DOCUMENT AND ENTITY INFORMATION
DOCUMENT AND ENTITY INFORMATION - shares | 6 Months Ended | |
Jun. 30, 2015 | Aug. 05, 2015 | |
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 | Jun. 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 | Q2 |
CONDENSED CONSOLIDATED STATEMEN
CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Statement [Abstract] | ||||
Operating revenues | $ 330.3 | $ 359 | $ 755.3 | $ 915 |
Cost of fuel, natural gas, and purchased power | 120.4 | 147.7 | 321 | 450.8 |
Operating and maintenance expense | 125.2 | 135.4 | 239.6 | 262.5 |
Depreciation and amortization expense | 30.2 | 29 | 60.1 | 57.4 |
Property and revenue taxes | 10.3 | 10.6 | 20.5 | 20.6 |
Operating income | 44.2 | 36.3 | 114.1 | 123.7 |
Miscellaneous income | 6.3 | 6.8 | 13.1 | 14.3 |
Interest expense | 13.2 | 14.3 | 27.1 | 28.3 |
Other expense | (6.9) | (7.5) | (14) | (14) |
Income before taxes | 37.3 | 28.8 | 100.1 | 109.7 |
Provision for income taxes | 13.9 | 10.9 | 36.9 | 40.7 |
Net income | 23.4 | 17.9 | 63.2 | 69 |
Preferred stock dividend requirements | (0.8) | (0.8) | (1.6) | (1.6) |
Net income attributed to common shareholder | $ 22.6 | $ 17.1 | $ 61.6 | $ 67.4 |
CONDENSED CONSOLIDATED BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Assets | ||
Cash and cash equivalents | $ 3.7 | $ 5.4 |
Accounts receivable, net of reserves of $4.8 and $3.2, respectively | 109.7 | 130.8 |
Accrued unbilled revenues | 43.6 | 72.3 |
Receivables from related parties | 4.9 | 1.3 |
Inventories | ||
Fuel and gas | 83.2 | 85 |
Materials and supplies, at average cost | 47.4 | 39.2 |
Prepaid taxes | 51.2 | 65.7 |
Other current assets | 27.4 | 18.3 |
Current assets | 371.1 | 418 |
Property, plant, and equipment, net of accumulated depreciation of $1,541.0 and $1,542.5, respectively | 3,231 | 3,131 |
Regulatory assets | 470.2 | 457.1 |
Goodwill | 36.4 | 36.4 |
Pension and other postretirement benefit assets | 140.5 | 128.9 |
Other long-term assets | 105.7 | 107.3 |
Total assets | 4,354.9 | 4,278.7 |
Liabilities and Shareholders' Equity | ||
Short-term debt | 164.8 | 145.1 |
Current portion of long-term debt | 125 | 125 |
Current portion of long-term debt to parent | 3.2 | 2.5 |
Accounts payable | 170.8 | 161.6 |
Payables to related parties | 18.4 | 16.9 |
Other current liabilities | 63 | 75.4 |
Current liabilities | 545.2 | 526.5 |
Long-term debt to parent | 0 | 2.9 |
Long-term debt | 1,049.6 | 1,049.5 |
Deferred income taxes | 754.6 | 722.1 |
Deferred investment tax credits | 7.6 | 7.8 |
Regulatory liabilities | 310.7 | 318.4 |
Environmental remediation liabilities | 81.8 | 86.3 |
Pension and other postretirement benefit obligations | 39.3 | 37.6 |
Payables to related parties | 5.1 | 5.4 |
Other long-term liabilities | 80.6 | 71.6 |
Long-term liabilities | $ 2,329.3 | $ 2,301.6 |
Commitments and contingencies | ||
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 | 808.4 | 782 |
Retained earnings | 525.2 | 521.8 |
Total liabilities and shareholders’ equity | $ 4,354.9 | $ 4,278.7 |
CONDENSED CONSOLIDATED BALANCE4
CONDENSED CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Accounts receivable, reserves (in dollars) | $ 4.8 | $ 3.2 |
Property, plant, and equipment, accumulated depreciation (in dollars) | $ 1,541 | $ 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 | 6 Months Ended | |
Jun. 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 | 808.4 | 782 |
Retained earnings | 525.2 | 521.8 |
Total common stock equity | $ 1,429.2 | 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) | 3.2 | 5.4 |
Current portion of long-term debt to parent | (3.2) | (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 | $ 2,530 | 2,503 |
Long Term debt to parent, 8.76% Series, Year Due, 2015 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 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 | ||
Interest rate (as a percent) | 7.35% | |
Total long-term debt to parent (including current portion) | $ 3.2 | 3.4 |
Long Term debt, 7.125% Series, Year Due, 2023 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 7.125% | |
First Mortgage Bonds | $ 0.1 | 0.1 |
Long Term debt, 6.375% Series, Year Due, 2015 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 6.375% | |
Senior Notes | $ 125 | 125 |
Long Term debt, 5.65% Series, Year Due, 2017 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 5.65% | |
Senior Notes | $ 125 | 125 |
Long Term debt, 6.08% Series, Year Due, 2028 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 6.08% | |
Senior Notes | $ 50 | 50 |
