefit obligation 8.5 21.5 The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2015 2014 2015 2014 Net regulatory assets Net actuarial loss $ 61.2 $ 178.7 $ 5.2 $ 41.0 Prior service cost (credit) — 1.8 — (78.3 ) Total $ 61.2 $ 180.5 $ 5.2 $ (37.3 ) The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans: Pension Costs OPEB Costs (in millions) 2015 2014 2013 2015 2014 2013 Service cost $ 10.7 $ 8.6 $ 10.8 $ 8.7 $ 7.7 $ 10.6 Interest cost 31.7 34.4 30.6 10.4 11.5 13.4 Expected return on plan assets (64.8 ) (64.1 ) (57.2 ) (16.0 ) (16.0 ) (14.8 ) Loss on plan settlement 0.1 0.4 — — — — Amortization of prior service cost (credit) 0.2 0.6 3.6 (9.3 ) (8.0 ) (2.1 ) Amortization of net actuarial loss 21.0 15.0 24.0 3.7 2.8 7.5 Net periodic benefit cost $ (1.1 ) $ (5.1 ) $ 11.8 $ (2.5 ) $ (2.0 ) $ 14.6 Assumptions – Pension and Other Postretirement Benefit 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 2015 2014 2015 2014 Discount rate 4.49% 4.08% 4.46% 4.11% Rate of compensation increase 4.00% 4.23% N/A N/A Assumed medical cost trend rate N/A N/A 7.50% 6.00% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2021 2023 The weighted-average assumptions used to determine net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2015 2014 2013 Discount rate 4.08% 4.92% 4.07% Expected return on assets 7.75% 8.00% 8.00% Rate of compensation increase 4.23% 4.25% 4.26% OPEB Costs 2015 2014 2013 Discount rate 4.11% 4.78% 4.01% Expected return on assets 7.75% 8.00% 8.00% Assumed medical cost trend rate (Pre 65/Post 65) 6.00% 6.50% 7.00% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2023 2019 2019 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 2016 , the expected return on assets assumption for the pension and OPEB plans is 7.25% . 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, 2015 , 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 $ 3.8 $ (2.9 ) Effect on the health care component of the accumulated postretirement benefit obligation 31.9 (25.7 ) 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. Central to the policy are target allocation ranges by major asset categories. The objectives of the target allocations are to maintain investment portfolios that diversify risk through prudent asset allocation parameters and to achieve asset returns that meet or exceed the plans' actuarial assumptions and that are competitive with like instruments employing similar investment strategies. The portfolio diversification provides protection against significant concentrations of risk in the plan assets. In 2014, the pension plan target asset allocation was 70% equity securities and 30% fixed income securities. In December 2014, we changed the pension plan target asset allocation to 60% equity securities and 40% fixed income securities for 2015. The target asset allocation for OPEB plans that have significant assets is 70% equity securities and 30% fixed income securities. Equity securities primarily include investments in large-cap and small-cap companies. Fixed income securities primarily include corporate bonds of companies from diversified industries, United States government securities, and mortgage-backed securities. Pension and OPEB plan investments are recorded at fair value. See Note 1(p), 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 provide the fair values of our investments by asset class: December 31, 2015 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 $ — $ 27.4 $ — $ 27.4 $ 4.6 $ 1.0 $ — $ 5.6 Equity securities: U.S. Equity 39.2 162.2 — 201.4 11.9 60.0 — 71.9 International Equity 40.3 179.3 — 219.6 15.5 58.5 — 74.0 Fixed income securities: (1) U.S. Bonds 6.3 218.3 — 224.6 65.1 — — 65.1 International Bonds — 55.9 — 55.9 — — — — 85.8 643.1 — 728.9 97.1 119.5 — 216.6 401(h) other benefit plan assets invested as pension assets (2) (0.9 ) (7.2 ) — (8.1 ) 0.9 7.2 — 8.1 Total (3) $ 84.9 $ 635.9 $ — $ 720.8 $ 98.0 $ 126.7 $ — $ 224.7 (1) This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries. (2) Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h). (3) Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets. December 31, 2014 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 $ 0.3 $ 25.3 $ — $ 25.6 $ 3.4 $ 1.5 $ 4.9 Equity securities: U.S. Equity 53.3 197.8 — 251.1 14.6 62.4 77.0 International Equity 54.4 225.9 — 280.3 17.6 65.5 83.1 Fixed income securities: (1) U.S. Bonds 41.3 261.8 — 303.1 62.8 — 62.8 International Bonds — 44.6 — 44.6 — — — 149.3 755.4 — 904.7 98.4 129.4 — 227.8 401(h) other benefit plan assets invested as pension assets (2) (1.5 ) (7.3 ) — (8.8 ) 1.5 7.3 — 8.8 Total (3) $ 147.8 $ 748.1 $ — $ 895.9 $ 99.9 $ 136.7 $ — $ 236.6 (1) This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries. (2) Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h). (3) Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets. The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2014. There was no level 3 activity in 2015. (in millions) International Bonds U.S. Bonds Total Beginning balance at January 1, 2014 $ 1.3 $ 0.7 $ 2.0 Net realized and unrealized gains 0.1 0.1 0.2 Sales (1.4 ) (0.8 ) (2.2 ) Ending balance at December 31, 2014 $ — $ — $ — Cash Flows We expect to contribute $1.4 million to the pension plans and $2.1 million to OPEB plans in 2016 , dependent on various factors affecting us, including our liquidity position and tax law changes. 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 2016 $ 46.9 $ 9.6 2017 29.6 10.5 2018 29.1 11.4 2019 32.6 12.2 2020 33.7 13.0 2021-2025 172.4 73.7 Savings Plans Integrys maintains a 401(k) Savings Plan for substantially all of our full-time employees. A percentage of employee contributions are matched through an employee stock ownership plan (ESOP) contribution up to certain limits. Certain union employees receive a contribution to their ESOP account regardless of their participation in the 401(k) Savings Plan. Certain employees participate in a defined contribution pension plan, in which certain amounts are contributed to an employee's account based on the employee's wages, age, and years of service. Our share of the total costs incurred under all of these plans was $9.7 million in 2015 , $8.6 million in 2014 , and $8.2 million in 2013 . |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES We have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental remediation, and enforcement and litigation matters. Energy Related Purchased Power Agreements We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. 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. The following table shows our minimum future commitments related to these purchase obligations as of December 31, 2015 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2016 2017 2018 2019 2020 Later Years Electric utility: Purchased power 2027 $ 732.6 $ 85.5 $ 53.5 $ 56.2 $ 57.5 $ 59.8 $ 420.1 Coal supply and transportation 2019 198.4 97.3 46.5 43.5 11.1 — — Natural gas utility supply and transportation 2024 198.1 43.8 42.9 42.4 27.1 14.6 27.3 Total $ 1,129.1 $ 226.6 $ 142.9 $ 142.1 $ 95.7 $ 74.4 $ 447.4 Operating Leases We lease various property, plant, and equipment with various terms in the operating leases. 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 $1.4 million , $1.6 million , and $2.3 million in 2015 , 2014 , and 2013 , respectively. Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2016 $ 0.4 2017 0.8 2018 0.6 2019 0.4 2020 0.5 Later years 12.3 Total $ 15.0 Environmental Matters Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO 2 , NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites. 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 new 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 plants and conversion to modern, efficient, natural gas generation and super-critical pulverized coal generation; • the beneficial use of ash and other products from coal-fired generating units; and • the remediation of former manufactured gas plant sites. Air Quality Sulfur Dioxide National Air Ambient Quality Standards The EPA issued a revised 1-Hour SO 2 NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies latitude in rule implementation. States have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection) and make attainment designation recommendations. If a state chooses modeling and an area does not show attainment, and sources do not agree to reductions by 2017 to allow attainment, the area would be classified as nonattainment. A plan would need to be developed requiring emission reductions to bring the area back into attainment by 2023. Alternatively, if a state opted out of modeling and instead chose to install air quality monitors, and subsequently monitored nonattainment, then it would face a 2026 compliance date. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. In March 2015, a federal court entered a consent decree between the EPA and the Sierra Club and others agreeing to specific actions related to implementing the revised standard for areas containing large sources emitting above a certain threshold level of SO 2 . The consent decree requires the EPA to complete attainment designations for certain areas with large sources by no later than July 2, 2016. We believe our fleet overall is well positioned to meet the new regulation. 8-Hour Ozone National Air Ambient Quality Standards The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to tighten (lower) the NAAQS. In October 2015, the EPA released the final rule, which lowered the limit for ground-level ozone. This is expected to cause nonattainment designations for some counties in Wisconsin with potential future impacts for our fossil-fueled power plant fleet. For nonattainment areas, the state will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020 and are in the process of reviewing and determining potential impacts resulting from this rule. Mercury and Other Hazardous Air Pollutants In December 2011, the EPA issued the final MATS rule, which imposes stringent limitations on emissions of mercury and other hazardous air pollutants from coal and oil-fired electric generating units beginning in April 2015. In addition, Wisconsin has a state mercury rule that requires a 90% reduction of mercury; however, these rules are not in effect as long as MATS is in place. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule has been remanded to the EPA to address the Supreme Court decision, but remains in effect while the EPA completes its cost evaluation. Our compliance plans currently include capital projects for our jointly owned plants to achieve the required reductions for MATS. Construction of the ReACT TM multi-pollutant control system at Weston Unit 3 is complete and startup/commissioning work is underway with an expected in-service date of July 2016. Controls for acid gases and mercury are already in operation at the Pulliam units. Although we received a one year MATS compliance extension from the WDNR for Weston Unit 3 through April 2016, this unit is shut down to complete the construction of the ReACT TM system. Climate Change In 2015, the EPA issued the Clean Power Plan, a final rule regulating GHG emissions from existing generating units, a proposed federal plan as an alternative to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. The final rule for existing fossil generating units seeks to achieve state-specific GHG emission reduction goals by 2030, and requires states to submit plans by September 6, 2016. States submitting initial plans and requesting an extension would be required to submit final plans by September 2018, either alone or in conjunction with other states. States will be required to meet interim goals over the period from 2022 through 2029, and a final goal in 2030, with the goal of reducing nationwide GHG emissions by 32% from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin of 41% below 2012 levels by 2030. The building blocks used by the EPA to determine each state's emission reduction requirements include a combination of improving power plant efficiency, increasing reliance on combined cycle natural gas units, and adding new renewable energy resources. Rules for existing, as well as new, modified, and reconstructed generating units became effective in October 2015. A draft Federal Plan and Model Trading Rule were also published in October 2015 for use in developing state plans or for use in states where a plan is not submitted or approved. In December 2015, the state of Wisconsin submitted petitions for review to the EPA of the final standards for existing as well as new, modified, and reconstructed generating units. A petition for review was also submitted jointly by the Wisconsin utilities. The utilities' petition narrowly asks the EPA to consider revising the state goal for existing units to reflect the 2013 retirement of the Kewaunee Power Station, which could lower the state's CO 2 equivalent reduction goal by about 10% . The state's petition asks for review of a number of aspects of the final rules, including an adjustment to reflect the Kewaunee Power Station retirement. In January 2016, we submitted comments on the draft Federal Plan and Model Trading Rule. We are in the process of reviewing the final rule for existing generating units to determine the potential impacts to our operations. The rule could result in significant additional compliance costs, including capital expenditures, could impact how we operate our existing fossil-fueled power plants, and could have a material adverse impact on our operating costs. In October 2015, following publication of the final rule, numerous states (including Wisconsin), trade associations, and private parties filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but on February 9, 2016, the Supreme Court stayed the effectiveness of the rule until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that review is sought, at the Supreme Court. Therefore, it is unlikely that states will move forward on the development of state plans until the litigation is complete. In addition, on February 15, 2016, the Governor of Wisconsin issued Executive Order 186, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan. We are required to report our CO 2 equivalent emissions from our electric generating facilities under the EPA Greenhouse Gases Reporting Program. For 2014, we reported aggregated CO 2 equivalent emissions of approximately 6.2 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 5.7 million metric tonnes to the EPA for 2015. The level of CO 2 and other GHG emissions vary from year to year and are dependent on the level of electric generation and mix of fuel sources, which is determined primarily by demand, the availability of the generating units, the unit cost of fuel consumed, and how our units are dispatched by MISO. We are also required to report CO 2 equivalent amounts related to the natural gas that our natural gas operations distribute and sell. For 2014, we reported aggregated CO 2 equivalent emissions of approximately 3.9 million metric tonnes to the EPA related to our distribution and sale of natural gas. Based upon our preliminary analysis of the data, we estimate that we will report CO 2 equivalent emissions of approximately 3.5 million metric tonnes to the EPA for 2015. Water Quality Clean Water Act Cooling Water Intake Structure Rule In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement and entrainment. The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit. BTA determinations must also be made by the WDNR to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8 and Weston Units 2 through 4. During 2016-2018, we plan to complete studies and evaluate options to address the EM BTA requirements at our plants. With the exception of Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at our facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit. Entrainment studies are currently being conducted at Pulliam Units 7 and 8. Steam Electric Effluent Guidelines The EPA's final steam electric effluent guidelines rule took effect in January 2016 and applies to discharges of wastewater from our power plant processes in Wisconsin. Unless pending challenges to the final guidelines are successful, the WDNR will modify the state rules and incorporate the new requirements into our facility permits, which are renewed every five years . We expect the new requirements to be phased in between 2018 and 2023 as our permits are renewed. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, these standards will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use. The final rule phases in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. The rule also requires dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are also required by the new rule, and modifications will be required at Pulliam Units 7 and 8 and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of $10 million to $20 million for these bottom ash transport systems. Land Quality Coal Combustion Residuals Rule In April 2015, the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule was entered into the Federal Register. The final rule regulates the disposal of coal combustion residuals as a non-hazardous waste. We do not expect the compliance costs will be significant because we currently have a program of beneficial utilization for most of our coal combustion products. