DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION | 9 Months Ended |
Sep. 30, 2015shares | |
Document and Entity Information | |
Entity Registrant Name | WISCONSIN PUBLIC SERVICE CORP |
Entity Central Index Key | 107,833 |
Document Type | 10-Q |
Document Period End Date | Sep. 30, 2015 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | 23,896,962 |
Document Fiscal Year Focus | 2,015 |
Document Fiscal Period Focus | Q3 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Income Statement [Abstract] | ||||
Operating revenues | $ 390.8 | $ 370.9 | $ 1,146.1 | $ 1,285.9 |
Cost of sales | 141.4 | 138.6 | 466.3 | 593.5 |
Other operation and maintenance | 120.3 | 116 | 356 | 374.4 |
Depreciation and amortization | 30.4 | 29.6 | 90.5 | 87 |
Property and revenue taxes | 10.2 | 9 | 30.7 | 29.6 |
Total operating expenses | 302.3 | 293.2 | 943.5 | 1,084.5 |
Operating income | 88.5 | 77.7 | 202.6 | 201.4 |
Other income, net | 6.7 | 5.8 | 19.8 | 20.1 |
Interest expense | 13.2 | 14.6 | 40.3 | 42.9 |
Other expense | (6.5) | (8.8) | (20.5) | (22.8) |
Income before taxes | 82 | 68.9 | 182.1 | 178.6 |
Income tax expense | 31 | 26 | 67.9 | 66.7 |
Net income | 51 | 42.9 | 114.2 | 111.9 |
Preferred stock dividend requirements | (0.7) | (0.7) | (2.3) | (2.3) |
Net income attributed to common shareholder | $ 50.3 | $ 42.2 | $ 111.9 | $ 109.6 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash and cash equivalents | $ 2.9 | $ 5.4 |
Accounts receivable and unbilled revenue, net of reserves of $4.5 and $3.2, respectively | 159.8 | 203.1 |
Receivables from related parties | 1.5 | 1.3 |
Inventories | ||
Fuel and natural gas | 90.3 | 85 |
Materials and supplies, at average cost | 42.2 | 39.2 |
Prepaid taxes | 31 | 65.7 |
Other current assets | 27 | 18.3 |
Current assets | 354.7 | 418 |
Long-term assets | ||
Property, plant, and equipment, net of accumulated depreciation of $1,560.1 and $1,542.5, respectively | 3,331.7 | 3,131 |
Regulatory assets | 466.6 | 457.1 |
Goodwill | 36.4 | 36.4 |
Pension and other postretirement benefit assets | 146.3 | 128.9 |
Other long-term assets | 103.6 | 107.3 |
Long-term assets | 4,084.6 | 3,860.7 |
Total assets | 4,439.3 | 4,278.7 |
Current liabilities | ||
Short-term debt | 102.1 | 145.1 |
Current portion of long-term debt | 125 | 125 |
Current portion of long-term debt to parent | 3 | 2.5 |
Accounts payable | 202 | 161.6 |
Payables to related parties | 19.7 | 16.9 |
Other current liabilities | 79 | 75.4 |
Current liabilities | 530.8 | 526.5 |
Long-term liabilities | ||
Long-term debt to parent | 0 | 2.9 |
Long-term debt | 1,049.6 | 1,049.5 |
Deferred income taxes | 767.9 | 722.1 |
Deferred investment tax credits | 7.5 | 7.8 |
Regulatory liabilities | 315.4 | 318.4 |
Accrual for Environmental Loss Contingencies | 86.1 | |
Environmental remediation liabilities | 86.3 | |
Pension and other postretirement benefit obligations | 40.1 | 37.6 |
Payables to related parties | 4.9 | 5.4 |
Other long-term liabilities | 80.2 | 71.6 |
Long-term liabilities | $ 2,351.7 | $ 2,301.6 |
Commitments and contingencies (note 6) | ||
Preferred stock – $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding | $ 51.2 | $ 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 | 863.4 | 782 |
Retained earnings | 546.6 | 521.8 |
Total liabilities and shareholders’ equity | $ 4,439.3 | $ 4,278.7 |
CONDENSED CONSOLIDATED BALANCE4
CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Accounts receivable, reserves (in dollars) | $ 4.5 | $ 3.2 |
Property, plant, and equipment, accumulated depreciation (in dollars) | $ 1,560.1 | $ 1,542.5 |
Preferred stock, par value (in dollars per share) | $ 100 | |
Preferred stock, shares authorized | 1,000,000 | |
Preferred stock, shares issued | 511,882 | |
Preferred stock, shares outstanding | 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 | |
Common stock, shares outstanding | 23,896,962 |
CONDENSED CONSOLIDATED STATEME5
CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 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 | 863.4 | 782 |
Retained earnings | 546.6 | 521.8 |
Total common stock equity | $ 1,505.6 | 1,399.4 |
Preferred stock, shares outstanding | 511,882 | |
Preferred stock – Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption | $ 51.2 | 51.2 |
Total long-term debt to parent (including current portion) | 3 | 5.4 |
Current portion of long-term debt to parent | (3) | (2.5) |
Long-term debt to parent | 0 | 2.9 |
Total First Mortgage Bonds and Senior Notes | 1,175.1 | 1,175.1 |
Unamortized discount on long-term debt | (0.5) | (0.6) |
Total | 1,174.6 | 1,174.5 |
Current portion of long-term debt | (125) | (125) |
Total long-term debt | 1,049.6 | 1,049.5 |
Total capitalization | $ 2,606.4 | 2,503 |
Long Term debt to parent, 8.76% Series, Year Due, 2015 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 8.76% | |
Total long-term debt to parent (including current portion) | $ 0 | 2 |
Long Term debt to parent, 7.35% Series, Year Due, 2016 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 7.35% | |
Total long-term debt to parent (including current portion) | $ 3 | 3.4 |
Long Term debt, 7.125% Series, Year Due, 2023 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 7.125% | |
First Mortgage Bonds | $ 0.1 | 0.1 |
Long Term debt, 6.375% Series, Year Due, 2015 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.375% | |
Senior Notes | $ 125 | 125 |
Long Term debt, 5.65% Series, Year Due, 2017 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.65% | |
Senior Notes | $ 125 | 125 |
Long Term debt, 6.08% Series, Year Due, 2028 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.08% | |
Senior Notes | $ 50 | 50 |
Long Term debt, 5.55% Series, Year Due, 2036 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.55% | |
Senior Notes | $ 125 | 125 |
Long Term Debt 3.671% Series, Year Due, 2042 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 3.671% | |
Senior Notes | $ 300 | 300 |
Long Term debt 4.752% Series, Year Due 2044 | ||
Schedule of Capitalization | ||
Debt Instrument, Interest Rate, Stated Percentage | 4.752% | |
Senior Notes | $ 450 | 450 |
Preferred stock, 5.00% Series | ||
Schedule of Capitalization | ||
Preferred stock, dividend rate, (as a percent) | 5.00% | |
Preferred stock, shares outstanding | 131,916 | |
Preferred stock – Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption | $ 13.2 | 13.2 |
Preferred stock, 5.04% Series | ||
Schedule of Capitalization | ||
Preferred stock, dividend rate, (as a percent) | 5.04% | |
Preferred stock, shares outstanding | 29,983 | |
Preferred stock – Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption | $ 3 | 3 |
Preferred stock, 5.08% Series | ||
Schedule of Capitalization | ||
Preferred stock, dividend rate, (as a percent) | 5.08% | |
Preferred stock, shares outstanding | 49,983 | |
Preferred stock – Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption | $ 5 | 5 |
Preferred stock, 6.76% Series | ||
Schedule of Capitalization | ||
Preferred stock, dividend rate, (as a percent) | 6.76% | |
Preferred stock, shares outstanding | 150,000 | |
Preferred stock – Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption | $ 15 | 15 |
Preferred stock, 6.88% Series | ||
Schedule of Capitalization | ||
Preferred stock, dividend rate, (as a percent) | 6.88% | |
Preferred stock, shares outstanding | 150,000 | |
Preferred stock – Cumulative; $100 par value; 1,000,000 shares authorized with no mandatory redemption | $ 15 | $ 15 |
CONDENSED CONSOLIDATED STATEME6
CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) | Sep. 30, 2015$ / sharesshares |
CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION | |
Common stock, par value (in dollars per share) | $ / shares | $ 4 |
Common stock, shares authorized | 32,000,000 |
Common stock, shares outstanding | 23,896,962 |
Preferred stock, par value (in dollars per share) | $ / shares | $ 100 |
Preferred stock, shares authorized | 1,000,000 |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Operating Activities | ||
Net income | $ 114.2 | $ 111.9 |
Reconciliation to cash provided by operating activities | ||
Depreciation and amortization | 91.9 | 85.9 |
Deferred income taxes and investment tax credits, net | 36.8 | 52.1 |
Contributions to pension and other postretirement plans | (0.9) | (46.7) |
Change in | ||
Accounts receivable and unbilled revenues | 40.9 | 45 |
Inventories | (4.1) | (25.6) |
Other current assets | 21.7 | 40.1 |
Accounts payable | (5.4) | (10.3) |
Other current liabilities | 24.9 | (8.3) |
Other, net | 0 | (16.1) |
Net cash provided by operating activities | 320 | 228 |
Investing Activities | ||
Capital expenditures | (265.6) | (215.8) |
Cost of removal, net of salvage | (2.7) | (2.1) |
Other, net | (1.6) | (0.7) |
Net cash used in investing activities | (269.9) | (218.6) |
Financing Activities | ||
Preferred stock dividend requirements | (2.3) | (2.3) |
Short-term debt, net | (43) | 37.4 |
Payments of long-term debt to parent | (2.4) | (0.6) |
Dividends to parent | (86.3) | (83.9) |
Equity contribution from parent | 85 | 40 |
Other | (3.6) | (2.1) |
Net cash used in financing activities | (52.6) | (11.5) |
Net change in cash and cash equivalents | (2.5) | (2.1) |
Cash and cash equivalents at beginning of period | 5.4 | 5.7 |
Cash and cash equivalents at end of period | 2.9 | 3.6 |
Supplemental Cash Flow Information | ||
Cash paid for interest | 29.2 | 27.9 |
Cash received for income taxes | $ (13.2) | $ (5.1) |
GENERAL INFORMATION