Long Term debt, 5.55% Series, Year Due, 2036 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 5.55% | |
Senior Notes | $ 125 | 125 |
Long Term Debt 3.671% Series, Year Due, 2042 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 3.671% | |
Senior Notes | $ 300 | 300 |
Long Term debt 4.752% Series, Year Due 2044 | ||
Schedule of Capitalization | ||
Interest rate (as a percent) | 4.752% | |
Senior Notes | $ 450 | 450 |
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) - Jun. 30, 2015 - $ / shares | Total |
CONDENSED CONSOLIDATED STATEMENTS OF CAPITALIZATION | |
Common stock, par value (in dollars per share) | $ 4 |
Common stock, shares authorized | 32,000,000 |
Common stock, shares outstanding | 23,896,962 |
Preferred stock, par value (in dollars per share) | $ 100 |
Preferred stock, shares authorized | 1,000,000 |
CONDENSED CONSOLIDATED STATEME7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Operating Activities | ||
Net income | $ 63.2 | $ 69 |
Adjustments to reconcile net income to net cash provided by operating activities | ||
Depreciation and amortization | 60.6 | 57.9 |
Deferred income taxes and investment tax credits, net | 25.6 | 34.9 |
Pension and other postretirement contributions | (0.7) | (46.5) |
Changes in working capital | ||
Accounts receivable and accrued revenues | 43.3 | 20.7 |
Inventories | (2.5) | (10.1) |
Other current assets | 2.8 | 27.3 |
Accounts payable | (5.3) | 8.5 |
Other current liabilities | 11.5 | (13.1) |
Other, net | (13.5) | (21.7) |
Net cash provided by operating activities | 185 | 126.9 |
Investing Activities | ||
Capital expenditures | (167.4) | (124) |
Cost of removal, net of salvage | (2.8) | (1.3) |
Other, net | (1.3) | (1.6) |
Net cash used for investing activities | (171.5) | (126.9) |
Financing Activities | ||
Preferred stock dividend requirements | (1.6) | (1.6) |
Short-term debt, net | 19.7 | 34.8 |
Payments of long-term debt to parent | (2.2) | (0.4) |
Dividends to parent | (57.6) | (55.9) |
Equity contribution from parent | 30 | 40 |
Other | (3.5) | (2.3) |
Net cash (used for) provided by financing activities | (15.2) | 14.6 |
Net change in cash and cash equivalents | (1.7) | 14.6 |
Cash and cash equivalents at beginning of period | 5.4 | 5.7 |
Cash and cash equivalents at end of period | 3.7 | 20.3 |
Supplemental Cash Flow Information | ||
Cash paid for interest | 29 | 27.8 |
Cash paid (received) for income taxes | $ 1.6 | $ (9.2) |
BASIS OF PRESENTATION
BASIS OF PRESENTATION | 6 Months Ended |
Jun. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
BASIS OF PRESENTATION | Basis of Presentation 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 WPS. When we refer to the "WEC Merger," we are referring to the acquisition of our parent company, formerly known as Integrys Energy Group, by Wisconsin Energy Corporation, which was completed on June 29, 2015. We prepare our financial statements in conformity with the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with 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. Our balance sheet reflects the historical basis of our assets and liabilities as we 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, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation. Reclassifications As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below. Statements of Income: • Certain amortizations of deferrals were reclassified from operating and maintenance expense to cost of fuel, natural gas, and purchased power; depreciation and amortization expense; and miscellaneous income. • Payroll taxes of $2.0 million and $4.6 million for the three and six months ended June 30, 2014, respectively, were reclassified from taxes other than income taxes to operating and maintenance expense. The taxes other than income taxes line item was also renamed to property and revenue taxes. • Certain expenses in cost of fuel, natural gas, and purchased power were reclassified to operating revenues, operating and maintenance expense, and depreciation and amortization expense. The amounts reclassified to operating and maintenance expense were $3.4 million and $7.1 million for the three and six months ended June 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, respectively. • Current regulatory liabilities of $6.1 million and $15.1 million were recl assified to other current liabilities and long-t erm regulatory liabilities, respectively. 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 | 6 Months Ended |