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources. Coal Combustion Product Landfill Sites We aggressively seek environmentally acceptable, beneficial uses for our coal combustion products. However, some coal combustion products have been, and to a small degree continue to be, managed in company-owned, licensed landfills. Some early designed and constructed landfills have at times required some level of monitoring or remediation. Where we have become aware of these conditions, and where necessary, we have worked to define the nature and extent of the impact, if any, and work has been performed to address these conditions. During 2015 , 2014 , and 2013 , landfill remediation expenses were not material. See Note 9, Asset Retirement Obligations, for more information about obligations related to these sites. Renewables, Efficiency, and Conservation Wisconsin Act 141 In 2006, Wisconsin revised the requirements for renewable energy generation by enacting Act 141. Act 141 established a goal that 10% of all electricity consumed in Wisconsin be generated by renewable resources by December 31, 2015. Under Act 141, we are required to increase our renewable energy percentage to 9.74% . To comply with these requirements, we constructed the Crane Creek wind park. We also rely on renewable energy purchases to meet our renewable portfolio standard commitments. We are in compliance with Act 141's 2015 standard and have entered into agreements for renewable energy credits, that should allow us to remain in compliance through 2023. If market conditions are favorable, we may purchase more renewable energy credits. Act 141 assigned responsibility for the administration of energy efficiency, conservation, and renewable programs to the PSCW and/or contracted third parties. The funding required by Act 141 for 2015 was 1.2% of our annual operating revenues. 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, some of which are in the EPA Superfund Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure. In addition, some of these sites are coordinating the investigation and cleanup subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2015 2014 Regulatory assets $ 104.4 $ 102.3 Reserves for future remediation 83.5 86.3 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. Weston Title V Air Permit In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, we challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, a new permit change was challenged and added to the case. The administrative law judge (ALJ) dismissed some of the petition issues relating to the averaging period and monitoring issues. In May 2014, the WDNR issued a Notice of Violation (NOV) alleging that we failed to maintain a minimum sorbent feed rate prior to the Continuous Emissions Monitoring System certification and included an issue related to reporting NOx emissions from the Weston Unit 4 auxiliary boiler. In June 2015, the WDNR issued a NOV alleging that we failed to comply with mercury reporting requirements related to challenged matters in the 2013 Weston Title V permit. The ALJ denied our request to issue a stay or confirm that a statutory stay applies to the requirements identified in the NOV. The contested case has been stayed for a period of months, and no hearing date has been set. We do not expect these matters to have a material impact on our financial statements. Consent Decrees Consent Decree – Weston and Pulliam In November 2009, the EPA issued a NOV to us, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. We entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the U.S. District Court for the Eastern District of Wisconsin in March 2013. The final Consent Decree includes: • the installation of emission control technology, including ReACT™ on Weston 3, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects totaling $6.0 million , and • a civil penalty of $1.2 million . As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023. We received approval from the PSCW in our rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. The majority of the beneficial environmental projects proposed by us have been approved by the EPA. We are currently working with the EPA on certain changes to the environmental projects, but these changes are not expected to materially impact the overall cost. Also, in May 2010, we received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of December 31, 2015 . It is unknown whether the Sierra Club will take further action in the future. Joint Ownership Power Plants Consent Decree – Columbia and Edgewater In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, Wisconsin Electric (former co-owner of an Edgewater unit), and us. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. We, Wisconsin Power and Light, Madison Gas and Electric, and Wisconsin Electric entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013. The final Consent Decree includes: • the installation of emission control technology, including scrubbers at the Columbia plant, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects, with our portion totaling $1.3 million , and • Our portion of a civil penalty and legal fees totaling $0.4 million . As mentioned above, the Consent Decree contains a requirement to refuel, repower, or retire Edgewater Unit 4, of which we are a joint owner, by no later than December 31, 2018. In the first quarter of 2015, management of the joint owners recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available. All of the beneficial environmental projects that we proposed have been approved by the EPA. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.3 $ — $ — $ 0.3 FTRs — — 2.0 2.0 Total derivative assets $ 0.3 $ — $ 2.0 $ 2.3 Derivative liabilities Natural gas contracts $ 0.9 $ — $ — $ 0.9 Petroleum products contracts 0.5 — — 0.5 Coal contracts — 4.7 — 4.7 Total derivative liabilities $ 1.4 $ 4.7 $ — $ 6.1 December 31, 2014 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ — $ 0.1 $ — $ 0.1 FTRs — — 2.2 2.2 Total derivative assets $ — $ 0.1 $ 2.2 $ 2.3 Derivative liabilities Natural gas contracts $ 2.2 $ — $ — $ 2.2 FTRs — — 0.3 0.3 Petroleum products contracts 1.1 — — 1.1 Coal contracts — 1.2 2.2 3.4 Total derivative liabilities $ 3.3 $ 1.2 $ 2.5 $ 7.0 The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets. See Note 20, Derivative Instruments, for more information . The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2015 2014 2013 Balance at the beginning of the period $ (0.3 ) $ (1.3 ) $ (5.4 ) Realized and unrealized (losses) gains (10.7 ) (1.0 ) 3.3 Purchases 9.8 4.3 3.2 Sales (0.1 ) — (0.2 ) Settlements (1.4 ) (3.5 ) (2.2 ) Net transfers out of level 3 4.7 1.2 — Balance at the end of the period $ 2.0 $ (0.3 ) $ (1.3 ) Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on our income statements. Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2015 December 31, 2014 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,289.4 $ 1,350.4 $ 1,165.1 $ 1,286.2 Long-term debt to parent, including current portion 2.9 3.0 5.4 5.7 Preferred stock * — — 51.2 52.0 * On November 13, 2015, we redeemed all of our outstanding shares of preferred stock. See Note 12, Preferred Stock, for more information . |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS The following table shows our derivative assets and derivative liabilities: December 31, 2015 December 31, 2014 (in millions) Balance Sheet Presentation Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Natural gas contracts Other Current $ 0.3 $ 0.9 $ 0.1 $ 2.1 Natural gas contracts Other Long-term — — — 0.1 Petroleum product contracts Other Current — 0.5 — 1.1 FTRs Other Current 2.0 — 2.2 0.3 Coal contracts Other Current — 3.3 — 2.4 Coal contracts Other Long-term — 1.4 — 1.0 Other Current 2.3 4.7 2.3 5.9 Other Long-term — 1.4 — 1.1 Total $ 2.3 $ 6.1 $ 2.3 $ 7.0 Our estimated notional volumes and gains (losses) were as follows: December 31, 2015 December 31, 2014 December 31, 2013 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains (Losses) Natural gas 22.9 Dth $ (4.9 ) 20.0 Dth $ 0.6 15.5 Dth $ (0.8 ) Petroleum products 6.1 gallons (1.7 ) 5.3 gallons (0.1 ) 2.8 gallons (0.1 ) FTRs 9.0 MWh 3.3 8.7 MWh 3.2 9.1 MWh 5.1 Total $ (3.3 ) $ 3.7 $ 4.2 At December 31, 2015 , and December 31, 2014 , we had posted collateral of $17.6 million and $6.6 million , respectively, 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, 2015 December 31, 2014 Derivative Derivative Derivative Derivative (in millions) Assets Liabilities Assets Liabilities Gross amount recognized on the balance sheet $ 2.3 $ 6.1 $ 2.3 $ 7.0 Gross amount not offset on the balance sheet * (0.3 ) (1.4 ) (0.4 ) (3.6 ) Net amount $ 2.0 $ 4.7 $ 1.9 $ 3.4 * Includes cash collateral posted of $1.1 million and $3.2 million as of December 31, 2015 and December 31, 2014 , respectively. |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 12 Months Ended |
Dec. 31, 2015 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT 2016 Wisconsin Rate Order In April 2015, we initiated a rate proceeding with the PSCW. In December 2015, the PSCW issued a final written order, effective January 1, 2016. The order, which reflects a 10.0% ROE and a common equity component average of 51.0% , authorized a net retail electric rate decrease of $7.9 million ( -0.8% ) and a net retail natural gas rate decrease of $6.2 million ( -2.1% ). Based on the order, the PSCW will continue to allow escrow treatment for ATC and MISO network transmission expenses, including any future SSR payments. This allows us to defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. In addition, the PSCW approved a deferral for ReACT™, which requires us to defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level through 2016. Fuel costs will continue to be monitored using a 2% tolerance window. 2015 Wisconsin Rate Order In April 2014, we initiated a rate proceeding with the PSCW. In December 2014, the PSCW issued a final written order, effective January 1, 2015. It authorized a net retail electric rate increase of $24.6 million and a net retail natural gas rate decrease of $15.4 million , reflecting a 10.20% ROE. The order also included a common equity component of 50.28% . The PSCW approved a change in rate design, which includes higher fixed charges to better match the related fixed costs of providing service. In addition, the order continued to exclude a decoupling mechanism that was terminated beginning January 1, 2014. The primary driver of the increase in retail electric rates was higher costs of fuel for electric generation of approximately $42.0 million . In addition, 2015 rates include approximately $9.0 million of lower refunds to customers related to decoupling over-collections. In 2015 rates, we refunded approximately $4.0 million to customers related to 2013 decoupling over-collections compared with refunding approximately $13.0 million to customers in 2014 rates related to 2012 decoupling over-collections. Absent these adjustments for electric fuel costs and decoupling refunds, we would have realized an electric rate decrease. In addition, we received approval from the PSCW to defer and amortize the undepreciated book value associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. See Note 18, Commitments and Contingencies, for more information . The PSCW is allowing us to escrow ATC and MISO network transmission expenses for 2015 and 2016. As a result, we defer as a regulatory asset or liability the differences between actual transmission expenses and those included in rates until a future rate proceeding. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a 2% tolerance window. The retail natural gas rate decrease was driven by the approximate $16.0 million year-over-year negative impact of decoupling refunds to and collections from customers. In 2015 rates, we refunded approximately $8.0 million to customers related to 2013 decoupling over-collections compared with recovering approximately $8.0 million from customers in 2014 rates related to 2012 decoupling under-collections. Absent the adjustment for decoupling refunds to and collections from customers, we would have realized a retail natural gas rate increase. 2014 Wisconsin Rate Order In March 2013, we initiated a rate proceeding with the PSCW. In December 2013, the PSCW issued a final written order, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million , reflecting a 10.20% ROE. The order also included a common equity component average of 50.14% . The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase discussed below, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case, as discussed below. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 related to the Pulliam and Weston sites. See Note 18, Commitments and Contingencies, for more information . Additionally, the order required us to terminate our existing decoupling mechanism, beginning January 1, 2014. 2013 Wisconsin Rate Order In March 2012, we initiated a rate proceeding with the PSCW. In December 2012, the PSCW issued a final written order, effective January 1, 2013. The order included a $28.5 million retail electric rate increase, partially offset by the actual 2012 fuel refund of $20.5 million . The difference between the 2012 fuel refund and the rate increase was deferred for recovery in 2014 rates. As a result, there was no change to customers' 2013 retail electric rates. The order also included a $3.4 million retail natural gas rate decrease. The order reflected a 10.30% ROE and a common equity component average of 51.61% . The rate changes included deferrals of $7.3 million for retail electric and $2.1 million for retail natural gas of pension and other employee benefit costs that were recovered in 2014 rates. In addition, we were authorized recovery of $5.9 million related to income tax amounts previously expensed due to the Federal Health Care Reform Act. As a result, this amount was recorded as a regulatory asset in 2012, and recovery from customers began in 2013. The order also authorized the recovery of direct CSAPR costs incurred through the end of 2012. Lastly, the order authorized us to switch from production tax credits to a Section 1603 Grant for the Crane Creek wind project. A decoupling mechanism for natural gas and electric residential and small commercial and industrial customers was approved on a pilot basis as part of the order. The mechanism was based on total rate case-approved margins, rather than being calculated on a per-customer basis. The mechanism did not cover all customer classes, and it included an annual $14.0 million cap for electric service and an annual $8.0 million cap for natural gas service. Amounts recoverable from or refundable to customers were subject to these caps. 2015 Michigan Rate Order In October 2014, we initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement. The order authorized a retail electric rate increase of $4.0 million to be implemented over three years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflect a 10.2% ROE and a common equity component average of 50.48% . The increase reflects the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflects the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, we will discontinue the deferral of Fox Energy Center costs and will begin amortizing this deferral along with the deferral associated with the termination of a tolling agreement related to the Fox Energy Center. We also received approval from the MPSC to defer and amortize the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. Lastly, we will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018. |
SEGMENTS INFORMATION
SEGMENTS INFORMATION | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
SEGMENTS OF BUSINESS | SEGMENT INFORMATION At December 31, 2015 , we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are our electric utility operations and the natural gas utility operations. The other segment includes non-utility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC. Operating income is used to measure segment profitability and to allocate resources to our businesses. All of our operations and assets are located within the United States. The table below presents information related to our reportable segments: Regulated Utilities 2015 (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated External revenues $ 1,187.8 $ 295.5 $ 1,483.3 $ — $ — $ 1,483.3 Intersegment revenues — 10.7 10.7 0.8 (11.5 ) — Other operation and maintenance 424.3 69.6 493.9 0.3 (0.8 ) 493.4 Depreciation and amortization 103.7 17.0 120.7 0.3 — 121.0 Operating income 194.0 34.0 228.0 0.1 — 228.1 Other income, net 15.6 0.4 16.0 9.6 — 25.6 Interest expense 43.0 10.2 53.2 0.3 — 53.5 Capital expenditures 319.4 51.6 371.0 — — 371.0 Total assets 3,718.9 697.9 4,416.8 88.3 — 4,505.1 Regulated Utilities 2014 (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated External revenues $ 1,223.7 $ 459.9 $ 1,683.6 $ — $ — $ 1,683.6 Intersegment revenues — 12.4 12.4 1.4 (13.8 ) — Other operation and maintenance 425.8 73.5 499.3 0.4 — 499.7 Depreciation and amortization 100.5 16.2 116.7 0.6 (0.5 ) 116.8 Operating income 204.8 52.4 257.2 0.4 — 257.6 Other income, net 11.7 0.6 12.3 12.9 — 25.2 Interest expense 45.1 10.2 55.3 2.1 — 57.4 Capital expenditures 272.7 49.3 322.0 — — 322.0 Total assets 3,503.0 680.9 4,183.9 85.4 — 4,269.3 Regulated Utilities 2013 (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated External revenues $ 1,243.0 $ 337.5 $ 1,580.5 $ — $ — $ 1,580.5 Intersegment revenues — 10.9 10.9 1.4 (12.3 ) — Other operation and maintenance 405.0 65.1 470.1 0.3 — 470.4 Depreciation and amortization 93.7 15.6 109.3 0.6 (0.5 ) 109.4 Operating income 189.5 50.0 239.5 0.5 — 240.0 Other income, net 9.9 0.2 10.1 13.4 — 23.5 Interest expense 33.0 8.5 41.5 2.2 — 43.7 Capital expenditures 590.3 37.4 627.7 — — 627.7 Total assets 3,233.6 632.3 3,865.9 85.7 — 3,951.6 |