GENERAL INFORMATION | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL INFORMATION | GENERAL INFORMATION On June 29, 2015, our parent company, Integrys, was acquired by Wisconsin Energy Corporation, and the combined company was renamed WEC Energy Group, Inc. In this report, when we refer to the "WEC Merger," we are referring to this acquisition. See Note 2, WEC Merger, for more information on the acquisition. As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated balance sheets, condensed consolidated statements of capitalization, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation. We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2014 . Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2015 , are not necessarily indicative of expected results for 2015 due to seasonal variations and other factors. Our balance sheet reflects the historical basis of our assets and liabilities, as WEC Energy Group did not elect pushdown accounting for the WEC Merger. This is consistent with how our financial statements are viewed by our regulators. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. Reclassifications As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC Energy Group. The previously reported items below were reclassified to conform to the current period presentation. Only significant 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 $2.1 million and $6.7 million for the three and nine months ended September 30, 2014 , 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 $1.6 million and $4.6 million for the three and nine months ended September 30, 2014 , 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. 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. |
WEC MERGER
WEC MERGER | 9 Months Ended |
Sep. 30, 2015 | |
Business Combinations [Abstract] | |
WEC MERGER | WEC MERGER On June 29, 2015, the WEC Merger was completed, and our parent company became a wholly owned subsidiary of WEC Energy Group. The acquisition was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order 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 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. |
CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS | 9 Months Ended |
Sep. 30, 2015 | |
Cash and Cash Equivalents [Abstract] | |
CASH AND CASH EQUIVALENTS | Accounts payable related to construction costs totaled $74.9 million and $56.2 million for the nine months ended September 30, 2015 and 2014, respectively. These costs were treated as noncash investing activities. |
GOODWILL AND OTHER INTANGIBLE A
GOODWILL AND OTHER INTANGIBLE ASSETS | 9 Months Ended |
Sep. 30, 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 nine months ended September 30, 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 the balance sheets. September 30, 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 $ (6.7 ) $ 8.9 $ 15.6 $ (4.3 ) $ 11.3 Unamortized intangible assets 0.4 — 0.4 — — — Total intangible assets $ 16.0 $ (6.7 ) $ 9.3 $ 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 September 30, 2015 , was approximately three years . |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 9 Months Ended |
Sep. 30, 2015 | |
Short-term Debt [Abstract] | |
SHORT-TERM DEBT AND LINES OF CREDIT | SHORT-TERM DEBT AND LINES OF CREDIT Our outstanding short-term borrowings were as follows: (in millions, except percentages) September 30, 2015 December 31, 2014 Commercial paper $ 102.1 $ 145.1 Average interest rate on commercial paper outstanding 0.29 % 0.32 % Our average amount of commercial paper borrowings based on daily outstanding balances during the nine months ended September 30, 2015 , was $141.4 million with a weighted-average interest rate during the period of 0.29% . We manage our liquidity by maintaining what we believe to be adequate external financing commitments. The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities: (in millions) Maturity September 30, 2015 Revolving credit facility June 2017 $ 115.0 Revolving credit facility May 2019 135.0 Total short-term credit capacity $ 250.0 Less: Commercial paper outstanding 102.1 Available capacity under existing agreements $ 147.9 |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | COMMITMENTS AND CONTINGENCIES Unconditional Purchase Obligations 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. Our minimum future commitments related to these purchase obligations as of September 30, 2015 , was $1,137.5 million . Environmental Matters We periodically review our exposure for environmental remediation costs as evidence becomes available indicating that our liability has changed. Given current information, including the following, we believe that future costs in excess of the amounts accrued and/or disclosed on all presently known and quantifiable environmental contingencies will not be material to our financial position or results of operations. We have a program of comprehensive environmental remediation planning for former manufactured gas plant sites and coal combustion product disposal/landfill sites. We perform ongoing assessments of these sites. Air Quality Sulfur Dioxide National Ambient Air Quality Standards The EPA issued a 1-Hour SO 2 NAAQS that became effective in August 2010. In August 2015, the EPA issued the Data Requirements Rule that established procedures and timelines for implementation of the revised standard. The 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 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 is classified as nonattainment. A plan would need to be developed requiring emission reductions to allow attainment by 2023. Alternatively, if a state opted out of modeling and instead chose monitoring, 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 permitting constraints for area sources, and for other new or existing sources in the area. In March 2015, a Federal Court in the Northern District of California entered a consent decree relating to the implementation of the revised 1-Hour SO 2 standard that Sierra Club and the EPA had agreed upon in May 2014. This consent decree has 1-Hour SO 2 implementation dates that are sooner than the Data Requirements Rule. We believe our fleet is well positioned to meet this regulation once it is finalized. 8-Hour Ozone National Ambient Air Quality Standard The EPA completed its review of the 2008 8-hour ozone standard in November 2014, and announced a proposal to lower the NAAQS. In October 2015, the EPA released the final rule, which effectively 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. We will be required to comply with the new reduction requirements 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 mercury rules that require a 90% reduction of mercury. In June 2015, the United States 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 remains in effect pending action by the D.C. Circuit Court of Appeals, which has the option to vacate the rule while the EPA completes its cost evaluation. If the rule is stayed or revoked, the Wisconsin mercury rule is likely to be the governing standard for our units. Our compliance plans currently include capital projects for our jointly owned plants to achieve the required reductions for MATS and the state mercury rules. We are working on the addition of a multi-pollutant control technology at Weston Unit 3. Controls for acid gases and mercury were also installed at the Pulliam units. We received a one year MATS compliance extension for Weston Unit 3 from the WDNR. Climate Change In August 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 require states to submit plans as early as September 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. 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. Any state or federal compliance plans that are developed could be subject to change based upon the outcome of this litigation. Weston and Pulliam Clean Air Act (CAA) Issues In November 2009, the EPA issued a Notice of Violation (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 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. Columbia and Edgewater CAA Issues In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the owner and 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, WP&L, 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 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. Weston Title V Air Permit Issues 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 an 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 nitrogen oxide emissions from the Weston Unit 4 auxiliary boiler. In June 2015, the WDNR issued an NOV to us 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. 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 BTA for minimizing adverse environmental impacts. Impacts are both from entrainment (larvae, eggs, and small fry being drawn into cooling water systems) and impingement (larger fish being pinned against cooling water intake structures). 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 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 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 2015-2018, 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 (units 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. Steam Electric Effluent Guidelines In September 2015, the EPA issued the final steam electric effluent guidelines rule, which governs discharges of wastewater from our power plant processes in Wisconsin. 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. 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 to be significant because we currently have a program of beneficial utilization for most of our coal combustion byproducts. If needed, we have landfill capacity that meets the rule requirements for our remaining coal combustion product sources. 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. All sites are at various stages of investigation, monitoring, remediation, and closure. In addition, we are coordinating the investigation and cleanup of the sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below. The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites. We established the following regulatory assets and reserves related to manufactured gas plant sites: (in millions) September 30, 2015 December 31, 2014 Regulatory assets $ 104.5 $ 102.3 Reserves for future remediation 86.1 86.3 See Note 1 5, Commitments and Contingencies, in Item 8 of our 2014 Annual Report on Form 10-K for additional information regarding environmental matters affecting our operations. |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