Jun. 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. The merger was subject to the approvals of various government agencies, including the PSCW. Approvals were obtained from all agencies subject to several conditions. The PSCW order requires that any future electric generation projects affecting Wisconsin ratepayers submitted by WEC or its subsidiaries will first consider the extent to which existing intercompany resources can meet energy and capacity needs. We do not believe that the conditions set forth in the various regulatory orders approving the merger will have a material impact on our operations or financial results. |
CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS | 6 Months Ended |
Jun. 30, 2015 | |
Cash and Cash Equivalents [Abstract] | |
CASH AND CASH EQUIVALENTS | Cash and Cash Equivalents Short-term investments with an original maturity of three months or less are reported as cash equivalents. Construction costs funded through accounts payable totaled $45.0 million and $46.3 million for the six months ended June 30, 2015 and 2014, respectively. These costs were treated as noncash investing activities. |
GOODWILL AND OTHER INTANGIBLE A
GOODWILL AND OTHER INTANGIBLE ASSETS | 6 Months Ended |
Jun. 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 six months ended June 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. June 30, 2015 December 31, 2014 (Millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 15.6 $ (5.9 ) $ 9.7 $ 15.6 $ (4.3 ) $ 11.3 Unamortized intangible assets 0.4 — 0.4 — — — Total intangible assets $ 16.0 $ (5.9 ) $ 10.1 $ 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 June 30, 2015 , was approximately four years . |
SHORT-TERM DEBT AND LINES OF CR
SHORT-TERM DEBT AND LINES OF CREDIT | 6 Months Ended |
Jun. 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: (Millions, except percentages) June 30, 2015 December 31, 2014 Commercial paper $ 164.8 * $ 145.1 Average interest rate on commercial paper outstanding 0.30 % 0.32 % * Maturity dates ranged from July 1, 2015, through July 14, 2015. Our average amount of commercial paper borrowings based on daily outstanding balances during the six months ended June 30, 2015 , and 2014 , was $110.4 million and $18.5 million , respectively. We manage our liquidity by maintaining 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: (Millions) Maturity June 30, 2015 December 31, 2014 Revolving credit facility 06/13/2017 $ 115.0 $ 115.0 Revolving credit facility 05/08/2019 135.0 135.0 Total short-term credit capacity $ 250.0 $ 250.0 Less: Commercial paper outstanding 164.8 145.1 Available capacity under existing agreements $ 85.2 $ 104.9 |
INCOME TAXES
INCOME TAXES | 6 Months Ended |
Jun. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | Income Taxes We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items. The table below shows our effective tax rates: Three Months Ended June 30 Six months ended June 30 2015 2014 2015 2014 Effective tax rate 37.3 % 37.8 % 36.9 % 37.1 % Our effective tax rate normally differs from the federal statutory tax rate of 35% due to additional provision for state income tax obligations. No other items had a significant impact on our effective tax rates during the three and six months ended June 30, 2015 , and 2014 . We had no liabilities for unrecognized tax benefits at June 30, 2015 and December 31, 2014. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 6 Months Ended |
Jun. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | Commitments and Contingencies (a) Unconditional Purchase Obligations and Purchase Order Commitments We routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. We have obligations to distribute and sell electricity and natural gas to our customers and expect to recover costs related to these obligations in future customer rates. The following table shows our minimum future commitments related to these purchase obligations as of June 30, 2015 : Payments Due By Period (Millions) Year Contracts Extend Through Total Amounts Committed 2015 2016 2017 2018 2019 Later Years Electric utility Purchased power 2029 $ 816.3 $ 61.4 $ 78.9 $ 54.1 $ 56.8 $ 58.1 $ 507.0 Coal supply and transportation 2019 154.0 35.6 39.0 34.9 33.4 11.1 — Natural gas utility supply and transportation 2024 218.9 20.7 43.8 42.9 42.4 27.1 42.0 Total $ 1,189.2 $ 117.7 $ 161.7 $ 131.9 $ 132.6 $ 96.3 $ 549.0 (b) Environmental Matters Air Permitting Violation Claims 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 reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the