QUARTERLY FINANCIAL INFORMATION
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) | QUARTERLY FINANCIAL INFORMATION (Unaudited) (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2015 Operating revenues $ 425.0 $ 330.3 $ 390.8 $ 337.2 $ 1,483.3 Operating income 69.9 44.2 88.5 25.5 228.1 Net income attributed to common shareholder 39.0 22.6 50.3 10.6 $ 122.5 2014 Operating revenues $ 556.0 $ 359.0 $ 370.9 $ 397.7 $ 1,683.6 Operating income 87.4 36.3 77.7 56.2 257.6 Net income attributed to common shareholder 50.3 17.1 42.2 28.0 137.6 Due to various factors, the quarterly results of operations are not necessarily comparable. |
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS | 12 Months Ended |
Dec. 31, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | NEW ACCOUNTING PRONOUNCEMENTS Revenue Recognition In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and can either be applied retrospectively or as a cumulative-effect adjustment as of the date of adoption. We are currently assessing the effects this guidance may have on our financial statements. Classification and Measurement of Financial Instruments In January 2016, the FASB issued ASU 2016-01, Classification and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. We are currently assessing the effects this guidance may have on our financial statements. Leases In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We are currently assessing the effects this guidance may have on our financial statements. |
SCHEDULE II VALUATION AND QUALI
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS | 12 Months Ended |
Dec. 31, 2015 | |
Valuation and Qualifying Accounts [Abstract] | |
Valuation and Qualifying Accounts | SCHEDULE II WISCONSIN PUBLIC SERVICE CORPORATION VALUATION AND QUALIFYING ACCOUNTS Allowance for Doubtful Accounts (in millions) Balance at Beginning of the Period Expense (1) Net Write-offs (2) Balance at End of the Period December 31, 2015 $ 3.2 $ 6.7 $ (7.4 ) $ 2.5 December 31, 2014 $ 2.5 $ 7.3 $ (6.6 ) $ 3.2 December 31, 2013 $ 2.5 $ 5.2 $ (5.2 ) $ 2.5 (1) Net of recoveries. (2) Represents amounts written off to the reserve, net of adjustments to regulatory assets. |
SUMMARY OF SIGNIFICANT ACCOUN34
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Nature of operations | On June 29, 2015, Wisconsin Energy Corporation acquired our parent company, Integrys, and changed its name to WEC Energy Group. See Note 2, Merger, for more information on the acquisition. We are an electric and natural gas utility company that services customers in northeastern Wisconsin and Michigan's Upper Peninsula. We are subject to the jurisdiction of, and regulation by, the PSCW and the MPSC, which have general supervisory and regulatory powers over virtually all phases of the public utility industry in Wisconsin and Michigan, respectively. We are also subject to the jurisdiction of the FERC, which regulates our natural gas pipelines and wholesale electric rates. |
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. At December 31, 2015 , we had one wholly owned subsidiary, WPS Leasing. The financial statements include our accounts and the accounts of our wholly owned subsidiary. These financial statements also reflect our proportionate interests in certain jointly owned utility facilities. |
Investment | 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. |
Reclassifications | As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below. Statements of Income • Certain amortizations of deferrals were reclassified from other operation and maintenance to cost of sales; depreciation and amortization; and other income, net. • Payroll taxes of $8.3 million and $8.9 million for the years ended December 31, 2014 and 2013, respectively, were reclassified from taxes other than income taxes to other operation and maintenance. The taxes other than income taxes line item was also renamed to property and revenue taxes. • Certain expenses in cost of sales were reclassified to operating revenues, other operation and maintenance, and depreciation and amortization. The amounts reclassified to other operation and maintenance were $5.9 million and $6.7 million for the years ended December 31, 2014 and 2013, respectively. • Certain expenses in other operation and maintenance were reclassified to cost of sales, and depreciation and amortization. The amounts reclassified to other cost of sales were $3.1 million and $5.6 million for the years ended December 31, 2014 and 2013, respectively. Balance Sheets • Current regulatory assets of $1.4 million and $23.6 million were reclassified to accounts receivable and long-term regulatory assets, respective ly, at December 31, 2014. • Current regulatory liabilities of $6.1 million and $15.1 million were recl assified to other current liabilities and long-t erm regulatory liabilities, respectivel y, at December 31, 2014. • During the fourth quarter of 2015, we early implemented ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. As a result, debt issuance costs of $0.6 million and $8.8 million , previously reported as other current assets and other long-term assets, respectively, were reclassified to offset long-term debt on the December 31, 2014 balance sheet. • During the fourth quarter of 2015, we also early implemented ASU 2015-17, Balance Sheet Classification of Deferred Taxes. Since we adopted this ASU on a retrospective basis, we reclassified current deferred income taxes of $3.8 million , previously reported as a component of other current liabilities, to long-term deferred income tax liabilities on the December 31, 2014 balance sheet. Statements of Cash Flows • Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections. |
Cash and cash equivalents | Cash and cash equivalents include marketable debt securities acquired three months or less from maturity. |
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 return on common equity than authorized by the PSCW. • 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. 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 revenue. 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 and natural gas service to customers in northeastern Wisconsin and Michigan's Upper Peninsula. 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. As a result, we did not have any significant concentrations of credit risk at December 31, 2015 . In addition, there were no customers that accounted for more than 10% of our revenues for the year ended December 31, 2015 . |
Inventories | Substantially all fossil fuels, materials and supplies, and natural gas in storage inventories are recorded using the weighted-average cost method of accounting. |
Regulatory accounting | 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 revenue 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 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 is three years . If software is retired prior to being fully amortized, the difference is recorded as a loss on the income statement. We receive grants related to certain renewable generation projects under federal and state grant programs. Our policy is to reduce the depreciable basis of the qualifying project by the grant received. We then reflect the benefit of the grant in income over the life of the related renewable generation project through a reduction in depreciation expense. We record property, plant, and equipment at cost. Cost includes material, labor, and overhead. Utility property also includes AFUDC – Equity. Additions to and significant replacements of property are charged to property, plant, and equipment at cost; minor items are charged to 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 applicable regulators. |
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 stockholders' 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 7.92% , 8.08% , and 8.61% for 2015, 2014, and 2013, respectively. Our average AFUDC wholesale rates were 5.10% , 6.99% , and 2.64% for 2015, 2014, and 2013, respectively. |
Emission allowances | We account for emission allowances as inventory at average cost by vintage year. Charges to income result when allowances are used in operating our generation plants. These charges are included in the costs subject to the fuel window rules. Gains on sales of allowances are returned to ratepayers. |
Goodwill | Goodwill is subject to an annual impairment test. Our natural gas utility reporting unit contains goodwill and performed its annual goodwill impairment test as of April 1, 2015. Interim impairment tests are performed when impairment indicators are present. The carrying amount of the reporting unit's goodwill is considered not recoverable if the carrying amount of the reporting unit exceeds the reporting unit's fair value. An impairment loss is recorded for the excess of the carrying amount of the goodwill over its implied fair value. |
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. A 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 AROs are accreted to their present value each period using the credit-adjusted risk-free interest rate associated with the expected settlement dates of the AROs. This rate is determined when the obligation is 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. |
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 18, Commitments and Contingencies, for more information . We record environmental remediation liabilities when site assessments indicate remediation is probable and we can reasonably estimate the loss or a range of possible losses. The estimate includes both our share of the liability and any additional amounts that will not be paid by other potential 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 applicable state's Commission'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. |
Income taxes | We and our subsidiary are included in the consolidated United States income tax return filed by Integrys for all tax periods up to and including the tax year ended June 29, 2015. For all tax periods after June 29, 2015, we and our subsidiary are included within the WEC Energy Group consolidated return. Similarly, we and our subsidiary are party to a tax allocation arrangement with Integrys and its consolidated subsidiaries for all tax periods up to and including June 29, 2015, and are a party to a tax allocation arrangement with WEC Energy Group and its consolidated subsidiaries for tax periods ending after June 29, 2015. Deferred income taxes have been recorded to recognize the expected future tax consequences of events that have been included in the financial statements by using currently enacted tax rates for the differences between the income tax basis of assets and liabilities and the basis reported in the financial statements. We record valuation allowances for deferred income tax assets unless it is more likely than not that the benefit will be realized in the future. We defer certain adjustments made to income taxes that will impact future rates and record regulatory assets or liabilities related to these adjustments. We use the deferral method of accounting for investment tax credits (ITCs). Under this method, we record the ITCs as deferred credits and amortize such credits as a reduction to the provision for income taxes over the life of the asset that generated the ITCs. ITCs that do not reduce income taxes payable for the current year are eligible for carryover and recognized as a deferred income tax asset. We report interest and penalties accrued, related to income taxes, as a component of income tax expense in our income statements. We record excess tax benefits from stock-based compensation awards when the actual tax benefit is realized. We follow the tax law ordering approach to determine when the tax benefit has been realized. Under this approach, the tax benefit is realized in the year it reduces taxable income. Current year stock-based compensation deductions are assumed to be used before any net operating loss carryforwards. |
Guarantees | We follow the guidance of the Guarantees Topic of the FASB ASC, which requires that the guarantor recognize, at the inception of the guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. |
Employee benefits | The costs of pension and OPEB are expensed over the periods during which employees render service. The benefit costs associated with employee benefit plans are allocated among WEC Energy Group's subsidiaries based on current employment status and actuarial calculations, as applicable. Our regulators allow recovery in rates for the net periodic benefit cost calculated under GAAP. |
Fair value | 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. The valuation for FTRs is derived from historical data from MISO, which is considered a Level 3 input. Derivatives are transferred between levels of the fair value hierarchy due to observable pricing becoming available. We recognize transfers at the value as of the end of the reporting period. Due to the short-term nature of cash and cash equivalents, net accounts receivable, accounts payable, and short-term borrowings, the carrying amount for each such item approximates fair value. The fair values of long-term debt, including the current portion of long-term debt, are estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis. |
Derivative instruments | We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by the PSCW and the MPSC. We record derivative instruments on our balance sheets as an asset or liability measured at fair value, unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. We classify derivative assets and liabilities as current or long-term on our balance sheets based on the maturities of the underlying contracts. 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. |
Customer deposits and credit balances | When utility customers apply for new service, they may be required to provide a deposit for the service. 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 accounts payable on our balance sheets. |
SUMMARY OF SIGNIFICANT ACCOUN35
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Schedule of inventory | Our inventory as of December 31 consisted of: (in millions) 2015 2014 Fossil fuel $ 76.4 $ 48.9 Materials and supplies 40.5 39.2 Natural gas in storage 28.1 36.1 Total $ 145.0 $ 124.2 |
Schedule of annual utility composite depreciation rates | Annual utility composite depreciation rates are shown below: Annual Utility Composite Depreciation Rates 2015 2014 2013 Electric 2.70 % 2.73 % 2.79 % Natural gas 2.15 % 2.17 % 2.19 % |
Schedule of total AFUDC | We recorded the following AFUDC for the years ended December 31: (in millions) 2015 2014 2013 AFUDC – Debt $ 6.1 $ 4.6 $ 3.8 AFUDC – Equity 15.1 11.0 9.9 |
MERGER (Tables)
MERGER (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Severance expense by segment [Table Text Block] | The severance expense was recorded in the following segments: (in millions) 2015 Electric utility segment $ 3.6 Natural gas utility segment 1.0 Total severance expense $ 4.6 |
ACQUISITION (Tables)
ACQUISITION (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Schedule of assets acquired and liabilities assumed | The purchase price was allocated based on the estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition, as follows: (in millions) Assets acquired (1) Inventories – materials and supplies $ 3.0 Other current assets 0.4 Property, plant, and equipment 374.4 Other long-term assets (2) 15.6 Total assets acquired $ 393.4 Liabilities assumed Accounts payable $ 1.8 Total liabilities assumed $ 1.8 (1) Relates to the electric utility segment. (2) Intangible assets recorded for contractual services agreements. See Note 10, Goodwill and Other Intangible Assets, for more information . |
RELATED PARTIES (Tables)
RELATED PARTIES (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Schedule of information summarizing other related party transactions | The table below includes information summarizing other transactions entered into with related parties: (in millions) December 31, 2015 December 31, 2014 Accounts receivable Service provided to ATC $ 0.5 $ 0.9 Notes payable * Integrys 2.9 5.4 Accounts payable Network transmission services from ATC 8.5 8.2 Liability related to income tax allocation Integrys 5.4 6.1 * WPS Leasing, our consolidated subsidiary, has a note payable to Integrys. At December 31, 2015 and 2014 , the current portion of the note payable was $2.9 million and $2.5 million , respectively. |