EMPLOYEE BENEFIT PLANS | EMPLOYEE BENEFIT PLANS The following table shows the components of net periodic pension and other postretirement employee benefits (OPEB) costs for our benefit plans: Pension Costs OPEB Costs Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 2015 2014 2015 2014 Service cost $ 2.6 $ 2.2 $ 8.0 $ 6.5 $ 2.2 $ 1.9 $ 6.5 $ 5.8 Interest cost 8.0 8.6 23.8 25.8 2.6 2.7 7.8 8.8 Expected return on plan assets (16.3 ) (16.0 ) (48.7 ) (48.0 ) (4.0 ) (4.0 ) (12.0 ) (12.0 ) Loss on plan settlement — — 0.1 0.4 — — — — Amortization of prior service cost (credit) 0.1 0.1 0.2 0.4 (2.3 ) (2.3 ) (6.9 ) (5.7 ) Amortization of net actuarial loss 5.3 3.7 15.8 11.2 0.8 0.7 2.7 2.0 Net periodic benefit cost (credit) $ (0.3 ) $ (1.4 ) $ (0.8 ) $ (3.7 ) $ (0.7 ) $ (1.0 ) $ (1.9 ) $ (1.1 ) 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. |
COMMON EQUITY
COMMON EQUITY | 9 Months Ended |
Sep. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | COMMON EQUITY Stock-Based Compensation Our employees were granted awards under Integrys’s stock-based compensation plans. Per the Merger Agreement, immediately prior to completion of the acquisition, all outstanding stock-based compensation awards became fully vested and were canceled in exchange for the right to be paid out in cash to award recipients. See Note 2, WEC Merger, for more information regarding the acquisition. The intrinsic values of the awards canceled due to the acquisition were $1.5 million and $5.2 million for performance stock rights and restricted stock units, respectively. The intrinsic value of stock options canceled 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 three and nine months ended September 30 : Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 Stock options $ — $ 0.1 $ — $ 0.4 Performance stock rights — 0.1 1.3 3.9 Restricted share units — 0.7 3.5 2.7 Total stock-based compensation expense $ — $ 0.9 $ 4.8 $ 7.0 Deferred income tax benefit $ — $ 0.4 $ 1.9 $ 2.8 A summary of the activity for our stock-based compensation awards for the nine months ended September 30, 2015 , is presented below: Stock Options Performance Stock Rights Restricted Stock Units Outstanding at December 31, 2014 5,714 13,937 70,544 Granted — — 30,174 Dividend equivalents N/A N/A 1,267 Exercised/Distributed/Vested and Released * (2,752 ) (2,229 ) (28,428 ) Adjustment for performance stock rights distributed or canceled N/A 9,555 N/A Transferred — — (166 ) Canceled due to WEC Merger (2,962 ) (21,263 ) (73,391 ) Outstanding at September 30, 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 or return capital to the sole holder of our common stock, Integrys. The PSCW allows us to pay dividends on our common stock of no more than 103% of the previous year's common stock dividend. We may return capital to Integrys if our average financial common equity ratio is at least 51% on a calendar year basis. We must obtain PSCW approval if a return of capital would cause our average financial common equity ratio to fall below this level. Integrys's right to receive dividends on our common stock is also subject to the prior rights of our preferred shareholders and to provisions in our restated articles of incorporation, which limit the amount of common stock dividends that we may pay if our common stock and common stock surplus accounts constitute less than 25% of our total capitalization. See Note 15, Subsequent Events , for information regarding the redemption of our preferred stock. Our short-term debt obligations contain financial and other covenants, including but not limited to, a requirement to maintain a debt to total capitalization ratio not to exceed 65% . 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. |
DERIVATIVE INSTRUMENTS
DERIVATIVE INSTRUMENTS | 9 Months Ended |
Sep. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE INSTRUMENTS | DERIVATIVE INSTRUMENTS We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by the PSCW and the MPSC. We record derivative instruments on the balance sheet as an asset or liability measured at fair value. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities. The following table shows our derivative assets and derivative liabilities: September 30, 2015 December 31, 2014 (in millions) Balance Sheet Presentation Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Natural gas Other current $ 0.3 $ 1.0 $ 0.1 $ 2.1 Natural gas Other long-term — 0.1 — 0.1 FTRs Other current 3.3 — 2.2 0.3 Petroleum products Other current — 0.3 — 1.1 Coal Other current — 3.4 — 2.4 Coal Other long-term — 2.4 — 1.0 Other current 3.6 4.7 2.3 5.9 Other long-term — 2.5 — 1.1 Total $ 3.6 $ 7.2 $ 2.3 $ 7.0 Gains (losses) on derivative instruments are primarily included in cost of sales on the condensed consolidated income statements. Our estimated notional volumes and gains (losses) were as follows: Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 (in millions) Volume Gains (Losses) Volume Gains (Losses) Natural Gas 3.7 Dth $ (0.7 ) 3.1 Dth $ (0.6 ) Petroleum products 1.5 gallons (0.4 ) 1.6 gallons — FTRs 2.5 MWh 1.6 2.2 MWh 1.3 Total $ 0.5 $ 0.7 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 (in millions) Volume Gains (Losses) Volume Gains Natural Gas 14.9 Dth $ (3.2 ) 14.1 Dth $ 1.2 Petroleum products 4.7 gallons (1.4 ) 4.2 gallons — FTRs 6.8 MWh 1.4 6.4 MWh 3.2 Total $ (3.2 ) $ 4.4 The amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At September 30, 2015 , and December 31, 2014 , we had posted collateral of $17.0 million and $6.6 million , respectively, in our margin accounts. These amounts are recorded on the condensed consolidated balance sheets in other current assets. The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on the condensed consolidated balance sheet: September 30, 2015 December 31, 2014 Derivative Derivative Derivative Derivative (in millions) Assets Liabilities Assets Liabilities Gross amount recognized on the balance sheet $ 3.6 $ 7.2 $ 2.3 $ 7.0 Gross amount not offset on balance sheet * (0.3 ) (1.4 ) (0.4 ) (3.6 ) Net Amount $ 3.3 $ 5.8 $ 1.9 $ 3.4 * Includes cash collateral posted of $1.1 million and $3.2 million as of September 30, 2015 , and December 31, 2014 , respectively. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows: Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods. Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. When possible, we base the valuations of our risk management 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 valuations for certain physical coal contracts are categorized as Level 3 as they are based on significant assumptions made to extrapolate prices from the last quoted period through the end of the transaction term. The valuation for FTRs is derived from historical data from MISO, which is also considered a Level 3 input. The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: September 30, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative Assets Natural gas contracts $ 0.3 $ — $ — $ 0.3 FTRs — — 3.3 3.3 Total Derivative Assets $ 0.3 $ — $ 3.3 $ 3.6 Derivative Liabilities Natural gas contracts $ 1.1 $ — $ — $ 1.1 Petroleum products contracts 0.3 — — 0.3 Coal contracts — 0.4 5.4 5.8 Total Derivative Liabilities $ 1.4 $ 0.4 $ 5.4 $ 7.2 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 market. The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 Balance at the beginning of period $ (1.3 ) $ 4.9 $ (0.3 ) $ (1.3 ) Net realized and unrealized gains (losses) 0.2 (0.4 ) (11.2 ) 3.5 Purchases — — 9.8 4.3 Settlements (1.0 ) (1.5 ) (0.4 ) (3.5 ) Balance at the end of period $ (2.1 ) $ 3.0 $ (2.1 ) $ 3.0 Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the condensed consolidated statements of income. Fair Value of Financial Instruments The following table shows the financial instruments included on our condensed consolidated balance sheets that are not recorded at fair value: September 30, 2015 December 31, 2014 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt $ 1,175.1 $ 1,221.7 $ 1,175.1 $ 1,286.2 Long-term debt to parent 3.0 3.1 5.4 5.7 Preferred stock 51.2 51.8 51.2 52.0 Due to the short-term nature of cash and cash equivalents, accounts receivable, accounts payable, and outstanding commercial paper, 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, but excluding unamortized discount on 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. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, when available, or by using a perpetual dividend discount model. |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 9 Months Ended |