U.S. District Court (Court) in March 2013, after a public comment period. The final Consent Decree includes: • the installation of emission control technology, including ReACT™, at Weston 3, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects totaling $6.0 million , and • a civil penalty of $1.2 million . As mentioned above, the Consent Decree contains a requirement to refuel, repower, and/or retire certain Weston and Pulliam units. Effective June 1, 2015, we retired Weston Unit 1 and Pulliam Units 5 and 6 and recorded a regulatory asset of $11.5 million for the undepreciated book value. We received approval from the PSCW in our 2015 rate order to defer and amortize the undepreciated book value of the retired plant associated with these units starting June 1, 2015, and concluding by 2023. We received approval from the PSCW in our 2014 and 2015 rate orders to recover prudently incurred costs as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty. We also believe that additional prudently incurred costs expected after 2015 will be recoverable from customers based on past precedent with the PSCW. The majority of the beneficial environmental projects that we proposed have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects. In May 2010, we received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that we violated the CAA at the Weston and Pulliam plants. We entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of June 30, 2015 . It is unknown whether the Sierra Club will take further action in the future. Columbia and Edgewater CAA Issues: In December 2009, the EPA issued an NOV to Wisconsin Power and Light (WP&L), the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric 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, and Madison Gas and Electric reached a settlement agreement with the EPA regarding this NOV and signed a Consent Decree. This Consent Decree was approved by the Court in June 2013, after a public comment period. The final Consent Decree includes: • the installation of emission control technology, including scrubbers at the Columbia plant, • changed operating conditions (including refueling, repowering, and/or retirement of units), • limitations on plant emissions, • beneficial environmental projects, with our portion totaling $1.3 million , and • our portion of a civil penalty and legal fees totaling $0.4 million . 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. We believe that significant costs prudently incurred as a result of complying with the terms of the Consent Decree, with the exception of the civil penalty, will be recoverable from customers. All of the beneficial environmental projects that we proposed have been approved by the EPA. Amounts have been accrued and recorded to regulatory assets, excluding costs associated with capital projects. Weston Title V Air Permit: In August 2013, the WDNR issued the Weston Title V air permit. In September 2013, we challenged various requirements in the permit by filing a contested case proceeding with the WDNR and also filed a Petition for Judicial Review in the Brown County Circuit Court. The Sierra Club and Clean Wisconsin also challenged various aspects of the permit. The WDNR granted all parties' requests for contested case proceedings. The Petitions for Judicial Review, by all parties, have been stayed pending the resolution of the contested cases. In February 2014, we also requested a modification to the construction permit for Weston 4 to remove the mercury Best Available Control Technology (BACT) emission limit requirement. This permit request was denied by the WDNR, and we challenged this issue as well. At our request, the permit was modified to resolve several of the petition issues. Those issues have now been voluntarily dismissed from the case, while 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 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 is proceeding and certain legal arguments are currently being addressed in the context of summary judgment motions. No hearing date has been set. We do not expect these matters to have a material impact on our financial statements. Air Quality Mercury and Other Hazardous Air Pollutants: In December 2011, the EPA issued the final Utility Mercury and Air Toxics Standards (MATS), 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 with the same compliance deadline that requires a 90% reduction of mercury. In June 2015, the United States Supreme Court (Supreme Court) ruled on a challenge to