Schedule of activity associated with related party transactions | The following table shows activity associated with our other related party transactions for the years ended December 31: (in millions) 2015 2014 2013 Electric transactions Sales to UPPCO (1) $ — $ 15.3 $ 22.8 Sales to ITF (2) — 0.1 — Sales to Wisconsin Electric 0.1 — — Natural gas transactions Sales to Wisconsin Electric 0.4 — — Sales to IES (3) — 0.6 0.5 Purchases from IES (3) — 2.5 0.9 Interest expense (4) Integrys 0.3 0.5 0.5 Transactions with equity-method investees Charges from ATC for network transmission services 101.3 99.0 98.4 Charges to ATC for services and construction 10.3 8.6 9.5 Purchases of energy from WRPC 3.8 3.7 3.7 Charges to WRPC for operations 1.1 1.4 0.9 Equity earnings from WPS Investments, LLC (5) 7.7 9.5 10.2 Sales of electricity to AMP Trillium, LLC (6) 0.1 — — (1) Integrys sold UPPCO in August 2014. (2) In February 2016, an agreement was entered into to sell ITF. This sale is scheduled to close in the first quarter of 2016. (3) Integrys sold IES's retail energy business in November 2014. (4) WPS Leasing has a note payable to Integrys. (5) WPS Investments, LLC is an indirect wholly-owned subsidiary of WEC Energy Group that is jointly owned by Integrys and us. WPS Investments, LLC invests in ATC, a for-profit, transmission-only company regulated by the FERC. At December 31, 2015 , we had an 10.83% interest in WPS Investments, LLC accounted for under the equity method. Our ownership percentage has continued to decrease as additional equity contributions are made by Integrys to WPS Investments, LLC. (6) In November 2015, ITF, an indirect wholly-owned subsidiary of Integrys, sold its ownership interest in AMP Trillium, LLC, a joint venture between ITF and AMP Americas, LLC. This joint venture owned and operated compressed natural gas fueling stations. |
SUPPLEMENTAL CASH FLOW INFORM39
SUPPLEMENTAL CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block] | (in millions) 2015 2014 2013 Cash paid for interest, net of amount capitalized $ 58.1 $ 56.8 $ 43.9 Cash paid (received) for income taxes, net of refunds 14.5 (6.2 ) (27.3 ) Significant non-cash transactions: Construction costs funded through accounts payable 70.5 54.0 37.3 |
REGULATORY ASSETS AND LIABILI40
REGULATORY ASSETS AND LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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) 2015 2014 See Note Regulatory assets (1) (2) Unrecognized pension and OPEB costs (3) $ 176.6 $ 185.6 17 Environmental remediation costs (4) 104.4 103.8 18 Income tax related items (5) 40.8 32.7 Termination of a tolling agreement with Fox Energy Company LLC 39.1 44.6 3 Crane Creek production tax credits (6) 30.9 32.2 De Pere Energy Center (7) 19.0 21.4 Energy costs recoverable through rate adjustments (8) 12.0 12.6 Other 39.9 25.6 Total regulatory assets $ 462.7 $ 458.5 Balance Sheet Presentation Current assets (9) $ 0.2 $ 1.4 Regulatory assets 462.5 457.1 Total regulatory assets $ 462.7 $ 458.5 (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 above. (2) As of December 31, 2015 , we had $21.0 million of regulatory assets not earning a return. (3) Represents the unrecognized future pension and OPEB costs resulting from actuarial gains and losses on defined benefit and OPEB plans. (4) As of December 31, 2015, we had not yet made cash expenditures for $83.5 million of these environmental remediation costs. The recovery of these costs depends on the timing of the actual expenditures. (5) Adjustments related to deferred income taxes. As the related temporary differences reverse, we prospectively collect taxes from customers for which deferred taxes were recorded in prior years. (6) In 2012, we elected to claim and subsequently received a Section 1603 Grant for the Crane Creek wind project in lieu of the production tax credit. As a result, we reversed previously recorded production tax credits. We also reduced the depreciable basis of the qualifying facility by the amount of the grant proceeds, which will result in a reduction of depreciation and amortization expense over a 12 -year period. We recorded a regulatory asset for the deferral of previously recorded production tax credits and are authorized recovery of this net regulatory asset through 2039. (7) Prior to purchasing the De Pere Energy Center in 2002, we had a long-term power purchase contract with them that was accounted for as a capital lease. As a result of the purchase, the capital lease obligation was reversed, and the difference between the capital lease asset and the purchase price was recorded as a regulatory asset. We are authorized recovery of this regulatory asset through 2023. (8) Represents energy costs that will be recovered from customers in the future. (9) Short-term regulatory assets are recorded in accounts receivable and accrued unbilled revenues on our balance sheets. |
Schedule of Regulatory Liabilities | The following regulatory liabilities were reflected on our balance sheets as of December 31: (in millions) 2015 2014 See Note Regulatory liabilities Removal costs (1) $ 243.7 $ 243.9 Energy costs refundable through rate adjustments (2) 29.4 6.0 Crane Creek depreciation deferral (3) 8.3 8.7 Unrecognized pension and OPEB costs (4) 1.0 42.4 17 Decoupling — 12.3 21 Other 11.2 11.2 Total regulatory liabilities $ 293.6 $ 324.5 Balance Sheet Presentation Other current liabilities $ 3.6 $ 6.1 Regulatory liabilities 290.0 318.4 Total regulatory liabilities $ 293.6 $ 324.5 (1) Represents amounts collected from customers to cover the cost of future removal of property, plant, and equipment. (2) Represents energy costs that will be refunded to customers in the future. (3) Represents the book depreciation taken on the Crane Creek wind project prior to our election to claim a Section 1603 Grant for the project in lieu of the production tax credit. See more information in the regulatory assets section above. (4) Represents the unrecognized future OPEB costs resulting from actuarial gains on OPEB plans. We will amortize this regulatory liability into net periodic benefit cost over the average remaining service life of each plan. |
PROPERTY, PLANT, AND EQUIPMENT
PROPERTY, PLANT, AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Schedule of property, plant, and equipment | Property, plant, and equipment consisted of the following utility and non-utility assets at December 31: (in millions) 2015 2014 Electric utility $ 3,722.8 $ 3,587.4 Natural gas utility 818.4 773.1 Total utility plant 4,541.2 4,360.5 Less: Accumulated depreciation 1,559.6 1,495.9 Net 2,981.6 2,864.6 CWIP 434.2 248.7 Plant to be retired, net * — 12.5 Net utility plant 3,415.8 3,125.8 Non-utility plant 8.9 15.2 Less: Accumulated depreciation 6.1 10.0 Net non-utility plant 2.8 5.2 Total property, plant, and equipment $ 3,418.6 $ 3,131.0 * In connection with the Consent Decree with the EPA, we retired Weston 1 and Pulliam Units 5 and 6 on June 1, 2015. See Note 18, Commitments and Contingencies, for more information regarding the Consent Decree. |
JOINTLY OWNED UTILITY FACILIT42
JOINTLY OWNED UTILITY FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Jointly Owned Utility Plant, Net Ownership Amount [Abstract] | |
Schedule of our share of significant jointly owned electric generating facilities | The amounts were as follows at December 31, 2015 : (in millions, except for percentages and MWs) Weston 4 Columbia Energy Center Units 1 and 2 Edgewater Unit 4 Ownership 70.0 % 31.8 % 31.8 % Our share of rated capacity (MWs) * 374.5 352.9 96.3 In-service date 2008 1975 and 1978 1969 Utility plant $ 591.5 $ 404.6 $ 47.6 Accumulated depreciation $ (150.5 ) $ (122.6 ) $ (30.6 ) CWIP $ 5.9 $ 23.4 $ 0.4 * Based on expected capacity ratings for summer 2016. The summer period is the most relevant for capacity planning purposes. This is a result of continually reaching demand peaks in the summer months, primarily due to air conditioning demand. |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes to asset retirement obligations | The following table shows changes to our AROs: (in millions) 2015 2014 2013 Balance as of January 1 $ 20.3 $ 18.0 $ 16.7 Accretion 1.2 1.0 0.9 Additions and revisions to estimated cash flows (1) 11.4 (1 ) 1.5 (2 ) 0.5 Liabilities settled (0.2 ) (0.2 ) (0.1 ) Balance as of December 31 $ 32.7 $ 20.3 $ 18.0 (1) An ARO of $9.0 million was recorded for the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities rule passed by the EPA in April 2015. See Note 18, Commitments and Contingencies, for more information on this rule. In addition, we revised the AROs recorded for our fly-ash landfills due to changes in estimated removal costs and settlement dates. (2) We revised the AROs recorded for the asbestos at our electric generation facilities primarily due to changes in estimated settlement dates. |
GOODWILL AND OTHER INTANGIBLE44
GOODWILL AND OTHER INTANGIBLE ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Assets Disclosure [Abstract] | |
Schedule of identifiable intangible assets other than goodwill | The identifiable intangible assets other than goodwill listed below are part of other long-term assets on our balance sheets. December 31, 2015 December 31, 2014 (in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 15.6 $ (7.5 ) $ 8.1 $ 15.6 $ (4.3 ) $ 11.3 Unamortized intangible assets 0.4 — 0.4 — — — Total intangible assets $ 16.0 $ (7.5 ) $ 8.5 $ 15.6 $ (4.3 ) $ 11.3 * Represents contractual service agreements that provide for major maintenance and protection against unforeseen maintenance costs related to the combustion turbine generators at the Fox Energy Center. The remaining weighted-average amortization period for these intangible assets at December 31, 2015 , was approximately three years . |
COMMON EQUITY (Tables)
COMMON EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
Schedule of stock-based compensation expense and the related deferred tax benefit recognized in income | The following table reflects the stock-based compensation expense and the related deferred income tax benefit recognized in income for the years ended December 31 : (in millions) 2015 2014 2013 Stock options $ — $ 1.0 $ 0.7 Performance stock rights 1.3 6.3 1.1 Restricted share units 3.5 3.8 3.4 Total stock-based compensation expense $ 4.8 $ 11.1 $ 5.2 Deferred income tax benefit $ 1.9 $ 4.4 $ 2.1 |
Summary of stock options, performance stock rights, and restricted share units activity | A summary of the activity for our stock-based compensation awards for the year ended December 31, 2015 , is presented below: Stock Options Performance Stock Rights Restricted Stock Units Outstanding as of January 1, 2015 5,714 13,937 70,544 Granted — — 30,174 Dividend equivalents N/A N/A 1,267 Transferred — — (166 ) Exercised/Distributed/Vested and Released * (2,752 ) (2,229 ) (28,428 ) Settled as a result of WEC Merger (2,962 ) (21,263 ) (73,391 ) Adjustment for performance stock rights distributed or settled N/A 9,555 N/A Outstanding as of December 31, 2015 — — — * The intrinsic value of restricted stock unit awards vested and released was $2.2 million . The intrinsic value of stock options exercised and shares distributed for performance stock rights was not significant. |
PREFERRED STOCK (Tables)
PREFERRED STOCK (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Class of Stock Disclosures [Abstract] | |
Schedule of outstanding shares of preferred stock | The following table shows preferred stock authorized and outstanding at December 31, 2015 and 2014 : 2015 Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Preferred Stock 1,000,000 — N/A N/A 2014 (in millions, except share and per share amounts) Shares Authorized Shares Outstanding Redemption Price Per Share Total $100 par value, Preferred Stock 1,000,000 5.00% Series 131,916 $ 107.50 $ 13.2 5.04% Series 29,983 102.81 3.0 5.08% Series 49,983 101.00 5.0 6.76% Series 150,000 103.35 15.0 6.88% Series 150,000 100.00 15.0 Total $ 51.2 |
SHORT-TERM DEBT AND LINES OF 47
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Short-term Debt [Abstract] | |
Schedule of short-term borrowings | Our short-term borrowings and their corresponding weighted-average interest rates as of December 31 were as follows: (in millions, except percentages) 2015 2014 Commercial paper Amount outstanding at December 31 $ 182.8 $ 145.1 Average interest rate on amounts outstanding at December 31 0.66% 0.32 % Average amount outstanding during the year * $ 145.0 $ 43.3 * Based on daily outstanding balances during the year. |
Schedule of revolving credit facilities and remaining available capacity | The information in the table below relates to our revolving credit facility used to support our commercial paper borrowing program, including remaining available capacity under this facility as of December 31 : (in millions) Maturity 2015 Revolving credit facility * December 2016 $ 250.0 Total short-term credit capacity $ 250.0 Less: commercial paper outstanding 182.8 Available capacity under existing agreement $ 67.2 * We plan to request approval from the PSCW to extend the maturity through December 2020. |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Schedule of all principal debt payment amounts related to bond maturities | A schedule of all principal debt payment amounts related to bond maturities, excluding those associated with long-term debt to our parent, is as follows: (in millions) Payments 2016 $ — 2017 125.0 2018 250.0 2019 — 2020 — Thereafter 925.0 Total $ 1,300.0 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of components of the provision for income tax expense | The following table is a summary of income tax expense for each of the years ended December 31: (in millions) 2015 2014 2013 Current tax expense $ 31.4 $ (6.1 ) $ 2.1 Deferred income taxes, net 44.0 91.1 80.1 Investment tax credit, net (0.4 ) (0.3 ) (0.3 ) Total income tax expense $ 75.0 $ 84.7 $ 81.9 |
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement | 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 U.S. statutory federal income tax rate to income before income taxes as a result of the following: 2015 2014 2013 (in millions) Amount Effective Tax Rate Amount Effective Tax Rate Amount Effective Tax Rate Expected tax at statutory federal tax rates $ 70.1 35.0 % $ 78.9 35.0 % $ 76.9 35.0 % State income taxes net of federal tax benefit 9.9 5.0 10.9 4.8 10.5 4.8 AFUDC – Equity (5.3 ) (2.6 ) (3.8 ) (1.7 ) (3.5 ) (1.6 ) Other, net 0.3 0.1 (1.3 ) (0.5 ) (2.0 ) (0.9 ) Total income tax expense $ 75.0 37.5 % $ 84.7 37.6 % $ 81.9 37.3 % |
Schedule of principal components of deferred income tax assets and liabilities recognized in the balance sheets | The components of deferred income taxes as of December 31 are as follows: (in millions) 2015 2014 Total deferred tax assets $ 23.9 $ 4.4 Deferred tax liabilities Plant-related 639.1 591.0 Employee benefits and compensation 91.7 83.9 Regulatory deferrals 52.0 42.4 Other 15.2 13.0 Total deferred tax liabilities 798.0 730.3 Deferred tax liability, net $ 774.1 $ 725.9 |
GUARANTEES (Tables)
GUARANTEES (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Guarantees [Abstract] | |
Schedule of outstanding guarantees | The following table shows our outstanding guarantees: Total Amounts Committed Expiration (in millions) at December 31, 2015 Less Than 1 Year 1 to 3 Years Over 3 Years Standby letters of credit (1) $ 9.5 $ — $ 9.5 $ — Surety bonds (2) 1.1 1.1 — — Other guarantee (3) 20.3 20.0 — 0.3 Total guarantees $ 30.9 $ 21.1 $ 9.5 $ 0.3 (1) At our request, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to us. These amounts are not reflected on our balance sheets. (2) Primarily for obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets. (3) Consists of (a) $20.0 million not reflected on our balance sheet for an interconnection agreement between us and ATC and (b) $0.3 million reflected on our balance sheet related to workers compensation. |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Compensation and Retirement Disclosure [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 share of the plans' benefit obligations and fair value of assets: Pension Costs OPEB Costs (in millions) 2015 2014 2015 2014 Change in benefit obligation Obligation at January 1 $ 791.8 $ 717.5 $ 252.5 $ 292.7 Service cost 10.7 8.6 8.7 7.7 Interest cost 31.7 34.4 10.4 11.5 Plan amendments — — — (74.4 ) Transfer to affiliates * (130.5 ) (12.1 ) — — Actuarial loss (gain), net (36.4 ) 73.0 (31.7 ) 24.0 Participant contributions — — 0.3 0.5 Benefit payments (33.3 ) (29.6 ) (8.6 ) (10.4 ) Federal subsidy on benefits paid — — — 0.9 Plan curtailment (0.1 ) $ — — $ — Obligation at December 31 $ 633.9 $ 791.8 $ 231.6 $ 252.5 Change in fair value of plan assets Fair value of plan assets at January 1 $ 897.4 $ 839.1 $ 236.6 $ 236.5 Actual return on plan assets (29.4 ) 53.1 (5.1 ) 7.4 Employer contributions 1.1 46.9 1.3 2.6 Participant contributions — — 0.3 0.5 Benefit payments (33.3 ) (29.6 ) (8.6 ) (10.4 ) Transfer to affiliates * (116.8 ) (12.1 ) — — Fair value at December 31 $ 719.0 $ 897.4 $ 224.5 $ 236.6 * Benefit obligations and plan assets were moved along with our employees who were transferred to affiliated entities. As a result of the WEC Merger, certain of our employees were realigned across WEC Energy Group's various subsidiaries. |
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) 2015 2014 2015 2014 Pension and other postretirement benefit assets $ 93.8 $ 128.9 $ 8.6 $ — Current liabilities — 1.5 — 0.1 Pension and other postretirement benefit liabilities 8.7 21.8 15.7 15.8 Total net assets (liabilities) $ 85.1 $ 105.6 $ (7.1 ) $ (15.9 ) |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | The following table shows information for pension plans with an accumulated benefit obligation in excess of plan assets. There were no plan assets related to these pension plans. Amounts presented are as of December 31: (in millions) 2015 2014 Projected benefit obligation $ 8.7 $ 23.3 Accumulated benefit obligation 8.5 21.5 |