Sep. 30, 2015 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | REGULATORY ENVIRONMENT 2016 Wisconsin Rate Case In April 2015, we filed an application with the PSCW to increase retail electric rates $94.1 million and increase retail natural gas rates $9.4 million , with rates expected to be effective January 1, 2016. Our request reflects a 10.2% ROE and a common equity component of 50.52% . The proposed retail electric rate increase is primarily driven by the expected completion in 2016 of the ReACT™ emission control technology at Weston Unit 3, the System Modernization and Reliability Project, and technology upgrades at the Fox Energy Center. Also included are increases in expenses for electric transmission, customer service, other operating and maintenance, and general inflation. The proposed retail natural gas rate increase is driven by higher operating and maintenance costs, general inflation, and an increase in the amount of outstanding equity supporting construction projects. In May 2015, we filed a revised application with the PSCW adjusting our requested retail electric rate increase to $96.9 million and our requested retail natural gas rate increase to $9.1 million . The revised requests are primarily driven by revisions to forecasted retail electric and natural gas revenues and employee benefit costs. In October 2015, we adjusted our requested retail electric rate increase to $48.0 million and our requested retail natural gas rate increase to $4.4 million . The revised requests are primarily driven by updates to fuel and purchased power costs, the cost of natural gas, payroll expense, employee benefit costs, and electric transmission expense. At the same time, we offered a two year earnings sharing mechanism to address concerns about acquisition-related benefits. Under the terms of our proposal, if we earn above our authorized return, 50% of the first 50 basis points of additional utility earnings will be shared with customers and used to reduce a deferral for ReACT™ if approved by the PSCW. If approved, we would defer the revenue requirement of ReACT™ costs above the authorized $275.0 million level until the next rate case. All utility earnings above the first 50 basis points will be solely used to reduce the deferral. 2015 Wisconsin Rates 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 10.2% 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 are refunding 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 in 2015 and concluding by 2023. See Note 6, 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. Finally, the PSCW ordered that 2015 fuel costs should continue to be monitored using a two percent 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 are refunding 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. 2015 Michigan Rates 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 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 in 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 OF BUSINESS
SEGMENTS OF BUSINESS | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
SEGMENTS OF BUSINESS | SEGMENTS OF BUSINESS At September 30, 2015 , we reported three segments. Our principal business segments are our regulated electric utility operations and our regulated natural gas utility operations. Our other segment includes nonutility activities, as well as equity earnings from our investments in WRPC and WPS Investments, LLC, which holds an interest in ATC. The tables below present information related to our reportable segments: Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended September 30, 2015 External revenues $ 346.5 $ 44.3 $ 390.8 $ — $ — $ 390.8 Intersegment revenues — 3.7 3.7 0.2 (3.9 ) — Depreciation and amortization 26.0 4.3 30.3 0.1 — 30.4 Operating income 84.9 3.5 88.4 0.1 — 88.5 Interest expense 10.6 2.5 13.1 0.1 — 13.2 Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended September 30, 2014 External revenues $ 327.9 $ 43.0 $ 370.9 $ — $ — $ 370.9 Intersegment revenues — 3.4 3.4 0.3 (3.7 ) — Depreciation and amortization 25.5 4.1 29.6 0.1 (0.1 ) 29.6 Operating income (loss) 80.2 (2.7 ) 77.5 0.2 — 77.7 Interest expense 11.4 2.6 14.0 0.6 — 14.6 Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Nine Months Ended September 30, 2015 External revenues $ 920.1 $ 226.0 $ 1,146.1 $ — $ — $ 1,146.1 Intersegment revenues — 8.4 8.4 0.6 (9.0 ) — Depreciation and amortization 77.5 12.7 90.2 0.3 — 90.5 Operating income 179.3 23.3 202.6 — — 202.6 Interest expense 32.4 7.7 40.1 0.2 — 40.3 Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Nine Months Ended September 30, 2014 External revenues $ 941.2 $ 344.7 $ 1,285.9 $ — $ — $ 1,285.9 Intersegment revenues — 10.5 10.5 1.0 (11.5 ) — Depreciation and amortization 74.7 12.2 86.9 0.5 (0.4 ) 87.0 Operating income 164.3 36.7 201.0 0.4 — 201.4 Interest expense 33.5 7.8 41.3 1.6 — 42.9 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 9 Months Ended |
Sep. 30, 2015 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | RELATED PARTY TRANSACTIONS 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 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 WEC Business Services, LLC (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 two other state commissions have approved the Non-WBS AIA or granted appropriate waivers related to the Non-WBS AIA. Approval of the Non-WBS AIA is still needed from the Minnesota Public Utilities Commission. The interim WBS AIAs have been approved by the PSCW. 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, WEC Energy Group will need to 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) September 30, 2015 December 31, 2014 Notes payable * Integrys $ 3.0 $ 5.4 Accounts payable Network transmission services from ATC 8.4 8.2 Liability related to income tax allocation Integrys 5.6 6.1 * WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys. At September 30, 2015 , and December 31, 2014 , the current portion of the note payable was $3.0 million and $2.5 million , respectively. In addition to the above transactions, Integrys had a $20.0 million parental guarantee at September 30, 2015, related to an interconnection agreement between ATC and us. This guarantee is not reflected on our condensed consolidated balance sheets. The following table shows activity associated with related party transactions: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 Electric transactions Sales to UPPCO (1) $ — $ 4.1 $ — $ 15.3 Sales to Integrys Transportation Fuels, LLC — 0.1 — 0.1 Natural gas transactions Sales to Wisconsin Electric 0.3 — 0.3 — Sales to IES (2) — 0.3 — 0.5 Purchases from IES (2) — 0.1 — 2.5 Interest expense (3) Integrys — 0.2 0.2 0.4 Transactions with equity method investees Charges from ATC for network transmission services 25.3 24.7 76.0 74.2 Charges to ATC for services and construction 2.9 2.4 7.5 7.5 Purchases of energy from WRPC 1.0 0.9 3.1 3.0 Charges to WRPC for operations 0.5 0.3 1.0 1.0 Equity earnings from WPS Investments, LLC (4) 2.5 2.6 6.8 7.7 Sales of electricity to AMP Trillium, LLC (5) — — 0.1 — (1) Integrys sold UPPCO in August 2014. (2) Integrys sold IES's retail energy business in November 2014. (3) WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys. (4) WPS Investments, LLC is a consolidated subsidiary of Integrys 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 September 30, 2015 , we had a 10.87% 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. (5) AMP Trillium, LLC is a joint venture between Integrys Transportation Fuels, LLC, a subsidiary of Integrys, and AMP Americas, LLC. This joint venture owns and operates compressed natural gas fueling stations. |
NEW ACCOUNTING PRONOUCEMENTS
NEW ACCOUNTING PRONOUCEMENTS | 9 Months Ended |
Sep. 30, 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. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption for fiscal years and interim periods beginning after December 15, 2016, permitted. The standard 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 consolidated financial statements. Debt Issuance Costs In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The guidance requires debt issuance costs to be presented on the balance sheet as a reduction to the carrying value of the corresponding debt, rather than as an asset as it is currently presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The standard requires retrospective application by restating each prior period presented in the financial statements. We are currently assessing the effects this guidance may have on our consolidated financial statements. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 9 Months Ended |
Sep. 30, 2015 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | SUBSEQUENT EVENTS In October 2015, we announced the planned redemption of all of the remaining $0.1 million aggregate principal amount of First Mortgage Bonds, 7-1/8% 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. The scheduled date of redemption is November 13, 2015. Following this redemption, we will discharge our mortgage indenture and do not intend to issue additional first mortgage bonds under the mortgage indenture. All $1,175.0 million of our senior notes outstanding are also secured by first mortgage bonds. On the redemption date of the 7-1/8% Series, the senior notes will become senior unsecured obligations and rank equally with all of our other unsecured and unsubordinated obligations. In addition, on October 14, 2015, we issued notices of redemption for 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 scheduled date of redemption is November 13, 2015. The aggregate redemption price is $52.8 million , plus accumulated and unpaid dividends. |