the MATS rule and remanded the case back to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court of Appeals), ruling that the EPA failed to appropriately consider the cost of the regulation. The MATS rule 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. At this time, it is too early to determine what effect, if any, this ruling will have on our compliance plans. We initiated certain capital projects for our wholly owned plants to achieve the required reductions for MATS or the Wisconsin Mercury Rule. These capital costs are expected to be recovered in future rates. Sulfur Dioxide: The EPA issued a 1-Hour Sulfur Dioxide (SO 2 ) National Ambient Air Quality Standard (NAAQS) that became effective in August 2010. In May 2014, the EPA issued the proposed Data Requirements Rule that would establish procedures and timelines for implementation of the standard. The proposed rule describes the EPA's plans for allowing the states to use either monitoring or modeling to make designations. As proposed, the rule affords state agencies latitude in rule implementation. States would have the option of modeling or monitoring to show attainment (subject to EPA approval for this selection). If the state chooses modeling and the sources in an area do not make reductions by 2017, and as a consequence the area is classified as nonattainment, then they would have to make emission reductions 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 EPA had agreed upon in May 2014. This consent decree has 1-Hour SO 2 implementation dates that are sooner than the proposed Data Requirements Rule. The EPA has not yet indicated how, in light of this consent decree, the Data Requirements Rule will be finalized. We believe our fleet, with the exception of the Pulliam plant, is well positioned to meet this regulation once it is finalized. The Pulliam plant is located in Brown County, which has been preliminarily determined to be in nonattainment with the standard based on monitoring data from 2012 through 2014. The WDNR has indicated that additional modeling and monitoring data will be required prior to final attainment designations being made in 2017 and 2020. We are currently working closely with the state of Wisconsin as they determine the attainment status of the areas and the effect, if any, on the Pulliam plant. Land Quality Coal Combustion Residuals (CCR) Rule: In April 2015, the EPA published the Hazardous and Solid Waste Management System; Disposal of Coal Combustion Residuals from Electric Utilities final rule in the Federal Register. The final rule regulates the disposal of coal combustion byproducts, primarily fly ash and bottom ash, as a nonhazardous waste. The rules are intended to address risks related to groundwater impacts, catastrophic failures, and air emissions. There will be additional requirements for recordkeeping, groundwater monitoring, and structural integrity, including ongoing inspections and hazard assessments. There will also be more locational restrictions to protect wetlands and seismic impact zones. The rule will affect how we operate the Weston plant's bottom ash basins and an offsite landfill. However, we have landfill capacity that meets the rule requirements, if needed, for our coal combustion product sources. 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 and expect to recover the costs in future rates. Water Quality Clean Water Act Rule: In August 2014, the EPA issued a final Clean Water Act rule under Section 316(b), which requires that the location, design, construction and capacity of cooling water intake structures reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts. The rule became effective in October 2014 and applies to the the Weston and Pulliam plants. Facility owners must select from seven compliance options available to meet the impingement mortality (IM) reduction standard. BTA determinations must also be made to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. The rule requires state permitting agencies, including the WDNR, to make BTA determinations for IM and EM over the next several years, subject to EPA oversight, when facility permits are reissued. Based on our assessment, we believe that existing technologies at Weston Units 3 and 4 satisfy the IM and EM requirements by virtue of their existing cooling towers. In addition, it is expected that the WDNR will determine that no modifications will be required at Weston Unit 2 due to low projected utilization. However, Pulliam Units 7 and 8 do not have the