Amounts that had not yet been recognized in the entity's net periodic benefit cost | The following table shows the amounts that had not yet been recognized in our net periodic benefit cost as of December 31: Pension Costs OPEB Costs (in millions) 2015 2014 2015 2014 Net regulatory assets Net actuarial loss $ 61.2 $ 178.7 $ 5.2 $ 41.0 Prior service cost (credit) — 1.8 — (78.3 ) Total $ 61.2 $ 180.5 $ 5.2 $ (37.3 ) |
Schedule of the components of net periodic benefit cost | The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans: Pension Costs OPEB Costs (in millions) 2015 2014 2013 2015 2014 2013 Service cost $ 10.7 $ 8.6 $ 10.8 $ 8.7 $ 7.7 $ 10.6 Interest cost 31.7 34.4 30.6 10.4 11.5 13.4 Expected return on plan assets (64.8 ) (64.1 ) (57.2 ) (16.0 ) (16.0 ) (14.8 ) Loss on plan settlement 0.1 0.4 — — — — Amortization of prior service cost (credit) 0.2 0.6 3.6 (9.3 ) (8.0 ) (2.1 ) Amortization of net actuarial loss 21.0 15.0 24.0 3.7 2.8 7.5 Net periodic benefit cost $ (1.1 ) $ (5.1 ) $ 11.8 $ (2.5 ) $ (2.0 ) $ 14.6 |
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 2015 2014 2015 2014 Discount rate 4.49% 4.08% 4.46% 4.11% Rate of compensation increase 4.00% 4.23% N/A N/A Assumed medical cost trend rate N/A N/A 7.50% 6.00% Ultimate trend rate N/A N/A 5.00% 5.00% Year ultimate trend rate is reached N/A N/A 2021 2023 The weighted-average assumptions used to determine net periodic benefit cost for the plans were as follows for the years ended December 31: Pension Costs 2015 2014 2013 Discount rate 4.08% 4.92% 4.07% Expected return on assets 7.75% 8.00% 8.00% Rate of compensation increase 4.23% 4.25% 4.26% OPEB Costs 2015 2014 2013 Discount rate 4.11% 4.78% 4.01% Expected return on assets 7.75% 8.00% 8.00% Assumed medical cost trend rate (Pre 65/Post 65) 6.00% 6.50% 7.00% Ultimate trend rate 5.00% 5.00% 5.00% Year ultimate trend rate is reached 2023 2019 2019 |
Effects of a one-percentage-point change in assumed health care cost trend rates | For the year ended December 31, 2015 , 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 $ 3.8 $ (2.9 ) Effect on the health care component of the accumulated postretirement benefit obligation 31.9 (25.7 ) |
Investments recorded at fair value, by asset class | The following tables provide the fair values of our investments by asset class: December 31, 2015 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 $ — $ 27.4 $ — $ 27.4 $ 4.6 $ 1.0 $ — $ 5.6 Equity securities: U.S. Equity 39.2 162.2 — 201.4 11.9 60.0 — 71.9 International Equity 40.3 179.3 — 219.6 15.5 58.5 — 74.0 Fixed income securities: (1) U.S. Bonds 6.3 218.3 — 224.6 65.1 — — 65.1 International Bonds — 55.9 — 55.9 — — — — 85.8 643.1 — 728.9 97.1 119.5 — 216.6 401(h) other benefit plan assets invested as pension assets (2) (0.9 ) (7.2 ) — (8.1 ) 0.9 7.2 — 8.1 Total (3) $ 84.9 $ 635.9 $ — $ 720.8 $ 98.0 $ 126.7 $ — $ 224.7 (1) This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries. (2) Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h). (3) Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets. December 31, 2014 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 $ 0.3 $ 25.3 $ — $ 25.6 $ 3.4 $ 1.5 $ 4.9 Equity securities: U.S. Equity 53.3 197.8 — 251.1 14.6 62.4 77.0 International Equity 54.4 225.9 — 280.3 17.6 65.5 83.1 Fixed income securities: (1) U.S. Bonds 41.3 261.8 — 303.1 62.8 — 62.8 International Bonds — 44.6 — 44.6 — — — 149.3 755.4 — 904.7 98.4 129.4 — 227.8 401(h) other benefit plan assets invested as pension assets (2) (1.5 ) (7.3 ) — (8.8 ) 1.5 7.3 — 8.8 Total (3) $ 147.8 $ 748.1 $ — $ 895.9 $ 99.9 $ 136.7 $ — $ 236.6 (1) This category represents investment grade bonds of U.S. and foreign issuers denominated in U.S. dollars from diverse industries. (2) Pension trust assets are used to pay other postretirement benefits as allowed under Internal Revenue Code Section 401(h). (3) Investments do not include accruals or pending transactions that are included in the table reconciling the change in fair value of plan assets. |
Reconciliation of changes in the fair value of pension assets categorized as Level 3 measurements | The following tables set forth a reconciliation of changes in the fair value of pension plan assets categorized as Level 3 in 2014. There was no level 3 activity in 2015. (in millions) International Bonds U.S. Bonds Total Beginning balance at January 1, 2014 $ 1.3 $ 0.7 $ 2.0 Net realized and unrealized gains 0.1 0.1 0.2 Sales (1.4 ) (0.8 ) (2.2 ) Ending balance at December 31, 2014 $ — $ — $ — |
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 2016 $ 46.9 $ 9.6 2017 29.6 10.5 2018 29.1 11.4 2019 32.6 12.2 2020 33.7 13.0 2021-2025 172.4 73.7 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 . Payments Due By Period (in millions) Date Contracts Extend Through Total Amounts Committed 2016 2017 2018 2019 2020 Later Years Electric utility: Purchased power 2027 $ 732.6 $ 85.5 $ 53.5 $ 56.2 $ 57.5 $ 59.8 $ 420.1 Coal supply and transportation 2019 198.4 97.3 46.5 43.5 11.1 — — Natural gas utility supply and transportation 2024 198.1 43.8 42.9 42.4 27.1 14.6 27.3 Total $ 1,129.1 $ 226.6 $ 142.9 $ 142.1 $ 95.7 $ 74.4 $ 447.4 |
Schedule of minimum future payments under noncancelable operating leases | Future minimum payments under noncancelable operating leases are payable as follows: Year Ending December 31 Payments (in millions) 2016 $ 0.4 2017 0.8 2018 0.6 2019 0.4 2020 0.5 Later years 12.3 Total $ 15.0 |
Schedule of regulatory assets and reserves related to manufactured gas plants | We have established the following regulatory assets and reserves related to manufactured gas plant sites as of December 31: (in millions) 2015 2014 Regulatory assets $ 104.4 $ 102.3 Reserves for future remediation 83.5 86.3 |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair value of assets and liabilities measured on a recurring basis, categorized by level within the fair value hierarchy | The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: December 31, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ 0.3 $ — $ — $ 0.3 FTRs — — 2.0 2.0 Total derivative assets $ 0.3 $ — $ 2.0 $ 2.3 Derivative liabilities Natural gas contracts $ 0.9 $ — $ — $ 0.9 Petroleum products contracts 0.5 — — 0.5 Coal contracts — 4.7 — 4.7 Total derivative liabilities $ 1.4 $ 4.7 $ — $ 6.1 December 31, 2014 (in millions) Level 1 Level 2 Level 3 Total Derivative assets Natural gas contracts $ — $ 0.1 $ — $ 0.1 FTRs — — 2.2 2.2 Total derivative assets $ — $ 0.1 $ 2.2 $ 2.3 Derivative liabilities Natural gas contracts $ 2.2 $ — $ — $ 2.2 FTRs — — 0.3 0.3 Petroleum products contracts 1.1 — — 1.1 Coal contracts — 1.2 2.2 3.4 Total derivative liabilities $ 3.3 $ 1.2 $ 2.5 $ 7.0 |
Reconciliation of changes in the fair value of items categorized as Level 3 measurements | The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy at December 31 : (in millions) 2015 2014 2013 Balance at the beginning of the period $ (0.3 ) $ (1.3 ) $ (5.4 ) Realized and unrealized (losses) gains (10.7 ) (1.0 ) 3.3 Purchases 9.8 4.3 3.2 Sales (0.1 ) — (0.2 ) Settlements (1.4 ) (3.5 ) (2.2 ) Net transfers out of level 3 4.7 1.2 — Balance at the end of the period $ 2.0 $ (0.3 ) $ (1.3 ) |
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: December 31, 2015 December 31, 2014 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,289.4 $ 1,350.4 $ 1,165.1 $ 1,286.2 Long-term debt to parent, including current portion 2.9 3.0 5.4 5.7 Preferred stock * — — 51.2 52.0 * On November 13, 2015, we redeemed all of our outstanding shares of preferred stock. See Note 12, Preferred Stock, for more information . |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative assets and derivative liabilities | The following table shows our derivative assets and derivative liabilities: December 31, 2015 December 31, 2014 (in millions) Balance Sheet Presentation Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Natural gas contracts Other Current $ 0.3 $ 0.9 $ 0.1 $ 2.1 Natural gas contracts Other Long-term — — — 0.1 Petroleum product contracts Other Current — 0.5 — 1.1 FTRs Other Current 2.0 — 2.2 0.3 Coal contracts Other Current — 3.3 — 2.4 Coal contracts Other Long-term — 1.4 — 1.0 Other Current 2.3 4.7 2.3 5.9 Other Long-term — 1.4 — 1.1 Total $ 2.3 $ 6.1 $ 2.3 $ 7.0 |
Estimated notional volumes and gains (losses) | Our estimated notional volumes and gains (losses) were as follows: December 31, 2015 December 31, 2014 December 31, 2013 (in millions) Volume Gains (Losses) Volume Gains (Losses) Volume Gains (Losses) Natural gas 22.9 Dth $ (4.9 ) 20.0 Dth $ 0.6 15.5 Dth $ (0.8 ) Petroleum products 6.1 gallons (1.7 ) 5.3 gallons (0.1 ) 2.8 gallons (0.1 ) FTRs 9.0 MWh 3.3 8.7 MWh 3.2 9.1 MWh 5.1 Total $ (3.3 ) $ 3.7 $ 4.2 |
Potential effect of netting arrangements for recognized derivative 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, 2015 December 31, 2014 Derivative Derivative Derivative Derivative (in millions) Assets Liabilities Assets Liabilities Gross amount recognized on the balance sheet $ 2.3 $ 6.1 $ 2.3 $ 7.0 Gross amount not offset on the balance sheet * (0.3 ) (1.4 ) (0.4 ) (3.6 ) Net amount $ 2.0 $ 4.7 $ 1.9 $ 3.4 * Includes cash collateral posted of $1.1 million and $3.2 million as of December 31, 2015 and December 31, 2014 , respectively. |
SEGMENTS INFORMATION (Tables)
SEGMENTS INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Segment Reporting [Abstract] | |
Schedule of information related to reportable segments | The table below presents information related to our reportable segments: Regulated Utilities 2015 (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated External revenues $ 1,187.8 $ 295.5 $ 1,483.3 $ — $ — $ 1,483.3 Intersegment revenues — 10.7 10.7 0.8 (11.5 ) — Other operation and maintenance 424.3 69.6 493.9 0.3 (0.8 ) 493.4 Depreciation and amortization 103.7 17.0 120.7 0.3 — 121.0 Operating income 194.0 34.0 228.0 0.1 — 228.1 Other income, net 15.6 0.4 16.0 9.6 — 25.6 Interest expense 43.0 10.2 53.2 0.3 — 53.5 Capital expenditures 319.4 51.6 371.0 — — 371.0 Total assets 3,718.9 697.9 4,416.8 88.3 — 4,505.1 Regulated Utilities 2014 (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated External revenues $ 1,223.7 $ 459.9 $ 1,683.6 $ — $ — $ 1,683.6 Intersegment revenues — 12.4 12.4 1.4 (13.8 ) — Other operation and maintenance 425.8 73.5 499.3 0.4 — 499.7 Depreciation and amortization 100.5 16.2 116.7 0.6 (0.5 ) 116.8 Operating income 204.8 52.4 257.2 0.4 — 257.6 Other income, net 11.7 0.6 12.3 12.9 — 25.2 Interest expense 45.1 10.2 55.3 2.1 — 57.4 Capital expenditures 272.7 49.3 322.0 — — 322.0 Total assets 3,503.0 680.9 4,183.9 85.4 — 4,269.3 Regulated Utilities 2013 (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated External revenues $ 1,243.0 $ 337.5 $ 1,580.5 $ — $ — $ 1,580.5 Intersegment revenues — 10.9 10.9 1.4 (12.3 ) — Other operation and maintenance 405.0 65.1 470.1 0.3 — 470.4 Depreciation and amortization 93.7 15.6 109.3 0.6 (0.5 ) 109.4 Operating income 189.5 50.0 239.5 0.5 — 240.0 Other income, net 9.9 0.2 10.1 13.4 — 23.5 Interest expense 33.0 8.5 41.5 2.2 — 43.7 Capital expenditures 590.3 37.4 627.7 — — 627.7 Total assets 3,233.6 632.3 3,865.9 85.7 — 3,951.6 |
QUARTERLY FINANCIAL INFORMATI56
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of quarterly financial information (unaudited) | (in millions) First Quarter Second Quarter Third Quarter Fourth Quarter Total 2015 Operating revenues $ 425.0 $ 330.3 $ 390.8 $ 337.2 $ 1,483.3 Operating income 69.9 44.2 88.5 25.5 228.1 Net income attributed to common shareholder 39.0 22.6 50.3 10.6 $ 122.5 2014 Operating revenues $ 556.0 $ 359.0 $ 370.9 $ 397.7 $ 1,683.6 Operating income 87.4 36.3 77.7 56.2 257.6 Net income attributed to common shareholder 50.3 17.1 42.2 28.0 137.6 |
SUMMARY OF SIGNIFICANT ACCOUN57
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES GENERAL INFORMATION (Details) | Dec. 31, 2015 |
Accounting Policies [Abstract] | |
Number of wholly owned subsidiaries | 1 |
SUMMARY OF SIGNIFICANT ACCOUN58
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATIONS (Details) - Restatement Adjustment [Member] - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Income Statement Reclassification [Member] | ||
Prior Period Income Statement Reclassification Payroll Taxes | $ 8.3 | $ 8.9 |
Prior Period Income Statement Reclassification Cost Of Sales | 5.9 | 6.7 |
Prior Period Income Statement Reclassification Other Operation and Maintenance | 3.1 | $ 5.6 |
Balance Sheet Reclassification [Member] | ||
Prior Period Balance Sheet Reclassification Current Regulatory Assets Accounts Receivable | 1.4 | |
Prior Period Balance Sheet Reclassification Regulatory Assets Current Long Term | 23.6 | |
Prior Period Balance Sheet Reclassification Current Regulatory Liabilities Other Current Liabilities | 6.1 | |
Prior Period Balance Sheet Reclassification Regulatory Liabilities Current Long Term | 15.1 | |
Prior Period Balance Sheet Reclassification ASU 2015-03 Current | 0.6 | |
Prior Period Balance Sheet Reclassification ASU 2015-03 Long-Term | 8.8 | |
Prior Period Balance Sheet Reclassification ASU 2015-17 | 3.8 | |
Cash Flow Statement Reclassification [Member] | ||
Prior Period Cash Flow Statement Reclassifications | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN59
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES CASH AND CASH EQUIVALENTS (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Cash and cash equivalents | |
Maximum maturity of short-term investments to classify instruments as cash equivalents | 3 months |
SUMMARY OF SIGNIFICANT ACCOUN60
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES REVENUES AND CUSTOMER RECEIVABLES (Details) | 12 Months Ended |
Dec. 31, 2015customer | |
Revenues from external customers | |
Percentage price variance from rate case-approved fuel and purchased power costs before deferral is required | 2.00% |
Customer concentration risk | |
Revenues from external customers | |
Customers that account for more than 10% of revenues | 0 |
Threshold percentage of revenues from major customers | 10.00% |
SUMMARY OF SIGNIFICANT ACCOUN61
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES MATERIALS, SUPPLIES, AND INVENTORIES (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting Policies [Abstract] | ||
Fossil fuel | $ 76.4 | $ 48.9 |
Materials and supplies | 40.5 | 39.2 |
Natural gas in storage | 28.1 | 36.1 |
Total | $ 145 | $ 124.2 |
SUMMARY OF SIGNIFICANT ACCOUN62
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PROPERTY, PLANT, AND EQUIPMENT (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Software | |||
Property, plant and equipment | |||
Useful life | 3 years | ||
Electric | |||
Property, plant and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.70% | 2.73% | 2.79% |
Natural gas | |||
Property, plant and equipment | |||
Annual utility composite depreciation rate (as a percent) | 2.15% | 2.17% | 2.19% |
SUMMARY OF SIGNIFICANT ACCOUN63
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AFUDC (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
AFUDC | |||
Percentage of retail jurisdictional construction work in progress expenditures subject to AFUDC calculation | 50.00% | ||
Allowance for borrowed funds used during construction | $ 6.1 | $ 4.6 | $ 3.8 |
Allowance for equity funds used during construction | $ 15.1 | $ 11 | $ 9.9 |
Retail | |||
AFUDC | |||
Average AFUDC rate (as a percent) | 7.92% | 8.08% | 8.61% |
Wholesale | |||
AFUDC | |||
Average AFUDC rate (as a percent) | 5.10% | 6.99% | 2.64% |
MERGER (Details)
MERGER (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Merger | |
Severance expense | $ 4.6 |
Severance payments | 4.3 |
Electric Utility | |
Merger | |
Severance expense | 3.6 |
Natural Gas Utility | |
Merger | |
Severance expense | $ 1 |
ACQUISITION (Details)
ACQUISITION (Details) $ in Millions | Jan. 02, 2014 | Mar. 31, 2013USD ($)MW | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Acquisitions | |||||
Purchase price | $ 0 | $ 0 | $ 391.6 | ||
Fox Energy Company LLC | |||||
Acquisitions | |||||
Purchase price | $ 391.6 | ||||
Capacity of Electric Generating Facility | MW | 593 | ||||
Assets acquired | |||||
Inventories - materials and supplies | $ 3 | ||||
Other current assets | 0.4 | ||||
Property, plant, and equipment | 374.4 | ||||
Other long-term assets | 15.6 | ||||
Total assets acquired | 393.4 | ||||
Liabilities assumed | |||||
Accounts payable | 1.8 | ||||
Total liabilities assumed | $ 1.8 | ||||
Contracted Capacity From Power Purchase Agreement | MW | 500 | ||||
Contract termination fee related to tolling arrangement | $ 50 | ||||
Amortization Period of Regulatory Asset | 9 years | ||||
Beginning of regulatory asset amortization period | Jan. 1, 2014 |
RELATED PARTIES (Details)
RELATED PARTIES (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related parties | |||
Notes payable to Integrys | $ 2.9 | $ 5.4 | |
Current portion of notes payable to Integrys | 2.9 | 2.5 | |
ATC | |||
Related parties | |||
Accounts receivable for services provided to ATC | 0.5 | 0.9 | |
Accounts payable to ATC for network transmission services | 8.5 | 8.2 | |
Charges from ATC for network transmission services | 101.3 | 99 | $ 98.4 |
Charges to equity method investee for services, construction, and/or operations | 10.3 | 8.6 | 9.5 |
WRPC | |||
Related parties | |||
Purchases from related party | 3.8 | 3.7 | 3.7 |
Charges to equity method investee for services, construction, and/or operations | 1.1 | 1.4 | 0.9 |
WPS Investments, LLC | |||