GENERAL INFORMATION (Policies)
GENERAL INFORMATION (Policies) | 9 Months Ended |
Sep. 30, 2015 | |
Accounting policies | |
Consolidation | As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the condensed consolidated statements of income, condensed consolidated balance sheets, condensed consolidated statements of capitalization, and condensed consolidated statements of cash flows, unless otherwise noted. In this report, when we refer to "us," "we," "our," or "ours," we are referring to Wisconsin Public Service Corporation. |
Basis of accounting | We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended December 31, 2014 . Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the three and nine months ended September 30, 2015 , are not necessarily indicative of expected results for 2015 due to seasonal variations and other factors. Our balance sheet reflects the historical basis of our assets and liabilities, as WEC Energy Group did not elect pushdown accounting for the WEC Merger. This is consistent with how our financial statements are viewed by our regulators. In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results. |
Reclassifications | Reclassifications As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC Energy Group. The previously reported items below were reclassified to conform to the current period presentation. Only significant 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 $2.1 million and $6.7 million for the three and nine months ended September 30, 2014 , 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 $1.6 million and $4.6 million for the three and nine months ended September 30, 2014 , 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. 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. |
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 risk management 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 valuations for certain physical coal contracts are categorized as Level 3 as they are based on significant assumptions made to extrapolate prices from the last quoted period through the end of the transaction term. The valuation for FTRs is derived from historical data from MISO, which is also considered a Level 3 input. |
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. The guidance is based on the principle that revenue is recognized when promised goods or services are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, with early adoption for fiscal years and interim periods beginning after December 15, 2016, permitted. The standard 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 consolidated financial statements. Debt Issuance Costs In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. The guidance requires debt issuance costs to be presented on the balance sheet as a reduction to the carrying value of the corresponding debt, rather than as an asset as it is currently presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The standard requires retrospective application by restating each prior period presented in the financial statements. We are currently assessing the effects this guidance may have on our consolidated financial statements. |
GOODWILL AND OTHER INTANGIBLE24
GOODWILL AND OTHER INTANGIBLE ASSETS (Tables) | 9 Months Ended |
Sep. 30, 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 the balance sheets. September 30, 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 $ (6.7 ) $ 8.9 $ 15.6 $ (4.3 ) $ 11.3 Unamortized intangible assets 0.4 — 0.4 — — — Total intangible assets $ 16.0 $ (6.7 ) $ 9.3 $ 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 September 30, 2015 , was approximately three years . |
SHORT-TERM DEBT AND LINES OF 25
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Short-term Debt [Abstract] | |
Schedule of short-term borrowings | Our outstanding short-term borrowings were as follows: (in millions, except percentages) September 30, 2015 December 31, 2014 Commercial paper $ 102.1 $ 145.1 Average interest rate on commercial paper outstanding 0.29 % 0.32 % |
Schedule of revolving credit facilities and remaining available capacity | The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing program, including remaining available capacity under these facilities: (in millions) Maturity September 30, 2015 Revolving credit facility June 2017 $ 115.0 Revolving credit facility May 2019 135.0 Total short-term credit capacity $ 250.0 Less: Commercial paper outstanding 102.1 Available capacity under existing agreements $ 147.9 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of regulatory assets and reserves related to manufactured gas plant sites | We established the following regulatory assets and reserves related to manufactured gas plant sites: (in millions) September 30, 2015 December 31, 2014 Regulatory assets $ 104.5 $ 102.3 Reserves for future remediation 86.1 86.3 |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Schedule of the components of net periodic benefit cost | The following table shows the components of net periodic pension and other postretirement employee benefits (OPEB) costs for our benefit plans: Pension Costs OPEB Costs Three Months Ended September 30 Nine Months Ended September 30 Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 2015 2014 2015 2014 Service cost $ 2.6 $ 2.2 $ 8.0 $ 6.5 $ 2.2 $ 1.9 $ 6.5 $ 5.8 Interest cost 8.0 8.6 23.8 25.8 2.6 2.7 7.8 8.8 Expected return on plan assets (16.3 ) (16.0 ) (48.7 ) (48.0 ) (4.0 ) (4.0 ) (12.0 ) (12.0 ) Loss on plan settlement — — 0.1 0.4 — — — — Amortization of prior service cost (credit) 0.1 0.1 0.2 0.4 (2.3 ) (2.3 ) (6.9 ) (5.7 ) Amortization of net actuarial loss 5.3 3.7 15.8 11.2 0.8 0.7 2.7 2.0 Net periodic benefit cost (credit) $ (0.3 ) $ (1.4 ) $ (0.8 ) $ (3.7 ) $ (0.7 ) $ (1.0 ) $ (1.9 ) $ (1.1 ) |
COMMON EQUITY (Tables)
COMMON EQUITY (Tables) | 9 Months Ended |
Sep. 30, 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 three and nine months ended September 30 : Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 Stock options $ — $ 0.1 $ — $ 0.4 Performance stock rights — 0.1 1.3 3.9 Restricted share units — 0.7 3.5 2.7 Total stock-based compensation expense $ — $ 0.9 $ 4.8 $ 7.0 Deferred income tax benefit $ — $ 0.4 $ 1.9 $ 2.8 |
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 nine months ended September 30, 2015 , is presented below: Stock Options Performance Stock Rights Restricted Stock Units Outstanding at December 31, 2014 5,714 13,937 70,544 Granted — — 30,174 Dividend equivalents N/A N/A 1,267 Exercised/Distributed/Vested and Released * (2,752 ) (2,229 ) (28,428 ) Adjustment for performance stock rights distributed or canceled N/A 9,555 N/A Transferred — — (166 ) Canceled due to WEC Merger (2,962 ) (21,263 ) (73,391 ) Outstanding at September 30, 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. |
DERIVATIVE INSTRUMENTS (Tables)
DERIVATIVE INSTRUMENTS (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative assets and derivative liabilities | The following table shows our derivative assets and derivative liabilities: September 30, 2015 December 31, 2014 (in millions) Balance Sheet Presentation Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Natural gas Other current $ 0.3 $ 1.0 $ 0.1 $ 2.1 Natural gas Other long-term — 0.1 — 0.1 FTRs Other current 3.3 — 2.2 0.3 Petroleum products Other current — 0.3 — 1.1 Coal Other current — 3.4 — 2.4 Coal Other long-term — 2.4 — 1.0 Other current 3.6 4.7 2.3 5.9 Other long-term — 2.5 — 1.1 Total $ 3.6 $ 7.2 $ 2.3 $ 7.0 |
Estimated notional volumes and gains (losses) | Our estimated notional volumes and gains (losses) were as follows: Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 (in millions) Volume Gains (Losses) Volume Gains (Losses) Natural Gas 3.7 Dth $ (0.7 ) 3.1 Dth $ (0.6 ) Petroleum products 1.5 gallons (0.4 ) 1.6 gallons — FTRs 2.5 MWh 1.6 2.2 MWh 1.3 Total $ 0.5 $ 0.7 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 (in millions) Volume Gains (Losses) Volume Gains Natural Gas 14.9 Dth $ (3.2 ) 14.1 Dth $ 1.2 Petroleum products 4.7 gallons (1.4 ) 4.2 gallons — FTRs 6.8 MWh 1.4 6.4 MWh 3.2 Total $ (3.2 ) $ 4.4 |
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 the condensed consolidated balance sheet: September 30, 2015 December 31, 2014 Derivative Derivative Derivative Derivative (in millions) Assets Liabilities Assets Liabilities Gross amount recognized on the balance sheet $ 3.6 $ 7.2 $ 2.3 $ 7.0 Gross amount not offset on balance sheet * (0.3 ) (1.4 ) (0.4 ) (3.6 ) Net Amount $ 3.3 $ 5.8 $ 1.9 $ 3.4 * Includes cash collateral posted of $1.1 million and $3.2 million as of September 30, 2015 , and December 31, 2014 , respectively |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 9 Months Ended |
Sep. 30, 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: September 30, 2015 (in millions) Level 1 Level 2 Level 3 Total Derivative Assets Natural gas contracts $ 0.3 $ — $ — $ 0.3 FTRs — — 3.3 3.3 Total Derivative Assets $ 0.3 $ — $ 3.3 $ 3.6 Derivative Liabilities Natural gas contracts $ 1.1 $ — $ — $ 1.1 Petroleum products contracts 0.3 — — 0.3 Coal contracts — 0.4 5.4 5.8 Total Derivative Liabilities $ 1.4 $ 0.4 $ 5.4 $ 7.2 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: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 Balance at the beginning of period $ (1.3 ) $ 4.9 $ (0.3 ) $ (1.3 ) Net realized and unrealized gains (losses) 0.2 (0.4 ) (11.2 ) 3.5 Purchases — — 9.8 4.3 Settlements (1.0 ) (1.5 ) (0.4 ) (3.5 ) Balance at the end of period $ (2.1 ) $ 3.0 $ (2.1 ) $ 3.0 |