Related parties | |||
Equity earnings from WPS Investments, LLC | $ 7.7 | 9.5 | 10.2 |
Equity method investment, ownership interest (as a percent) | 10.83% | ||
AMP Trillium LLC | Electric utility | |||
Related parties | |||
Sales to related party | $ 0.1 | 0 | 0 |
WBS | |||
Related parties | |||
Number of other significant changes from the Non-IBS affiliated interest agreement | 0 | ||
Number of categories of services provided by WBS | 15 | ||
Number of extensions available for affiliated interest agreement | 1 | ||
Integrys | |||
Related parties | |||
Liability related to income tax allocation | $ 5.4 | 6.1 | |
Integrys | WPS Leasing | |||
Related parties | |||
Notes payable to Integrys | 2.9 | 5.4 | |
Current portion of notes payable to Integrys | 2.9 | 2.5 | |
Interest expense related to notes payable with Integrys | 0.3 | 0.5 | 0.5 |
UPPCO | Electric utility | |||
Related parties | |||
Sales to related party | 0 | 15.3 | 22.8 |
ITF | Electric utility | |||
Related parties | |||
Sales to related party | 0 | 0.1 | 0 |
Wisconsin Electric | Electric utility | |||
Related parties | |||
Sales to related party | 0.1 | 0 | 0 |
Wisconsin Electric | Natural gas utility | |||
Related parties | |||
Sales to related party | 0.4 | 0 | 0 |
IES | Natural gas utility | |||
Related parties | |||
Sales to related party | 0 | 0.6 | 0.5 |
Purchases from related party | $ 0 | $ 2.5 | $ 0.9 |
SUPPLEMENTAL CASH FLOW INFORM67
SUPPLEMENTAL CASH FLOW INFORMATION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental Cash Flow Information [Abstract] | |||
Cash paid for interest, net of amount capitalized | $ 58.1 | $ 56.8 | $ 43.9 |
Cash paid for income taxes, net of refunds | 14.5 | ||
Cash received for income taxes, net of refunds | (6.2) | (27.3) | |
Construction costs funded through accounts payable | $ 70.5 | $ 54 | $ 37.3 |
REGULATORY ASSETS AND LIABILI68
REGULATORY ASSETS AND LIABILITIES - REGULATORY ASSETS (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Regulatory assets | ||
Current assets | $ 0.2 | $ 1.4 |
Long-term assets | 462.5 | 457.1 |
Total regulatory assets | 462.7 | 458.5 |
Other Disclosures | ||
Regulatory assets not earning a return | 21 | |
Environmental remediation liabilities | 83.5 | 86.3 |
Unrecognized pension and other postretirement benefit costs | ||
Regulatory assets | ||
Total regulatory assets | 176.6 | 185.6 |
Environmental remediation costs | ||
Regulatory assets | ||
Total regulatory assets | 104.4 | 103.8 |
Other Disclosures | ||
Environmental remediation liabilities | 83.5 | |
Income tax related items | ||
Regulatory assets | ||
Total regulatory assets | 40.8 | 32.7 |
Termination of a tolling agreement with Fox Energy Company LLC | ||
Regulatory assets | ||
Total regulatory assets | 39.1 | 44.6 |
Crane Creek production tax credits | ||
Regulatory assets | ||
Total regulatory assets | $ 30.9 | 32.2 |
Other Disclosures | ||
Period over which grant received will be reflected in income through reduction of depreciation and amortization expense | 12 years | |
De Pere Energy Center | ||
Regulatory assets | ||
Total regulatory assets | $ 19 | 21.4 |
Energy costs recoverable through rate adjustments | ||
Regulatory assets | ||
Total regulatory assets | 12 | 12.6 |
Other | ||
Regulatory assets | ||
Total regulatory assets | $ 39.9 | $ 25.6 |
REGULATORY ASSETS AND LIABILI69
REGULATORY ASSETS AND LIABILITIES - REGULATORY LIABILITIES (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Regulatory Liabilities | ||
Current liabilities | $ 3.6 | $ 6.1 |
Long-term liabilities | 290 | 318.4 |
Total regulatory liabilities | 293.6 | 324.5 |
Removal costs | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 243.7 | 243.9 |
Energy costs refundable through rate adjustments | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 29.4 | 6 |
Crane Creek depreciation deferral | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 8.3 | 8.7 |
Unrecognized pension and other postretirement benefit costs | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 1 | 42.4 |
Decoupling | ||
Regulatory Liabilities | ||
Total regulatory liabilities | 0 | 12.3 |
Other | ||
Regulatory Liabilities | ||
Total regulatory liabilities | $ 11.2 | $ 11.2 |
PROPERTY, PLANT, AND EQUIPMEN70
PROPERTY, PLANT, AND EQUIPMENT (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Property, plant and equipment | ||
Less: Accumulated depreciation | $ 1,565.7 | $ 1,542.5 |
Property, plant, and equipment, net | 3,418.6 | 3,131 |
Utility operations | ||
Property, plant and equipment | ||
Property, plant, and equipment, gross | 4,541.2 | 4,360.5 |
Less: Accumulated depreciation | 1,559.6 | 1,495.9 |
Net property, plant, and equipment excluding construction work in progress | 2,981.6 | 2,864.6 |
Construction work in progress | 434.2 | 248.7 |
Plant to be retired, net | 0 | 12.5 |
Property, plant, and equipment, net | 3,415.8 | 3,125.8 |
Utility operations | Electric Utility | ||
Property, plant and equipment | ||
Property, plant, and equipment, gross | 3,722.8 | 3,587.4 |
Utility operations | Natural Gas Utility | ||
Property, plant and equipment | ||
Property, plant, and equipment, gross | 818.4 | 773.1 |
Nonutility operations | Other | ||
Property, plant and equipment | ||
Property, plant, and equipment, gross | 8.9 | 15.2 |
Less: Accumulated depreciation | 6.1 | 10 |
Property, plant, and equipment, net | $ 2.8 | $ 5.2 |
JOINTLY OWNED UTILITY FACILIT71
JOINTLY OWNED UTILITY FACILITIES (Details) $ in Millions | Dec. 31, 2015USD ($)MW |
Weston 4 | |
Share of significant jointly owned electric generating facilities | |
Ownership (as a percent) | 70.00% |
Our share of rated capacity (in megawatts) | MW | 374.5 |
Utility plant | $ 591.5 |
Accumulated depreciation | (150.5) |
Construction work in progress | $ 5.9 |
Columbia Energy Center Units 1 and 2 | |
Share of significant jointly owned electric generating facilities | |
Ownership (as a percent) | 31.80% |
Our share of rated capacity (in megawatts) | MW | 352.9 |
Utility plant | $ 404.6 |
Accumulated depreciation | (122.6) |
Construction work in progress | $ 23.4 |
Edgewater Unit 4 | |
Share of significant jointly owned electric generating facilities | |
Ownership (as a percent) | 31.80% |
Our share of rated capacity (in megawatts) | MW | 96.3 |
Utility plant | $ 47.6 |
Accumulated depreciation | (30.6) |
Construction work in progress | $ 0.4 |
ASSET RETIREMENT OBLIGATIONS (D
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Changes to asset retirement obligations | |||
Asset retirement obligations at beginning of period | $ 20.3 | $ 18 | $ 16.7 |
Accretion | 1.2 | 1 | 0.9 |
Additions and Revisions to Estimated Cash Flows | 11.4 | 1.5 | 0.5 |
Settlements | (0.2) | (0.2) | (0.1) |
Asset retirement obligations at end of period | 32.7 | $ 20.3 | $ 18 |
Hazardous and Solid Waste Management System Disposal of Coal Combustion Residuals [Member] | |||
Changes to asset retirement obligations | |||
AROs additions | $ 9 |
GOODWILL AND OTHER INTANGIBLE73
GOODWILL AND OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Finite Lived And Indefinite Lived Intangible Assets [Line Items] | ||
Changes in the carrying amount of goodwill | $ 0 | $ 0 |
Goodwill impairment loss | 0 | |
Intangible Assets, Net (Excluding Goodwill) [Abstract] | ||
Contractual service agreements, accumulated amortization | (7.5) | (4.3) |
Indefinite-Lived Intangible Assets (Excluding Goodwill) | 0.4 | 0 |
Intangible Assets, Gross (Excluding Goodwill) | 16 | 15.6 |
Intangible Assets, Net (Excluding Goodwill) | 8.5 | 11.3 |
Contractual service agreements | ||
Intangible Assets, Net (Excluding Goodwill) [Abstract] | ||
Contractual service agreements, gross carrying amount | 15.6 | 15.6 |
Contractual service agreements, accumulated amortization | (7.5) | (4.3) |
Contractual service agreements, net carrying amount | $ 8.1 | $ 11.3 |
Weighted-average amortization period | 3 years |
COMMON EQUITY - STOCK-BASED COM
COMMON EQUITY - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allocated Share-based Compensation Expense | $ 4.8 | $ 11.1 | $ 5.2 |
Deferred Income Tax Benefit | 1.9 | 4.4 | 2.1 |
Stock Options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Allocated Share-based Compensation Expense | 0 | 1 | 0.7 |
Performance Stock Rights | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Intrinsic value of awards canceled due to WEC merger | 1.5 | ||
Allocated Share-based Compensation Expense | 1.3 | 6.3 | 1.1 |
Restricted Stock Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Intrinsic value of awards canceled due to WEC merger | 5.2 | ||
Allocated Share-based Compensation Expense | $ 3.5 | $ 3.8 | $ 3.4 |
COMMON EQUITY - STOCK-BASED C75
COMMON EQUITY - STOCK-BASED COMPENSATION UNITS ROLLFORWARD (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($)shares | |
Stock Options | |
Stock Options [Roll Forward] | |
Outstanding, at the beginning of the period (in shares) | 5,714 |
Granted (in shares) | 0 |
Transferred (in shares) | 0 |
Exercised (in shares) | (2,752) |
Stock options settled due to WEC merger | (2,962) |
Outstanding, at the end of the periods (in shares) | 0 |
Performance Stock Rights | |
Performance Stock Rights and Restricted Stock Units [Roll Forward] | |
Outstanding at the beginning of the period (in shares) | 13,937 |
Granted (in shares) | 0 |
Transferred (in shares) | 0 |
Distributed (in shares) | (2,229) |
Awards settled due to WEC merger | (21,263) |
Adjustment for performance stock rights distributed or settled | 9,555 |
Outstanding at the end of the period (in shares) | 0 |
Restricted Stock Units | |
Performance Stock Rights and Restricted Stock Units [Roll Forward] | |
Outstanding at the beginning of the period (in shares) | 70,544 |
Granted (in shares) | 30,174 |
Dividend equivalents (in shares) | 1,267 |
Transferred (in shares) | (166) |
Vested and released (in shares) | (28,428) |
Awards settled due to WEC merger | (73,391) |
Outstanding at the end of the period (in shares) | 0 |
Intrinsic value of restricted stock units vested and released | $ | $ 2.2 |
COMMON EQUITY - DIVIDEND RESTRI
COMMON EQUITY - DIVIDEND RESTRICTIONS (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Dividend Payment Restrictions | |
Retained Earnings, Appropriated | $ 528.5 |
Retained Earnings, Undistributed Earnings from Equity Method Investees | $ 32.3 |
Public Service Commission of Wisconsin (PSCW) | |
Dividend Payment Restrictions | |
Common equity ratio required to be maintained (as a percent) | 51.00% |
PREFERRED STOCK (Details)
PREFERRED STOCK (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | ||
Nov. 30, 2015 | Dec. 31, 2014 | Dec. 31, 2015 | Nov. 13, 2015 | |
Preferred stock | ||||
Par value (in dollars per share) | $ 100 | $ 100 | ||
Authorized shares | 1,000,000 | 1,000,000 | ||
Shares outstanding | 511,882 | 0 | ||
Carrying value | $ 51.2 | $ 0 | ||
Mandatorily redeemable shares | 511,882 | |||
Preferred Stock Redemption Price | $ 52.7 | |||
5.00% preferred stock series | ||||
Preferred stock | ||||
Series (as a percent) | 5.00% | 5.00% | ||
Shares outstanding | 131,916 | |||
Preferred Stock, Redemption Price Per Share | $ 107.50 | |||
Carrying value | $ 13.2 | |||
Mandatorily redeemable shares | 131,916 | |||
5.04% preferred stock series | ||||
Preferred stock | ||||
Series (as a percent) | 5.04% | 5.04% | ||
Shares outstanding | 29,983 | |||
Preferred Stock, Redemption Price Per Share | $ 102.81 | |||
Carrying value | $ 3 | |||
Mandatorily redeemable shares | 29,983 | |||
5.08% preferred stock series | ||||
Preferred stock | ||||
Series (as a percent) | 5.08% | 5.08% | ||
Shares outstanding | 49,983 | |||
Preferred Stock, Redemption Price Per Share | $ 101 | |||
Carrying value | $ 5 | |||
Mandatorily redeemable shares | 49,983 | |||
6.76% preferred stock series | ||||
Preferred stock | ||||
Series (as a percent) | 6.76% | 6.76% | ||
Shares outstanding | 150,000 | |||
Preferred Stock, Redemption Price Per Share | $ 103.35 | |||
Carrying value | $ 15 | |||
Mandatorily redeemable shares | 150,000 | |||
6.88% preferred stock series | ||||
Preferred stock | ||||
Series (as a percent) | 6.88% | 6.88% | ||
Shares outstanding | 150,000 | |||
Preferred Stock, Redemption Price Per Share | $ 100 | |||
Carrying value | $ 15 | |||
Mandatorily redeemable shares | 150,000 |
SHORT-TERM DEBT AND LINES OF 78
SHORT-TERM DEBT AND LINES OF CREDIT OUTSTANDING (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Short-term borrowings | ||
Short-term borrowings outstanding | $ 182.8 | $ 145.1 |
Commercial paper | ||
Short-term borrowings | ||
Short-term borrowings outstanding | $ 182.8 | $ 145.1 |
Average interest rate on amounts outstanding (as a percent) | 0.66% | 0.32% |
Average amount of short-term borrowings outstanding during the year | $ 145 | $ 43.3 |
SHORT-TERM DEBT AND LINES OF 79
SHORT-TERM DEBT AND LINES OF CREDIT CAPACITY (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2015USD ($)extension | Dec. 31, 2014USD ($) | |
Short-term borrowings | ||
Debt to capitalization ratio required to be maintained (as a percent) | 65.00% | |
Total short-term credit capacity | $ 250 | |
Short-term borrowings outstanding | 182.8 | $ 145.1 |
Available capacity under existing agreements | 67.2 | |
Revolving credit facility maturing in December 2016 [Member] | ||
Short-term borrowings | ||
Total short-term credit capacity | $ 250 | |
Number of extensions available on a credit facility | extension | 2 | |
Length of credit facility extension | 1 year | |
Commercial paper | ||
Short-term borrowings | ||
Short-term borrowings outstanding | $ 182.8 | $ 145.1 |
LONG-TERM DEBT (Details)
LONG-TERM DEBT (Details) - USD ($) $ in Millions | 1 Months Ended | |||
Dec. 31, 2015 | Dec. 01, 2015 | Nov. 30, 2015 | Dec. 31, 2014 | |
Long-term Debt, Fiscal Year Maturity | ||||
2,016 | $ 0 | |||
2,017 | 125 | |||
2,018 | 250 | |||
2,019 | 0 | |||
2,020 | 0 | |||
Later Years | 925 | |||
Total | 1,300 | $ 1,175.1 | ||
Senior Notes 6.375 Percent, Due 2015 | ||||
Long-term debt | ||||
Repayments of Debt | $ 125 | |||
Long Term Debt 1.65% Series, Due 2018 | ||||
Long-term debt | ||||
Interest rate stated percentage | 1.65% | 1.65% | ||
Proceeds from Issuance of Debt | $ 250 | |||
Long Term debt, 7.125% Series, Year Due, 2023 | ||||
Long-term debt | ||||
First Mortgage Bonds | $ 0 | $ 0.1 | $ 0.1 | |
Debt redemption price (percent) | 100.00% | |||
Interest rate stated percentage | 7.125% | |||
Senior Notes 6.375 Percent, Due 2015 | ||||
Long-term debt | ||||
Repayments of Debt | $ 125 | |||
Interest rate stated percentage | 6.375% |
INCOME TAXES INCOME TAXES PROVI
INCOME TAXES INCOME TAXES PROVISION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Provision for income taxes | |||
Total current provision | $ 31.4 | $ (6.1) | $ 2.1 |
Total deferred provision | 44 | 91.1 | 80.1 |
Investment tax credits | (0.4) | (0.3) | (0.3) |
Income tax expense | $ 75 | $ 84.7 | $ 81.9 |
INCOME TAXES RECONCILIATION (De
INCOME TAXES RECONCILIATION (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement | |||
Statutory federal income tax | $ 70,100,000 | $ 78,900,000 | $ 76,900,000 |
State income taxes, net | 9,900,000 | 10,900,000 | 10,500,000 |
Income Tax Reconciliation Allowance For Funds Used During Construction Capitalized Cost Of Equity | (5,300,000) | (3,800,000) | (3,500,000) |
Other differences, net | 300,000 | (1,300,000) | (2,000,000) |
Income tax expense | $ 75,000,000 | $ 84,700,000 | $ 81,900,000 |
Reconciliation of federal income taxes to the provision for income taxes reported in the income statement (as a percent) | |||
Statutory federal income tax rate (as a percent) | 35.00% | 35.00% | 35.00% |
State income tax rate, net (as a percent) | 5.00% | 4.80% | 4.80% |
Effective Income Tax Rate Reconciliation Allowance For Funds Used During Construction Capitalized Cost Of Equity | (2.60%) | (1.70%) | (1.60%) |
Other differences, net (as a percent) | 0.10% | (0.50%) | (0.90%) |
Effective income tax rate (as a percent) | 37.50% | 37.60% | 37.30% |
Unrecognized tax benefits, additional disclosures | |||
Balance at the end of the period | $ 0 | $ 0 | |
Accrued interest related to unrecognized tax benefits | 0 | 0 | |
Accrued penalties related to unrecognized tax benefits | $ 0 | $ 0 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Income taxes | ||
Unrecognized Tax Benefits | $ 0 | $ 0 |
Deferred income tax assets | ||
Total deferred income tax assets | 23.9 | 4.4 |
Deferred income tax liabilities | ||
Plant-related | 639.1 | 591 |
Employee benefits | 91.7 | 83.9 |
Regulatory deferrals | 52 | 42.4 |
Other | 15.2 | 13 |
Total deferred income tax liabilities | 798 | 730.3 |
Balance sheet presentation | ||
Total net deferred income tax liabilities | 774.1 | $ 725.9 |
Income taxes, additional disclosures | ||
Deferred tax credit carryforwards of alternative minimum tax credits | 2 | |
Deferred tax credit carryforwards of general business credits | 3 | |
Deferred Tax Assets, Operating Loss Carryforwards, Domestic | $ 16.1 | |
General business credits | ||
Income taxes, additional disclosures | ||
Carryback period of general business tax credits | 1 year | |
Carryforward period of general business tax credits | 20 years |
GUARANTEES (Details)
GUARANTEES (Details) $ in Millions | Dec. 31, 2015USD ($) |
Guarantor Obligations | |
Total guarantees | $ 30.9 |
Guarantees expiring in less than one year | 21.1 |
Guarantees expiring in one to three years | 9.5 |
Guarantees expiring in over one year | 0.3 |
Standby Letters of Credit | |
Guarantor Obligations | |
Total guarantees | 9.5 |
Guarantees expiring in less than one year | 0 |
Guarantees expiring in one to three years | 9.5 |
Guarantees expiring in over one year | 0 |
Surety Bonds | |
Guarantor Obligations | |
Total guarantees | 1.1 |
Guarantees expiring in less than one year | 1.1 |
Guarantees expiring in one to three years | 0 |
Guarantees expiring in over one year | 0 |
Other guarantees | |
Guarantor Obligations | |
Total guarantees | 20.3 |
Guarantees expiring in less than one year | 20 |
Guarantees expiring in one to three years | 0 |
Guarantees expiring in over one year | 0.3 |
Indemnification Agreement | |
Guarantor Obligations | |
Liability related to workers compensation coverage | 0.3 |
ATC [Member] | Other guarantees | |
Guarantor Obligations | |
Total guarantees | $ 20 |
EMPLOYEE BENEFIT PLANS - CHANGE
EMPLOYEE BENEFIT PLANS - CHANGE IN BENEFIT OBLIGATIONS AND PLAN ASSETS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans | |||
Long-term assets | $ 102.4 | $ 128.9 | |
Long-term liabilities | 24.4 | 37.6 | |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | |||
Fair value of plan assets | 0 | ||
Pension Benefits | |||
Change in benefit obligation | |||
Obligation at January 1 | 791.8 | 717.5 | |
Service cost | 10.7 | 8.6 | $ 10.8 |
Interest cost | 31.7 | 34.4 | 30.6 |
Plan amendments | 0 | 0 | |
Transfer to affiliates | (130.5) | (12.1) | |
Actuarial loss (gain), net | (36.4) | 73 | |
Participant contributions | 0 | 0 | |
Benefit payments | (33.3) | (29.6) | |
Federal subsidy on benefits paid | 0 | 0 | |
Plan curtailments | (0.1) | 0 | |
Obligation at December 31 | 633.9 | 791.8 | 717.5 |
Change in fair value of plan assets | |||
Fair value of plan assets at January 1 | 897.4 | 839.1 | |
Actual return on plan assets | (29.4) | 53.1 | |
Employer contributions | 1.1 | 46.9 | |
Participant contributions | 0 | 0 | |
Benefit payments | (33.3) | (29.6) | |
Transfer to affiliates | (116.8) | (12.1) | |
Fair value of plan assets at December 31 | 719 | 897.4 | 839.1 |
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans | |||
Long-term assets | 93.8 | 128.9 | |
Current liabilities | 0 | 1.5 | |
Long-term liabilities | 8.7 | 21.8 | |
Total net assets (liabilities) | 85.1 | 105.6 | |
Accumulated benefit obligation | 569.6 | 717.4 | |
Information for pension plans with an accumulated benefit obligation in excess of plan assets | |||
Projected benefit obligation | 8.7 | 23.3 | |
Accumulated benefit obligation | 8.5 | 21.5 | |
OPEB | |||
Change in benefit obligation | |||
Obligation at January 1 | 252.5 | 292.7 | |
Service cost | 8.7 | 7.7 | 10.6 |
Interest cost | 10.4 | 11.5 | 13.4 |
Plan amendments | 0 | (74.4) | |
Transfer to affiliates | 0 | 0 | |
Actuarial loss (gain), net | (31.7) | 24 | |
Participant contributions | 0.3 | 0.5 | |
Benefit payments | (8.6) | (10.4) | |
Federal subsidy on benefits paid | 0 | 0.9 | |
Plan curtailments | 0 | 0 | |
Obligation at December 31 | 231.6 | 252.5 | 292.7 |
Change in fair value of plan assets | |||
Fair value of plan assets at January 1 | 236.6 | 236.5 | |
Actual return on plan assets | (5.1) | 7.4 | |
Employer contributions | 1.3 | 2.6 | |
Participant contributions | 0.3 | 0.5 | |
Benefit payments | (8.6) | (10.4) | |
Transfer to affiliates | 0 | 0 | |
Fair value of plan assets at December 31 | 224.5 | 236.6 | $ 236.5 |
Amounts recognized on the entity's balance sheets related to the funded status of the benefit plans | |||
Long-term assets | 8.6 | 0 | |
Current liabilities | 0 | 0.1 | |
Long-term liabilities | 15.7 | 15.8 | |
Total net assets (liabilities) | $ (7.1) | $ (15.9) |
EMPLOYEE BENEFIT PLANS - NET PE
EMPLOYEE BENEFIT PLANS - NET PERIODIC BENEFIT COST (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Pension Benefits | |||
Net regulatory assets | |||
Net actuarial losses | $ 61.2 | $ 178.7 | |
Prior service cost (credit) | 0 | 1.8 | |
Total | 61.2 | 180.5 | |
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | |||
Service cost | 10.7 | 8.6 | $ 10.8 |
Interest cost | 31.7 | 34.4 | 30.6 |
Expected return on plan assets | (64.8) | (64.1) | (57.2) |
Loss on plan settlement | 0.1 | 0.4 | 0 |
Amortization of prior service cost (credit) | 0.2 | 0.6 | 3.6 |
Amortization of net actuarial loss | 21 | 15 | 24 |
Net periodic benefit cost | (1.1) | (5.1) | 11.8 |
OPEB | |||
Net regulatory assets | |||
Net actuarial losses | 5.2 | 41 | |
Prior service cost (credit) | 0 | (78.3) | |
Total | 5.2 | (37.3) | |
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | |||
Service cost | 8.7 | 7.7 | 10.6 |
Interest cost | 10.4 | 11.5 | 13.4 |
Expected return on plan assets | (16) | (16) | (14.8) |
Loss on plan settlement | 0 | 0 | |
Amortization of prior service cost (credit) | (9.3) | (8) | (2.1) |
Amortization of net actuarial loss | 3.7 | 2.8 | 7.5 |
Net periodic benefit cost | $ (2.5) | $ (2) | $ 14.6 |
EMPLOYEE BENEFIT PLANS - ASSUMP
EMPLOYEE BENEFIT PLANS - ASSUMPTIONS (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Pension Benefits | ||||
Weighted average assumptions used | ||||
Discount rate | 4.49% | 4.08% | ||
Rate of compensation increase | 4.00% | 4.23% | ||
Discount rate | 4.08% | 4.92% | 4.07% | |
Expected return on plan assets | 7.75% | 8.00% | 8.00% | |
Rate of compensation increase | 4.23% | 4.25% | 4.26% | |
Pension Benefits | Equity securities: | ||||
Target asset allocations | ||||
Target asset allocations (as a percent) | 60.00% | 70.00% | ||
Pension Benefits | Fixed income securities: | ||||
Target asset allocations | ||||
Target asset allocations (as a percent) | 40.00% | 30.00% | ||
OPEB | ||||
Weighted average assumptions used | ||||
Discount rate | 4.46% | 4.11% | ||
Assumed medical cost trend rate (as a percent) | 7.50% | 6.00% | ||
Ultimate trend rate (as a percent) | 5.00% | 5.00% | ||
Year ultimate trend rate is reached | 2,021 | 2,023 | ||
Discount rate | 4.11% | 4.78% | 4.01% | |
Expected return on plan assets | 7.75% | 8.00% | 8.00% | |
Expected return on assets during next fiscal year | 7.25% | |||
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 | $ 3.8 | |||
Effect of one-percentage-point decrease 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 | 31.9 | |||
Effect of one-percentage-point decrease on the health care component of the accumulated postretirement benefit obligation | $ (25.7) | |||
OPEB | Under age 65 | ||||
Weighted average assumptions used | ||||
Assumed medical cost trend rate (as a percent) | 6.00% | 6.50% | 7.00% | |
Ultimate trend rate (as a percent) | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2,023 | 2,019 | 2,019 | |
OPEB | Over age 65 | ||||
Weighted average assumptions used | ||||
Assumed medical cost trend rate (as a percent) | 6.00% | 6.50% | 7.00% | |
Ultimate trend rate (as a percent) | 5.00% | 5.00% | 5.00% | |
Year ultimate trend rate is reached | 2,023 | 2,019 | 2,019 | |
OPEB | Equity securities: | ||||
Target asset allocations | ||||
Target asset allocations (as a percent) | 70.00% | |||
OPEB | Fixed income securities: | ||||
Target asset allocations | ||||
Target asset allocations (as a percent) | 30.00% |
EMPLOYEE BENEFIT PLANS - PENSIO
EMPLOYEE BENEFIT PLANS - PENSION AND OTHER POSTRETIREMENT PLAN ASSETS (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Pension Plan Assets | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | $ 728.9 | $ 904.7 | |
401(h) other benefit plan assets invested as pension assets | (8.1) | (8.8) | |
Total | 720.8 | 895.9 | |
Pension Plan Assets | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 27.4 | 25.6 | |
Pension Plan Assets | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 201.4 | 251.1 | |
Pension Plan Assets | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 219.6 | 280.3 | |
Pension Plan Assets | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 224.6 | 303.1 | |
Pension Plan Assets | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 55.9 | 44.6 | |
Pension Plan Assets | Level 1 | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 85.8 | 149.3 | |
401(h) other benefit plan assets invested as pension assets | (0.9) | (1.5) | |
Total | 84.9 | 147.8 | |
Pension Plan Assets | Level 1 | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0.3 | |
Pension Plan Assets | Level 1 | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 39.2 | 53.3 | |
Pension Plan Assets | Level 1 | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 40.3 | 54.4 | |
Pension Plan Assets | Level 1 | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 6.3 | 41.3 | |
Pension Plan Assets | Level 1 | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
Pension Plan Assets | Level 2 | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 643.1 | 755.4 | |
401(h) other benefit plan assets invested as pension assets | (7.2) | (7.3) | |
Total | 635.9 | 748.1 | |
Pension Plan Assets | Level 2 | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 27.4 | 25.3 | |
Pension Plan Assets | Level 2 | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 162.2 | 197.8 | |
Pension Plan Assets | Level 2 | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 179.3 | 225.9 | |
Pension Plan Assets | Level 2 | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 218.3 | 261.8 | |
Pension Plan Assets | Level 2 | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 55.9 | 44.6 | |
Pension Plan Assets | Level 3 | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | $ 2 |
401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
Total | 0 | 0 | |
Pension Plan Assets | Level 3 | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
Pension Plan Assets | Level 3 | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
Pension Plan Assets | Level 3 | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
Pension Plan Assets | Level 3 | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | 0.7 |
Pension Plan Assets | Level 3 | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | $ 1.3 |
OPEB Plan Assets | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 216.6 | 227.8 | |
401(h) other benefit plan assets invested as pension assets | 8.1 | 8.8 | |
Total | 224.7 | 236.6 | |
OPEB Plan Assets | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 5.6 | 4.9 | |
OPEB Plan Assets | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 71.9 | 77 | |
OPEB Plan Assets | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 74 | 83.1 | |
OPEB Plan Assets | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 65.1 | 62.8 | |
OPEB Plan Assets | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
OPEB Plan Assets | Level 1 | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 97.1 | 98.4 | |
401(h) other benefit plan assets invested as pension assets | 0.9 | 1.5 | |
Total | 98 | 99.9 | |
OPEB Plan Assets | Level 1 | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 4.6 | 3.4 | |
OPEB Plan Assets | Level 1 | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 11.9 | 14.6 | |
OPEB Plan Assets | Level 1 | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 15.5 | 17.6 | |
OPEB Plan Assets | Level 1 | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 65.1 | 62.8 | |
OPEB Plan Assets | Level 1 | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
OPEB Plan Assets | Level 2 | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 119.5 | 129.4 | |
401(h) other benefit plan assets invested as pension assets | 7.2 | 7.3 | |
Total | 126.7 | 136.7 | |
OPEB Plan Assets | Level 2 | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 1 | 1.5 | |
OPEB Plan Assets | Level 2 | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 60 | 62.4 | |
OPEB Plan Assets | Level 2 | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 58.5 | 65.5 | |
OPEB Plan Assets | Level 2 | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
OPEB Plan Assets | Level 2 | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
OPEB Plan Assets | Level 3 | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
401(h) other benefit plan assets invested as pension assets | 0 | 0 | |
Total | 0 | $ 0 | |
OPEB Plan Assets | Level 3 | Cash and cash equivalents | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | ||
OPEB Plan Assets | Level 3 | United States equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | ||
OPEB Plan Assets | Level 3 | International equity | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | ||
OPEB Plan Assets | Level 3 | United States bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | 0 | ||
OPEB Plan Assets | Level 3 | International bonds | |||
Investments recorded at fair value, by asset class | |||
Fair value of plan assets before the adjustment for 401(h) other benefit plan assets invested as pension assets | $ 0 |
EMPLOYEE BENEFIT PLANS - CHAN89
EMPLOYEE BENEFIT PLANS - CHANGES IN THE FAIR VALUE OF PLAN ASSETS (Details) - Pension Benefits - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | $ 904,700,000 | |
Net realized and unrealized losses | (29,400,000) | $ 53,100,000 |
Ending balance at December 31 | 728,900,000 | 904,700,000 |
Level 3 | ||
Employee Benefit Plans | ||
Defined benefit plan change in fair value | 0 | |
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 2,000,000 |
Net realized and unrealized losses | 200,000 | |
Sales | (2,200,000) | |
Ending balance at December 31 | 0 | 0 |
International bonds | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 44,600,000 | |
Ending balance at December 31 | 55,900,000 | 44,600,000 |
International bonds | Level 3 | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 1,300,000 |
Net realized and unrealized losses | 100,000 | |
Sales | (1,400,000) | |
Ending balance at December 31 | 0 | 0 |
United States bonds | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 303,100,000 | |
Ending balance at December 31 | 224,600,000 | 303,100,000 |
United States bonds | Level 3 | ||
Reconciliation of changes in the fair value of pension plan assets | ||
Beginning balance at January 1 | 0 | 700,000 |
Net realized and unrealized losses | 100,000 | |
Sales | (800,000) | |
Ending balance at December 31 | $ 0 | $ 0 |
EMPLOYEE BENEFIT PLANS - DEFINE
EMPLOYEE BENEFIT PLANS - DEFINED CONTRIBUTION BENEFIT PLANS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined Contribution Benefit Plans | |||
Total costs incurred for defined contribution benefit plans | $ 9.7 | $ 8.6 | $ 8.2 |
Pension Benefits | |||
Employee Benefit Plans | |||
Expected contributions to the plans during the next fiscal year | 1.4 | ||
Expected payments, reflecting expected future service | |||
2,016 | 46.9 | ||
2,017 | 29.6 | ||
2,018 | 29.1 | ||
2,019 | 32.6 | ||
2,020 | 33.7 | ||
2021 through 2025 | 172.4 | ||
OPEB | |||
Employee Benefit Plans | |||
Expected contributions to the plans during the next fiscal year | 2.1 | ||
Expected payments, reflecting expected future service | |||
2,016 | 9.6 | ||
2,017 | 10.5 | ||
2,018 | 11.4 | ||
2,019 | 12.2 | ||
2,020 | 13 | ||
2021 through 2025 | $ 73.7 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Dec. 31, 2015USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 1,129.1 |
2,016 | 226.6 |
2,017 | 142.9 |
2,018 | 142.1 |
2,019 | 95.7 |
2,020 | 74.4 |
Later Years | 447.4 |
Purchased power | Electric utility | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 732.6 |
2,016 | 85.5 |
2,017 | 53.5 |
2,018 | 56.2 |
2,019 | 57.5 |
2,020 | 59.8 |
Later Years | 420.1 |
Coal supply and transportation | Electric utility | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 198.4 |
2,016 | 97.3 |
2,017 | 46.5 |
2,018 | 43.5 |
2,019 | 11.1 |
2,020 | 0 |
Later Years | 0 |
Natural gas utility supply and transportation | Natural gas utility | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 198.1 |
2,016 | 43.8 |
2,017 | 42.9 |
2,018 | 42.4 |
2,019 | 27.1 |
2,020 | 14.6 |
Later Years | $ 27.3 |
COMMITMENTS AND CONTINGENCIES92
COMMITMENTS AND CONTINGENCIES - OPERATING LEASES (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Leases [Abstract] | |||
Rental expense attributable to operating leases | $ 1.4 | $ 1.6 | $ 2.3 |
Minimum future payments under noncancelable operating leases | |||
2,016 | 0.4 | ||
2,017 | 0.8 | ||
2,018 | 0.6 | ||
2,019 | 0.4 | ||
2,020 | 0.5 | ||
Later years | 12.3 | ||
Total | $ 15 |
COMMITMENTS AND CONTINGENCIES93
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) T in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||||
Jan. 31, 2016USD ($) | Aug. 31, 2014 | Jun. 30, 2013USD ($) | Mar. 31, 2013USD ($) | Dec. 31, 2015USD ($)T | Dec. 31, 2014USD ($)T | Jun. 01, 2015USD ($) | |
Natural gas utility | |||||||
Manufactured Gas Plant Remediation | |||||||
Liabilities estimated and accrued for future undiscounted investigation and cleanup costs for all sites | $ 83.5 | $ 86.3 | |||||
Mercury and other hazardous air pollutants | Electric utility | |||||||
Air Quality | |||||||
Percentage mercury emission reduction required by the State of Wisconsin's mercury rule | 90.00% | ||||||
Term of MATS compliance extension | 1 year | ||||||
Climate Change | Electric utility | |||||||
Air Quality | |||||||
Percentage greenhouse gas emission reduction nationwide | 32.00% | ||||||
Percentage greenhouse gas emission reduction for retirement of a nuclear plant | 10.00% | ||||||
Carbon dioxide emissions | T | 5.7 | 6.2 | |||||
Climate Change | Natural gas utility | |||||||
Air Quality | |||||||
Carbon dioxide emissions | T | 3.5 | 3.9 | |||||
Clean Water Act Cooling Water Intake Structure Rule | Electric utility | |||||||
Water Quality | |||||||
Number of compliance options available to meet standard | 7 | ||||||