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 condensed consolidated balance sheets that are not recorded at fair value: September 30, 2015 December 31, 2014 (in millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt $ 1,175.1 $ 1,221.7 $ 1,175.1 $ 1,286.2 Long-term debt to parent 3.0 3.1 5.4 5.7 Preferred stock 51.2 51.8 51.2 52.0 |
SEGMENTS OF BUSINESS (Tables)
SEGMENTS OF BUSINESS (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Schedule of information related to reportable segments | The tables below present information related to our reportable segments: Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended September 30, 2015 External revenues $ 346.5 $ 44.3 $ 390.8 $ — $ — $ 390.8 Intersegment revenues — 3.7 3.7 0.2 (3.9 ) — Depreciation and amortization 26.0 4.3 30.3 0.1 — 30.4 Operating income 84.9 3.5 88.4 0.1 — 88.5 Interest expense 10.6 2.5 13.1 0.1 — 13.2 Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended September 30, 2014 External revenues $ 327.9 $ 43.0 $ 370.9 $ — $ — $ 370.9 Intersegment revenues — 3.4 3.4 0.3 (3.7 ) — Depreciation and amortization 25.5 4.1 29.6 0.1 (0.1 ) 29.6 Operating income (loss) 80.2 (2.7 ) 77.5 0.2 — 77.7 Interest expense 11.4 2.6 14.0 0.6 — 14.6 Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Nine Months Ended September 30, 2015 External revenues $ 920.1 $ 226.0 $ 1,146.1 $ — $ — $ 1,146.1 Intersegment revenues — 8.4 8.4 0.6 (9.0 ) — Depreciation and amortization 77.5 12.7 90.2 0.3 — 90.5 Operating income 179.3 23.3 202.6 — — 202.6 Interest expense 32.4 7.7 40.1 0.2 — 40.3 Regulated (in millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Nine Months Ended September 30, 2014 External revenues $ 941.2 $ 344.7 $ 1,285.9 $ — $ — $ 1,285.9 Intersegment revenues — 10.5 10.5 1.0 (11.5 ) — Depreciation and amortization 74.7 12.2 86.9 0.5 (0.4 ) 87.0 Operating income 164.3 36.7 201.0 0.4 — 201.4 Interest expense 33.5 7.8 41.3 1.6 — 42.9 |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Related Party Transactions [Abstract] | |
Schedule of information summarizing other transactions with related parties | The table below includes information summarizing other transactions entered into with related parties: (in millions) September 30, 2015 December 31, 2014 Notes payable * Integrys $ 3.0 $ 5.4 Accounts payable Network transmission services from ATC 8.4 8.2 Liability related to income tax allocation Integrys 5.6 6.1 * WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys. At September 30, 2015 , and December 31, 2014 , the current portion of the note payable was $3.0 million and $2.5 million , respectively. |
Schedule of activity associated with related party transactions | The following table shows activity associated with related party transactions: Three Months Ended September 30 Nine Months Ended September 30 (in millions) 2015 2014 2015 2014 Electric transactions Sales to UPPCO (1) $ — $ 4.1 $ — $ 15.3 Sales to Integrys Transportation Fuels, LLC — 0.1 — 0.1 Natural gas transactions Sales to Wisconsin Electric 0.3 — 0.3 — Sales to IES (2) — 0.3 — 0.5 Purchases from IES (2) — 0.1 — 2.5 Interest expense (3) Integrys — 0.2 0.2 0.4 Transactions with equity method investees Charges from ATC for network transmission services 25.3 24.7 76.0 74.2 Charges to ATC for services and construction 2.9 2.4 7.5 7.5 Purchases of energy from WRPC 1.0 0.9 3.1 3.0 Charges to WRPC for operations 0.5 0.3 1.0 1.0 Equity earnings from WPS Investments, LLC (4) 2.5 2.6 6.8 7.7 Sales of electricity to AMP Trillium, LLC (5) — — 0.1 — (1) Integrys sold UPPCO in August 2014. (2) Integrys sold IES's retail energy business in November 2014. (3) WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys. (4) WPS Investments, LLC is a consolidated subsidiary of Integrys 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 September 30, 2015 , we had a 10.87% 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. (5) AMP Trillium, LLC is a joint venture between Integrys Transportation Fuels, LLC, a subsidiary of Integrys, and AMP Americas, LLC. This joint venture owns and operates compressed natural gas fueling stations. |
GENERAL INFORMATION (Details)
GENERAL INFORMATION (Details) - Reclassification - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2014 | Sep. 30, 2014 | Dec. 31, 2014 | |
Statements of income | |||
Reclassifications | |||
Reclassification from property and revenue taxes to other operation and maintenance | $ 2.1 | $ 6.7 | |
Reclassification from cost of sales to other operation and maintenance | $ 1.6 | 4.6 | |
Balance sheets | |||
Reclassifications | |||
Reclassification from current regulatory assets to accounts receivable | $ 1.4 | ||
Reclassification from current regulatory assets to long-term regulatory assets | 23.6 | ||
Reclassification from current regulatory liabilities to other current liabilities | 6.1 | ||
Reclassification from current regulatory liabilities to long-term regulatory liabilities | $ 15.1 | ||
Statements of cash flows | |||
Reclassifications | |||
Impact of reclassifications on total cash flows from operating, investing, and financing activities | $ 0 |
CASH AND CASH EQUIVALENTS (Deta
CASH AND CASH EQUIVALENTS (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Cash and Cash Equivalents [Abstract] | ||
Construction costs funded through accounts payable | $ 74.9 | $ 56.2 |
GOODWILL AND OTHER INTANGIBLE35
GOODWILL AND OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Goodwill and other intangible assets | ||||
Changes to the carrying amount of goodwill | $ 0 | $ 0 | ||
Goodwill impairment loss | $ 0 | |||
Intangible assets other than goodwill | ||||
Amortized intangible assets, accumulated amortization | (6.7) | (6.7) | $ (4.3) | |
Unamortized intangible assets, carrying amount | 0.4 | 0.4 | 0 | |
Total intangible assets, gross carrying amount | 16 | 16 | 15.6 | |
Total intangible assets, net carrying amount | 9.3 | 9.3 | 11.3 | |
Contractual service agreements | ||||
Intangible assets other than goodwill | ||||
Amortized intangible assets, gross carrying amount | 15.6 | 15.6 | 15.6 | |
Amortized intangible assets, accumulated amortization | (6.7) | (6.7) | (4.3) | |
Amortized intangible assets, net carrying amount | $ 8.9 | $ 8.9 | $ 11.3 | |
Remaining weighted-average amortization period | 3 years |
SHORT-TERM DEBT AND LINES OF 36
SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Short-term borrowings | ||
Short-term Debt borrowings outstanding | $ 102.1 | $ 145.1 |
Commercial paper | ||
Short-term borrowings | ||
Short-term Debt borrowings outstanding | $ 102.1 | $ 145.1 |
Short-term Debt, Weighted Average Interest Rate | 0.29% | 0.32% |
Average amount of short-term borrowings outstanding | $ 141.4 | |
Average interest rate (as a percent) | 0.29% |
SHORT-TERM DEBT AND LINES OF 37
SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) $ in Millions | Sep. 30, 2015USD ($) |
Short-term borrowings | |
Total short-term credit capacity | $ 250 |
Available capacity under existing agreements | 147.9 |
Revolving credit facility maturing on June 13, 2017 | |
Short-term borrowings | |
Total short-term credit capacity | 115 |
Revolving Credit Facility, Maturing May 8, 2019 | |
Short-term borrowings | |
Total short-term credit capacity | 135 |
Commercial paper | |
Short-term borrowings | |
Commercial paper outstanding | $ 102.1 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Sep. 30, 2015USD ($) |
Minimum future commitments for purchase obligations | |
Purchase obligations | $ 1,137.5 |
COMMITMENTS AND CONTINGENCIES39
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions | 1 Months Ended | ||||
Sep. 30, 2015USD ($) | Aug. 31, 2014 | Aug. 31, 2015 | Jun. 01, 2015USD ($) | Dec. 31, 2014USD ($) | |
Manufactured Gas Plant Remediation | |||||
Reserves for future remediation | $ 86.1 | ||||
Mercury and other hazardous air pollutants | Electric Utility | |||||
Mercury and Interstate Air Quality Rules | |||||
Percentage of mercury emission reduction required by the state of Wisconsin | 90.00% | ||||
Term of Mercury and Air Toxics Standards (MATS) extension | 1 year | ||||
Climate Change | Electric Utility | |||||
Climate Change | |||||
Percentage greenhouse gas emission reduction nationwide | 32.00% | ||||
Percentage greenhouse gas emission reduction Wisconsin | 41.00% | ||||
Weston and Pulliam plants | Electric Utility | |||||
Weston and Pulliam Clean Air Act (CAA) Issues | |||||
Regulatory asset for undepreciated book value of retired plants | $ 11.5 | ||||
Clean Water Act Cooling Water Intake Structure Rule | Electric Utility | |||||
Clean Water Act Rule | |||||
Number of compliance options available to meet standard | 7 | ||||
Manufactured gas plant remediation | Natural Gas Utility | |||||
Manufactured Gas Plant Remediation | |||||
Regulatory assets | $ 104.5 | $ 102.3 | |||
Reserves for future remediation | $ 86.3 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Pension Benefits | ||||
Components of net periodic benefit cost | ||||
Service cost | $ 2.6 | $ 2.2 | $ 8 | $ 6.5 |
Interest cost | 8 | 8.6 | 23.8 | 25.8 |
Expected return on plan assets | (16.3) | (16) | (48.7) | (48) |