Steam Electric Effluent Guidelines | Electric utility | Subsequent event | |||||||
Water Quality | |||||||
Renewal period for facility permits | 5 years | ||||||
Steam Electric Effluent Guidelines | Electric utility | Minimum | Subsequent event | |||||||
Water Quality | |||||||
Expected environmental costs to achieve required emission reductions | $ 10 | ||||||
Steam Electric Effluent Guidelines | Electric utility | Maximum | Subsequent event | |||||||
Water Quality | |||||||
Expected environmental costs to achieve required emission reductions | $ 20 | ||||||
Renewables, efficiency, and conservation | Electric utility | |||||||
Renewables, Efficiency, and Conservation | |||||||
Percent goal of electricity consumption | 10.00% | ||||||
Renewable energy percent required | 9.74% | ||||||
Percent of annual operating revenues | 1.20% | ||||||
Manufactured gas plant remediation | Natural gas utility | |||||||
Manufactured Gas Plant Remediation | |||||||
Regulatory assets recorded for cash and estimated future remediation expenditures | $ 104.4 | $ 102.3 | |||||
Weston and Pulliam Consent Decree | Electric utility | |||||||
Consent Decrees | |||||||
Beneficial environmental project amount | $ 6 | ||||||
Civil penalty | $ 1.2 | ||||||
Regulatory asset for undepreciated book value of retired plants | $ 11.5 | ||||||
Joint Ownership Power Plants Consent Decree - Columbia and Edgewater | Electric utility | |||||||
Consent Decrees | |||||||
Beneficial environmental project amount | $ 1.3 | ||||||
Civil penalty | $ 0.4 | ||||||
WISCONSIN | Climate Change | Electric utility | |||||||
Air Quality | |||||||
Percentage greenhouse gas emission reduction Wisconsin | 41.00% |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Assets | ||
Derivative Asset | $ 2.3 | $ 2.3 |
Liabilities | ||
Derivative Liability | 6.1 | 7 |
Fair value measurements on a recurring basis | Level 1 | ||
Assets | ||
Derivative Asset | 0.3 | 0 |
Liabilities | ||
Derivative Liability | 1.4 | 3.3 |
Fair value measurements on a recurring basis | Level 2 | ||
Assets | ||
Derivative Asset | 0 | 0.1 |
Liabilities | ||
Derivative Liability | 4.7 | 1.2 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative Asset | 2 | 2.2 |
Liabilities | ||
Derivative Liability | 0 | 2.5 |
Fair value measurements on a recurring basis | Total | ||
Assets | ||
Derivative Asset | 2.3 | 2.3 |
Liabilities | ||
Derivative Liability | 6.1 | 7 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative Asset | 0.3 | 0 |
Liabilities | ||
Derivative Liability | 0.9 | 2.2 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | ||
Assets | ||
Derivative Asset | 0 | 0.1 |
Liabilities | ||
Derivative Liability | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Liabilities | ||
Derivative Liability | 0 | 0 |
Fair value measurements on a recurring basis | Natural gas contracts | Total | ||
Assets | ||
Derivative Asset | 0.3 | 0.1 |
Liabilities | ||
Derivative Liability | 0.9 | 2.2 |
Fair value measurements on a recurring basis | FTRs | Level 1 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Liabilities | ||
Derivative Liability | 0 | |
Fair value measurements on a recurring basis | FTRs | Level 2 | ||
Assets | ||
Derivative Asset | 0 | 0 |
Liabilities | ||
Derivative Liability | 0 | |
Fair value measurements on a recurring basis | FTRs | Level 3 | ||
Assets | ||
Derivative Asset | 2 | 2.2 |
Liabilities | ||
Derivative Liability | 0.3 | |
Fair value measurements on a recurring basis | FTRs | Total | ||
Assets | ||
Derivative Asset | 2 | 2.2 |
Liabilities | ||
Derivative Liability | 0.3 | |
Fair value measurements on a recurring basis | Petroleum product contracts | Level 1 | ||
Liabilities | ||
Derivative Liability | 0.5 | 1.1 |
Fair value measurements on a recurring basis | Petroleum product contracts | Level 2 | ||
Liabilities | ||
Derivative Liability | 0 | 0 |
Fair value measurements on a recurring basis | Petroleum product contracts | Level 3 | ||
Liabilities | ||
Derivative Liability | 0 | 0 |
Fair value measurements on a recurring basis | Petroleum product contracts | Total | ||
Liabilities | ||
Derivative Liability | 0.5 | 1.1 |
Fair value measurements on a recurring basis | Coal contracts | Level 1 | ||
Liabilities | ||
Derivative Liability | 0 | 0 |
Fair value measurements on a recurring basis | Coal contracts | Level 2 | ||
Liabilities | ||
Derivative Liability | 4.7 | 1.2 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Liabilities | ||
Derivative Liability | 0 | 2.2 |
Fair value measurements on a recurring basis | Coal contracts | Total | ||
Liabilities | ||
Derivative Liability | $ 4.7 | $ 3.4 |
FAIR VALUE MEASUREMENTS - LEVEL
FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | |||
Balance at the beginning of period | $ (0.3) | $ (1.3) | $ (5.4) |
Net realized and unrealized gains (losses) | (10.7) | (1) | 3.3 |
Purchases | 9.8 | 4.3 | 3.2 |
Sales | (0.1) | 0 | (0.2) |
Settlements | (1.4) | (3.5) | (2.2) |
Net transfers out of Level 3 | 4.7 | 1.2 | 0 |
Balance at the end of the period | $ 2 | $ (0.3) | $ (1.3) |
FAIR VALUE MEASUREMENTS - FINAN
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Carrying value and estimated fair value of financial instruments | ||
Long-term debt | $ 1,289.4 | $ 1,165.1 |
Long-term debt to parent | 2.9 | 5.4 |
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively | 0 | 51.2 |
Carrying Amount | ||
Carrying value and estimated fair value of financial instruments | ||
Long-term debt | 1,289.4 | 1,165.1 |
Long-term debt to parent | 2.9 | 5.4 |
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively | 0 | 51.2 |
Fair Value | ||
Carrying value and estimated fair value of financial instruments | ||
Long-term debt | 1,350.4 | 1,286.2 |
Long-term debt to parent | 3 | 5.7 |
Preferred stock – $100 par value; 1,000,000 shares authorized; shares issued and outstanding of zero and 511,882, respectively | $ 0 | $ 52 |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Asset [Abstract] | ||
Derivative Asset | $ 2.3 | $ 2.3 |
Derivative Liability [Abstract] | ||
Derivative Liability | 6.1 | 7 |
Not Designated as Hedging Instrument | ||
Derivative Asset [Abstract] | ||
Other current derivative assets | 2.3 | 2.3 |
Other long-term derivative assets | 0 | 0 |
Derivative Asset | 2.3 | 2.3 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 4.7 | 5.9 |
Other long-term liabilities from risk management activities | 1.4 | 1.1 |
Derivative Liability | 6.1 | 7 |
Not Designated as Hedging Instrument | Natural gas contracts | ||
Derivative Asset [Abstract] | ||
Other current derivative assets | 0.3 | 0.1 |
Other long-term derivative assets | 0 | 0 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0.9 | 2.1 |
Other long-term liabilities from risk management activities | 0 | 0.1 |
Not Designated as Hedging Instrument | FTRs | ||
Derivative Asset [Abstract] | ||
Other current derivative assets | 2 | 2.2 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0 | 0.3 |
Not Designated as Hedging Instrument | Petroleum product contracts | ||
Derivative Asset [Abstract] | ||
Other current derivative assets | 0 | 0 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0.5 | 1.1 |
Not Designated as Hedging Instrument | Coal contracts | ||
Derivative Asset [Abstract] | ||
Other current derivative assets | 0 | 0 |
Other long-term derivative assets | 0 | 0 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 3.3 | 2.4 |
Other long-term liabilities from risk management activities | $ 1.4 | $ 1 |
DERIVATIVE INSTRUMENTS - NOTION
DERIVATIVE INSTRUMENTS - NOTIONAL VOLUMES/ GAINS AND LOSSES (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Risk management activities | |||
Gain (Loss) | $ (3.3) | $ 3.7 | $ 4.2 |
Natural gas contracts | |||
Risk management activities | |||
Volume Of Derivative Instruments | 22.9 Dth | 20.0 Dth | 15.5 Dth |
Gain (Loss) | $ (4.9) | $ 0.6 | $ (0.8) |
Petroleum product contracts | |||
Risk management activities | |||
Volume Of Derivative Instruments | 6.1 gallons | 5.3 gallons | 2.8 gallons |
Gain (Loss) | $ (1.7) | $ (0.1) | $ (0.1) |
FTRs | |||
Risk management activities | |||
Volume Of Derivative Instruments | 9.0 MWh | 8.7 MWh | 9.1 MWh |
Gain (Loss) | $ 3.3 | $ 3.2 | $ 5.1 |
DERIVATIVE INSTRUMENTS - NETTIN
DERIVATIVE INSTRUMENTS - NETTING ARRANGEMENTS AND CASH COLLATERAL (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Assets | ||
Gross amount recognized on the balance sheet | $ 2.3 | $ 2.3 |
Gross amount not offset on the balance sheet | (0.3) | (0.4) |
Net Amount | 2 | 1.9 |
Liabilities | ||
Gross amount recognized on balance sheet | 6.1 | 7 |
Gross amount not offset on balance sheet | (1.4) | (3.6) |
Net Amount | 4.7 | 3.4 |
Cash collateral | ||
Cash Collateral | 17.6 | 6.6 |
Cash collateral not offset | $ 1.1 | $ 3.2 |
REGULATORY ENVIRONMENT (Details
REGULATORY ENVIRONMENT (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||||
Dec. 31, 2015 | Apr. 30, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2015 | |
Regulatory environment | ||||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | |||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.00% | |||||
Approved common equity component average (as a percent) | 51.00% | |||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Electric rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | $ (7.9) | |||||
Approved annual rate increase (decrease), percentage | (0.80%) | |||||
Authorized revenue requirement for ReACT | $ 275 | |||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | |||||
Public Service Commission of Wisconsin (PSCW) | 2016 Rates | Natural gas rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | $ (6.2) | |||||
Approved annual rate increase (decrease), percentage | (2.10%) | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.20% | |||||
Approved common equity component average (as a percent) | 50.28% | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Electric rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | $ 24.6 | |||||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | |||||
Increase in cost of fuel for electric generation | $ 42 | |||||
Year-over-year positive (negative) change in decoupling refunded to or collected from customers | 9 | |||||
Customer recoveries (refunds) related to decoupling | (4) | |||||
Public Service Commission of Wisconsin (PSCW) | 2015 Rates | Natural gas rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | 15.4 | |||||
Year-over-year positive (negative) change in decoupling refunded to or collected from customers | (16) | |||||
Customer recoveries (refunds) related to decoupling | (8) | |||||
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.20% | |||||
Approved common equity component average (as a percent) | 50.14% | |||||
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Electric rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | $ (12.8) | |||||
Customer recoveries (refunds) related to decoupling | (13) | |||||
Public Service Commission of Wisconsin (PSCW) | 2014 Rates | Natural gas rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | $ 4 | |||||
Customer recoveries (refunds) related to decoupling | $ 8 | |||||
Public Service Commission of Wisconsin (PSCW) | 2013 Rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.30% | |||||
Approved common equity component average (as a percent) | 51.61% | |||||
Recovery of income tax amounts previously expensed due to the Federal Health Care Reform Act | $ 5.9 | |||||
Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Electric rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | 28.5 | |||||
Fuel refund | 20.5 | |||||
Deferral related to pension and other employee benefit costs | 7.3 | |||||
Annual decoupling mechanism cap | 14 | |||||
Public Service Commission of Wisconsin (PSCW) | 2013 Rates | Natural gas rates | ||||||
Regulatory environment | ||||||
Approved annual rate increase (decrease) | (3.4) | |||||
Deferral related to pension and other employee benefit costs | 2.1 | |||||
Annual decoupling mechanism cap | $ 8 | |||||
Michigan Public Service Commission (MPSC) | 2015 Rates | Electric rates | ||||||
Regulatory environment | ||||||
Approved return on equity (as a percent) | 10.20% | |||||
Approved common equity component average (as a percent) | 50.48% | |||||
Approved annual rate increase (decrease) | $ 4 | |||||
Period of rate implementation | 3 years |
SEGMENTS INFORMATION (Details)
SEGMENTS INFORMATION (Details) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Sep. 30, 2014USD ($) | Jun. 30, 2014USD ($) | Mar. 31, 2014USD ($) | Dec. 31, 2015USD ($)segment | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | |
Segment reporting information | |||||||||||
Number of reportable segments | segment | 3 | ||||||||||
Revenues | $ 337.2 | $ 390.8 | $ 330.3 | $ 425 | $ 397.7 | $ 370.9 | $ 359 | $ 556 | $ 1,483.3 | $ 1,683.6 | $ 1,580.5 |
Other operation and maintenance | 493.4 | 499.7 | 470.4 | ||||||||
Depreciation and amortization | 121 | 116.8 | 109.4 | ||||||||
Operating income | 25.5 | $ 88.5 | $ 44.2 | $ 69.9 | 56.2 | $ 77.7 | $ 36.3 | $ 87.4 | 228.1 | 257.6 | 240 |
Other income, net | 25.6 | 25.2 | 23.5 | ||||||||
Interest expense | 53.5 | 57.4 | 43.7 | ||||||||
Capital expenditures | 371 | 322 | 627.7 | ||||||||
Total assets | 4,505.1 | 4,269.3 | 4,505.1 | 4,269.3 | 3,951.6 | ||||||
Intersegment revenues | |||||||||||
Segment reporting information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Reconciling Eliminations | |||||||||||
Segment reporting information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Other operation and maintenance | (0.8) | 0 | 0 | ||||||||
Depreciation and amortization | 0 | (0.5) | (0.5) | ||||||||
Operating income | 0 | 0 | 0 | ||||||||
Other income, net | 0 | 0 | 0 | ||||||||
Interest expense | 0 | 0 | 0 | ||||||||
Capital expenditures | 0 | 0 | 0 | ||||||||
Total assets | 0 | 0 | 0 | 0 | 0 | ||||||
Reconciling Eliminations | Intersegment revenues | |||||||||||
Segment reporting information | |||||||||||
Revenues | (11.5) | (13.8) | (12.3) | ||||||||
Utility operations | |||||||||||
Segment reporting information | |||||||||||
Revenues | 1,483.3 | 1,683.6 | 1,580.5 | ||||||||
Other operation and maintenance | 493.9 | 499.3 | 470.1 | ||||||||
Depreciation and amortization | 120.7 | 116.7 | 109.3 | ||||||||
Operating income | 228 | 257.2 | 239.5 | ||||||||
Other income, net | 16 | 12.3 | 10.1 | ||||||||
Interest expense | 53.2 | 55.3 | 41.5 | ||||||||
Capital expenditures | 371 | 322 | 627.7 | ||||||||
Total assets | 4,416.8 | 4,183.9 | 4,416.8 | 4,183.9 | 3,865.9 | ||||||
Utility operations | Intersegment revenues | |||||||||||
Segment reporting information | |||||||||||
Revenues | 10.7 | 12.4 | 10.9 | ||||||||
Utility operations | Electric Utility | |||||||||||
Segment reporting information | |||||||||||
Revenues | 1,187.8 | 1,223.7 | 1,243 | ||||||||
Other operation and maintenance | 424.3 | 425.8 | 405 | ||||||||
Depreciation and amortization | 103.7 | 100.5 | 93.7 | ||||||||
Operating income | 194 | 204.8 | 189.5 | ||||||||
Other income, net | 15.6 | 11.7 | 9.9 | ||||||||
Interest expense | 43 | 45.1 | 33 | ||||||||
Capital expenditures | 319.4 | 272.7 | 590.3 | ||||||||
Total assets | 3,718.9 | 3,503 | 3,718.9 | 3,503 | 3,233.6 | ||||||
Utility operations | Electric Utility | Intersegment revenues | |||||||||||
Segment reporting information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Utility operations | Natural Gas Utility | |||||||||||
Segment reporting information | |||||||||||
Revenues | 295.5 | 459.9 | 337.5 | ||||||||
Other operation and maintenance | 69.6 | 73.5 | 65.1 | ||||||||
Depreciation and amortization | 17 | 16.2 | 15.6 | ||||||||
Operating income | 34 | 52.4 | 50 | ||||||||
Other income, net | 0.4 | 0.6 | 0.2 | ||||||||
Interest expense | 10.2 | 10.2 | 8.5 | ||||||||
Capital expenditures | 51.6 | 49.3 | 37.4 | ||||||||
Total assets | 697.9 | 680.9 | 697.9 | 680.9 | 632.3 | ||||||
Utility operations | Natural Gas Utility | Intersegment revenues | |||||||||||
Segment reporting information | |||||||||||
Revenues | 10.7 | 12.4 | 10.9 | ||||||||
Nonutility operations | Other | |||||||||||
Segment reporting information | |||||||||||
Revenues | 0 | 0 | 0 | ||||||||
Other operation and maintenance | 0.3 | 0.4 | 0.3 | ||||||||
Depreciation and amortization | 0.3 | 0.6 | 0.6 | ||||||||
Operating income | 0.1 | 0.4 | 0.5 | ||||||||
Other income, net | 9.6 | 12.9 | 13.4 | ||||||||
Interest expense | 0.3 | 2.1 | 2.2 | ||||||||
Capital expenditures | 0 | 0 | 0 | ||||||||
Total assets | $ 88.3 | $ 85.4 | 88.3 | 85.4 | 85.7 | ||||||
Nonutility operations | Other | Intersegment revenues | |||||||||||
Segment reporting information | |||||||||||
Revenues | $ 0.8 | $ 1.4 | $ 1.4 |
QUARTERLY FINANCIAL INFORMAT102
QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Operating revenues | $ 337.2 | $ 390.8 | $ 330.3 | $ 425 | $ 397.7 | $ 370.9 | $ 359 | $ 556 | $ 1,483.3 | $ 1,683.6 | $ 1,580.5 |
Operating income | 25.5 | 88.5 | 44.2 | 69.9 | 56.2 | 77.7 | 36.3 | 87.4 | 228.1 | 257.6 | 240 |
Net income attributed to common shareholder | $ 10.6 | $ 50.3 | $ 22.6 | $ 39 | $ 28 | $ 42.2 | $ 17.1 | $ 50.3 | $ 122.5 | $ 137.6 | $ 134.8 |
SCHEDULE II VALUATION AND QU103
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Allowance for doubtful accounts | |||
Balance at beginning of year | $ 3.2 | $ 2.5 | $ 2.5 |
Charged to expense | 6.7 | 7.3 | 5.2 |
Deductions | 7.4 | 6.6 | 5.2 |
Balance at end of year | $ 2.5 | $ 3.2 | $ 2.5 |