Loss on plan settlement | 0 | 0 | 0.1 | 0.4 |
Amortization of prior service cost (credit) | 0.1 | 0.1 | 0.2 | 0.4 |
Amortization of net actuarial loss | 5.3 | 3.7 | 15.8 | 11.2 |
Net periodic benefit cost (credit) | (0.3) | (1.4) | (0.8) | (3.7) |
Other Postretirement Benefits | ||||
Components of net periodic benefit cost | ||||
Service cost | 2.2 | 1.9 | 6.5 | 5.8 |
Interest cost | 2.6 | 2.7 | 7.8 | 8.8 |
Expected return on plan assets | (4) | (4) | (12) | (12) |
Loss on plan settlement | 0 | 0 | 0 | 0 |
Amortization of prior service cost (credit) | (2.3) | (2.3) | (6.9) | (5.7) |
Amortization of net actuarial loss | 0.8 | 0.7 | 2.7 | 2 |
Net periodic benefit cost (credit) | $ (0.7) | $ (1) | $ (1.9) | $ (1.1) |
COMMON EQUITY - STOCK-BASED COM
COMMON EQUITY - STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Allocated Share-based Compensation Expense | $ 0 | $ 0.9 | $ 4.8 | $ 7 |
Deferred Income Tax Benefit | 0 | 0.4 | 1.9 | 2.8 |
Stock Options | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Allocated Share-based Compensation Expense | 0 | 0.1 | 0 | 0.4 |
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 | 0 | 0.1 | 1.3 | 3.9 |
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 | $ 0 | $ 0.7 | $ 3.5 | $ 2.7 |
COMMON EQUITY - STOCK-BASED C42
COMMON EQUITY - STOCK-BASED COMPENSATION UNITS ROLLFORWARD (Details) $ in Millions | 9 Months Ended |
Sep. 30, 2015USD ($)shares | |
Stock Options | |
Stock Options [Roll Forward] | |
Outstanding, at the beginning of the period (in shares) | 5,714 |
Granted (in shares) | 0 |
Exercised (in shares) | (2,752) |
Transferred (in shares) | 0 |
Stock options cancelled 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 |
Distributed (in shares) | (2,229) |
Adjustment for performance stock rights distributed or canceled (in shares) | 9,555 |
Transferred (in shares) | 0 |
Awards canceled due to WEC merger | (21,263) |
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 |
Vested and released (in shares) | (28,428) |
Transferred (in shares) | (166) |
Awards canceled 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) | 9 Months Ended |
Sep. 30, 2015 | |
Dividend Payment Restrictions | |
Maximum debt to capitalization ratio required to be maintained (as a percent) | 65.00% |
Maximum | Public Service Commission of Wisconsin (PSCW) | |
Dividend Payment Restrictions | |
Percentage of previous period's dividend as restriction on current period dividends | 103.00% |
Minimum | |
Dividend Payment Restrictions | |
Percentage of common stockholder's equity to total capitalization required to be maintained | 25.00% |
Minimum | Public Service Commission of Wisconsin (PSCW) | |
Dividend Payment Restrictions | |
Common equity ratio required to be maintained (as a percent) | 51.00% |
DERIVATIVE INSTRUMENTS - DERIVA
DERIVATIVE INSTRUMENTS - DERIVATIVE ASSETS AND LIABILITIES (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Derivative Asset [Abstract] | ||
Other current derivative assets | $ 3.6 | $ 2.3 |
Other long-term derivative assets | 0 | 0 |
Derivative Asset | 3.6 | 2.3 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 4.7 | 5.9 |
Other long-term liabilities from risk management activities | 2.5 | 1.1 |
Derivative Liability | 7.2 | 7 |
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 | 1 | 2.1 |
Other long-term liabilities from risk management activities | 0.1 | 0.1 |
FTRs | ||
Derivative Asset [Abstract] | ||
Other current derivative assets | 3.3 | 2.2 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0 | 0.3 |
Petroleum product contracts | ||
Derivative Asset [Abstract] | ||
Other current derivative assets | 0 | 0 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0.3 | 1.1 |
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 | 3.4 | 2.4 |
Other long-term liabilities from risk management activities | $ 2.4 | $ 1 |
DERIVATIVE INSTRUMENTS - NOTION
DERIVATIVE INSTRUMENTS - NOTIONAL VOLUMES (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Risk management activities | ||||
Gain (Loss) | $ 0.5 | $ 0.7 | $ (3.2) | $ 4.4 |
Natural gas contracts | ||||
Risk management activities | ||||
Volume Of Derivative Instruments | 3.7 Dth | 3.1 Dth | 14.9 Dth | 14.1 Dth |
Gain (Loss) | $ (0.7) | $ (0.6) | $ (3.2) | $ 1.2 |
Petroleum product contracts | ||||
Risk management activities | ||||
Volume Of Derivative Instruments | 1.5 gallons | 1.6 gallons | 4.7 gallons | 4.2 gallons |
Gain (Loss) | $ (0.4) | $ 0 | $ (1.4) | $ 0 |
FTRs | ||||
Risk management activities | ||||
Volume Of Derivative Instruments | 2.5 MWh | 2.2 MWh | 6.8 MWh | 6.4 MWh |
Gain (Loss) | $ 1.6 | $ 1.3 | $ 1.4 | $ 3.2 |
DERIVATIVE INSTRUMENTS - NETTIN
DERIVATIVE INSTRUMENTS - NETTING ARRANGEMENTS AND CASH COLLATERAL (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Assets | ||
Gross amount recognized on the balance sheet | $ 3.6 | $ 2.3 |
Gross amount not offset on the balance sheet | (0.3) | (0.4) |
Net Amount | 3.3 | 1.9 |
Liabilities | ||
Gross amount recognized on balance sheet | 7.2 | 7 |
Gross amount not offset on balance sheet | (1.4) | (3.6) |
Net Amount | 5.8 | 3.4 |
Cash collateral | ||
Cash Collateral | 17 | 6.6 |
Cash collateral not offset | $ 1.1 | $ 3.2 |
FAIR VALUE MEASUREMENTS - ASSET
FAIR VALUE MEASUREMENTS - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Assets | ||
Derivative Asset | $ 3.6 | $ 2.3 |
Liabilities | ||
Derivative Liability | 7.2 | 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 | 0.4 | 1.2 |
Fair value measurements on a recurring basis | Level 3 | ||
Assets | ||
Derivative Asset | 3.3 | 2.2 |
Liabilities | ||
Derivative Liability | 5.4 | 2.5 |
Fair value measurements on a recurring basis | Total | ||
Assets | ||
Derivative Asset | 3.6 | 2.3 |
Liabilities | ||
Derivative Liability | 7.2 | 7 |
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | ||
Assets | ||
Derivative Asset | 0.3 | 0 |
Liabilities | ||
Derivative Liability | 1.1 | 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 | 1.1 | 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 | 3.3 | 2.2 |
Liabilities | ||
Derivative Liability | 0.3 | |
Fair value measurements on a recurring basis | FTRs | Total | ||
Assets | ||
Derivative Asset | 3.3 | 2.2 |
Liabilities | ||
Derivative Liability | 0.3 | |
Fair value measurements on a recurring basis | Petroleum product contracts | Level 1 | ||
Liabilities | ||
Derivative Liability | 0.3 | 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 | 0.3 | 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 | 0.4 | 1.2 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Liabilities | ||
Derivative Liability | 5.4 | 2.2 |
Fair value measurements on a recurring basis | Coal contracts | Total | ||
Liabilities | ||
Derivative Liability | $ 5.8 | $ 3.4 |
FAIR VALUE MEASUREMENTS - LEVEL
FAIR VALUE MEASUREMENTS - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Balance at the beginning of period | $ (1.3) | $ 4.9 | $ (0.3) | $ (1.3) |
Net realized and unrealized gains (losses) | 0.2 | (0.4) | (11.2) | 3.5 |
Purchases | 0 | 0 | 9.8 | 4.3 |
Settlements | (1) | (1.5) | (0.4) | (3.5) |
Balance at the end of the period | $ (2.1) | $ 3 | $ (2.1) | $ 3 |
FAIR VALUE MEASUREMENTS - FINA
FAIR VALUE MEASUREMENTS - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) - USD ($) $ in Millions | Sep. 30, 2015 | Dec. 31, 2014 |
Carrying value and estimated fair value of financial instruments | ||
Long-term debt | $ 1,174.6 | $ 1,174.5 |
Long-term debt to parent | 3 | 5.4 |
Preferred stock – $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding | 51.2 | 51.2 |
Carrying Amount | ||
Carrying value and estimated fair value of financial instruments | ||
Long-term debt | 1,175.1 | 1,175.1 |
Long-term debt to parent | 3 | 5.4 |
Preferred stock – $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding | 51.2 | 51.2 |
Fair Value | ||
Carrying value and estimated fair value of financial instruments | ||
Long-term debt | 1,221.7 | 1,286.2 |
Long-term debt to parent | 3.1 | 5.7 |
Preferred stock – $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding | $ 51.8 | $ 52 |
REGULATORY ENVIRONMENT (Details
REGULATORY ENVIRONMENT (Details) $ in Millions | 1 Months Ended | |||
Oct. 31, 2015USD ($) | May. 31, 2015USD ($) | Apr. 30, 2015USD ($) | Dec. 31, 2014USD ($) | |
Public Service Commission of Wisconsin (PSCW) | 2016 rates | ||||
Regulatory environment | ||||
Requested return on equity (as a percent) | 10.20% | |||
Requested common equity component (as a percent) | 50.52% | |||
Public Service Commission of Wisconsin (PSCW) | 2016 rates | Subsequent event | ||||
Regulatory environment | ||||
Term of the potential earnings sharing mechanism | 2 years | |||
Percent of additional utility earnings shared with customers | 50.00% | |||
Basis points used to determine utility earnings shared with customers | 50 | |||
Public Service Commission of Wisconsin (PSCW) | 2016 rates | Retail electric rates | ||||
Regulatory environment | ||||
Requested annual increase (decrease) in rates | $ 94.1 | |||
Revised requested annual increase (decrease) in rates | $ 96.9 | |||
Public Service Commission of Wisconsin (PSCW) | 2016 rates | Retail electric rates | Subsequent event | ||||
Regulatory environment | ||||
Revised requested annual increase (decrease) in rates | $ 48 | |||
Authorized revenue requirement for ReACT | 275 | |||
Public Service Commission of Wisconsin (PSCW) | 2016 rates | Retail natural gas rates | ||||
Regulatory environment | ||||
Requested annual increase (decrease) in rates | 9.4 | |||
Revised requested annual increase (decrease) in rates | $ 9.1 | |||
Public Service Commission of Wisconsin (PSCW) | 2016 rates | Retail natural gas rates | Subsequent event | ||||
Regulatory environment | ||||
Revised requested annual increase (decrease) in rates | $ 4.4 | |||
Public Service Commission of Wisconsin (PSCW) | 2015 rates | ||||
Regulatory environment | ||||
Approved return on equity (as a percent) | 10.20% | |||
Approved common equity component (as a percent) | 50.28% | |||
Public Service Commission of Wisconsin (PSCW) | 2015 rates | Retail electric rates | ||||
Regulatory environment | ||||
Approved annual increase (decrease) in rates | $ 24.6 | |||
Increase in costs of fuel for electric generation | 42 | |||
Year-over-year positive (negative) change in decoupling refunded to or collected from customers in rates | 9 | |||
Customer recoveries (refunds) related to decoupling | $ (4) | |||
Percent fuel costs can vary from the rate case approved costs before deferral is required | 2.00% | |||
Public Service Commission of Wisconsin (PSCW) | 2015 rates | Retail natural gas rates | ||||
Regulatory environment | ||||
Approved annual increase (decrease) in rates | $ (15.4) | |||
Year-over-year positive (negative) change in decoupling refunded to or collected from customers in rates | (16) | |||
Customer recoveries (refunds) related to decoupling | (8) | |||
Public Service Commission of Wisconsin (PSCW) | 2014 rates | Retail electric rates | ||||
Regulatory environment | ||||
Customer recoveries (refunds) related to decoupling | (13) | |||
Public Service Commission of Wisconsin (PSCW) | 2014 rates | Retail natural gas rates | ||||
Regulatory environment | ||||
Customer recoveries (refunds) related to decoupling | $ 8 | |||
Michigan Public Service Commission (MPSC) | 2015 rates | Retail electric rates | ||||
Regulatory environment | ||||
Approved annual increase (decrease) in rates | $ 4 | |||
Approved return on equity (as a percent) | 10.20% | |||
Approved common equity component (as a percent) | 50.48% | |||
Period of rate implementation | 3 years |
SEGMENTS OF BUSINESS (Details)
SEGMENTS OF BUSINESS (Details) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)segment | Sep. 30, 2014USD ($) | |
Segment Reporting [Abstract] | ||||
Number of reportable segments | segment | 3 | |||
Segment reporting information | ||||
Revenues | $ 390.8 | $ 370.9 | $ 1,146.1 | $ 1,285.9 |
Depreciation and amortization | 30.4 | 29.6 | 90.5 | 87 |
Operating Income (Loss) | 88.5 | 77.7 | 202.6 | 201.4 |
Interest expense | 13.2 | 14.6 | 40.3 | 42.9 |
Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Reconciling Eliminations | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Depreciation and amortization | 0 | (0.1) | 0 | (0.4) |
Operating Income (Loss) | 0 | 0 | 0 | 0 |
Interest expense | 0 | 0 | 0 | 0 |
Reconciling Eliminations | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | (3.9) | (3.7) | (9) | (11.5) |
Utility Segments | ||||
Segment reporting information | ||||
Revenues | 390.8 | 370.9 | 1,146.1 | 1,285.9 |
Depreciation and amortization | 30.3 | 29.6 | 90.2 | 86.9 |
Operating Income (Loss) | 88.4 | 77.5 | 202.6 | 201 |
Interest expense | 13.1 | 14 | 40.1 | 41.3 |
Utility Segments | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 3.7 | 3.4 | 8.4 | 10.5 |
Utility Segments | Electric Utility | ||||
Segment reporting information | ||||
Revenues | 346.5 | 327.9 | 920.1 | 941.2 |
Depreciation and amortization | 26 | 25.5 | 77.5 | 74.7 |
Operating Income (Loss) | 84.9 | 80.2 | 179.3 | 164.3 |
Interest expense | 10.6 | 11.4 | 32.4 | 33.5 |
Utility Segments | Electric Utility | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Utility Segments | Natural Gas Utility | ||||
Segment reporting information | ||||
Revenues | 44.3 | 43 | 226 | 344.7 |
Depreciation and amortization | 4.3 | 4.1 | 12.7 | 12.2 |
Operating Income (Loss) | 3.5 | (2.7) | 23.3 | 36.7 |
Interest expense | 2.5 | 2.6 | 7.7 | 7.8 |
Utility Segments | Natural Gas Utility | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 3.7 | 3.4 | 8.4 | 10.5 |
Nonutility Segments | Other | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Depreciation and amortization | 0.1 | 0.1 | 0.3 | 0.5 |
Operating Income (Loss) | 0.1 | 0.2 | 0 | 0.4 |
Interest expense | 0.1 | 0.6 | 0.2 | 1.6 |
Nonutility Segments | Other | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | $ 0.2 | $ 0.3 | $ 0.6 | $ 1 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | Dec. 31, 2014 | |
Related party transactions | |||||
Notes payable to Integrys | $ 3 | $ 3 | $ 5.4 | ||
Current portion of notes payable to Integrys | 3 | 3 | 2.5 | ||
ATC | |||||
Related party transactions | |||||
Accounts payable to ATC for network transmission services | 8.4 | 8.4 | 8.2 | ||
Charges from ATC for network transmission services | 25.3 | $ 24.7 | 76 | $ 74.2 | |
Charges to equity method investee for services, construction, and/or operations | 2.9 | 2.4 | 7.5 | 7.5 | |
WRPC | |||||
Related party transactions | |||||
Purchases from related party | 1 | 0.9 | 3.1 | 3 | |
Charges to equity method investee for services, construction, and/or operations | 0.5 | 0.3 | 1 | 1 | |
WPS Investments, LLC | |||||
Related party transactions | |||||
Equity earnings from WPS Investments, LLC | $ 2.5 | 2.6 | $ 6.8 | 7.7 | |
Equity method investment, ownership interest (as a percent) | 10.87% | 10.87% | |||
AMP Trillium, LLC | Electric transactions | |||||
Related party transactions | |||||
Sales to related party | $ 0 | 0 | $ 0.1 | 0 | |
WBS | |||||
Related party transactions | |||||
Number of other significant changes from the Non-IBS affiliated interest agreement | 0 | 0 | |||
Number of state commissions that have approved the affiliated interest agreement | 2 | 2 | |||
Number of extensions available for affiliated interest agreement | 1 | 1 | |||
Integrys | |||||
Related party transactions | |||||
Liability related to income tax allocation | $ 5.6 | $ 5.6 | 6.1 | ||
Parental guarantee from Integrys | 20 | 20 | |||
Integrys | WPS Leasing | |||||
Related party transactions | |||||
Notes payable to Integrys | 3 | 3 | 5.4 | ||
Current portion of notes payable to Integrys | 3 | 3 | $ 2.5 | ||
Interest expense related to notes payable with Integrys | 0 | 0.2 | 0.2 | 0.4 | |
UPPCO | Electric transactions | |||||
Related party transactions | |||||
Sales to related party | 0 | 4.1 | 0 | 15.3 | |
Integrys Transportation Fuels, LLC | Electric transactions | |||||
Related party transactions | |||||
Sales to related party | 0 | 0.1 | 0 | 0.1 | |
Wisconsin Electric | Natural gas transactions | |||||
Related party transactions | |||||
Sales to related party | 0.3 | 0 | 0.3 | 0 | |
IES | Natural gas transactions | |||||
Related party transactions | |||||
Sales to related party | 0 | 0.3 | 0 | 0.5 | |
Purchases from related party | $ 0 | $ 0.1 | $ 0 | $ 2.5 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended | ||||
Oct. 31, 2015 | Sep. 30, 2015 | Nov. 13, 2015 | Oct. 14, 2015 | Oct. 01, 2015 | Dec. 31, 2014 | |
Subsequent Event [Line Items] | ||||||
Long-term Debt, Gross | $ 1,175.1 | $ 1,175.1 | ||||
Preferred stock, shares outstanding | 511,882 | |||||
Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 511,882 | |||||
Preferred Stock Redemption Price | $ 52.8 | |||||
Preferred stock, 5.00% Series | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 131,916 | |||||
Preferred Stock, Dividend Rate, Percentage | 5.00% | |||||
Preferred stock, 5.00% Series | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 131,916 | |||||
Preferred Stock, Dividend Rate, Percentage | 5.00% | |||||
Preferred stock, 5.04% Series | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 29,983 | |||||
Preferred Stock, Dividend Rate, Percentage | 5.04% | |||||
Preferred stock, 5.04% Series | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 29,983 | |||||
Preferred Stock, Dividend Rate, Percentage | 5.04% | |||||
Preferred stock, 5.08% Series | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 49,983 | |||||
Preferred Stock, Dividend Rate, Percentage | 5.08% | |||||
Preferred stock, 5.08% Series | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 49,983 | |||||
Preferred Stock, Dividend Rate, Percentage | 5.08% | |||||
Preferred stock, 6.76% Series | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 150,000 | |||||
Preferred Stock, Dividend Rate, Percentage | 6.76% | |||||
Preferred stock, 6.76% Series | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 150,000 | |||||
Preferred Stock, Dividend Rate, Percentage | 6.76% | |||||
Preferred stock, 6.88% Series | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 150,000 | |||||
Preferred Stock, Dividend Rate, Percentage | 6.88% | |||||
Preferred stock, 6.88% Series | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Preferred stock, shares outstanding | 150,000 | |||||
Preferred Stock, Dividend Rate, Percentage | 6.88% | |||||
Long Term debt, 7.125% Series, Year Due, 2023 | ||||||
Subsequent Event [Line Items] | ||||||
First Mortgage Bonds | $ 0.1 | $ 0.1 | ||||
Debt Instrument, Interest Rate, Stated Percentage | 7.125% | |||||
Long Term debt, 7.125% Series, Year Due, 2023 | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
First Mortgage Bonds | $ 0.1 | |||||
Debt redemption price (percent) | 100.00% | |||||
Debt Instrument, Interest Rate, Stated Percentage | 7.125% | |||||
Senior Notes [Member] | Subsequent event | ||||||
Subsequent Event [Line Items] | ||||||
Long-term Debt, Gross | $ 1,175 |