technologies to satisfy the IM and EM BTA requirements. During 2015-18, we plan to complete studies to address the EM BTA requirements and evaluate the available IM options for Pulliam Units 7 and 8. We also expect limited studies to support WDNR BTA determinations to be conducted at the Weston facility. We cannot yet determine what, if any, intake structure or operational modifications will be required to meet the EM BTA requirements for Pulliam Units 7 and 8. We expect to recover any future compliance costs in future rates. Manufactured Gas Plant Remediation We have identified several sites at which we, or a predecessor company, owned or operated a manufactured gas plant. These sites are at various stages of investigation, monitoring and remediation. 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 Alternative Sites Program. The future costs for detailed site investigation and future remediation 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, 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 reserves and regulatory assets related to manufactured gas plant sites: (Millions) June 30, 2015 December 31, 2014 Regulatory assets $ 100.4 $ 102.3 Reserves for future remediation 81.8 86.3 |
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS | 6 Months Ended |
Jun. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
EMPLOYEE BENEFIT PLANS | Employee Benefit Plans The following table shows the components of net periodic benefit cost (including amounts capitalized to our balance sheets) for our benefit plans: Pension Benefits Other Postretirement Benefits Three Months Ended June 30 Six Months Ended June 30 Three Months Ended June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 2015 2014 2015 2014 Service cost $ 2.7 $ 1.9 $ 5.4 $ 4.3 $ 2.1 $ 1.4 $ 4.3 $ 3.9 Interest cost 7.8 8.5 15.8 17.2 2.6 2.2 5.2 6.1 Expected return on plan assets (16.0 ) (15.8 ) (32.4 ) (32.0 ) (4.0 ) (3.4 ) (8.0 ) (8.0 ) Loss on plan settlement — 0.4 0.1 0.4 — — — — Amortization of prior service cost (credit) 0.1 0.2 0.1 0.3 (2.3 ) (2.3 ) (4.6 ) (3.4 ) Amortization of net actuarial loss 5.6 3.8 10.5 7.5 0.9 0.7 1.9 1.3 Net periodic benefit cost (credit) $ 0.2 $ (1.0 ) $ (0.5 ) $ (2.3 ) $ (0.7 ) $ (1.4 ) $ (1.2 ) $ (0.1 ) Prior service costs (credits), and net actuarial losses that have not yet been recognized as a component of net periodic benefit cost are recorded as net regulatory assets or liabilities. In March 2014, we remeasured the obligations of certain other postretirement benefit 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. |
STOCK-BASED COMPENSATION
STOCK-BASED COMPENSATION | 6 Months Ended |
Jun. 30, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
STOCK-BASED COMPENSATION | Stock-Based Compensation Our employees were granted awards under Integrys Holding’s stock-based compensation plans. Per the WEC Merger Agreement, immediately prior to completion of the merger, 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 merger. The intrinsic values of the awards canceled due to the merger were $1.5 million and $5.2 million for performance stock rights and restricted stock units, respectively. The intrinsic value of stock options 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 six months ended June 30 : Three Months Ended June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 Stock options $ — $ 0.2 $ — $ 0.3 Performance stock rights 1.1 3.6 1.3 3.8 Restricted share units 2.1 1.0 3.5 2.0 Total stock-based compensation expense $ 3.2 $ 4.8 $ 4.8 $ 6.1 Deferred income tax benefit $ 1.3 $ 1.9 $ 1.9 $ 2.4 A summary of the activity for our stock-based compensation awards for the six months ended June 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 June 30, 2015 — — — * The intrinsic value of restricted share 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. |
COMMON EQUITY
COMMON EQUITY | 6 Months Ended |
Jun. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
COMMON EQUITY | Common Equity 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 Holding. 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 Holding 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 Holding'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. 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% . As of June 30, 2015 , our total restricted retained earnings were $525.2 million . Our equity in undistributed earnings of 50% or less owned investees accounted for by the equity method was $32.7 million at June 30, 2015 . Except for the restrictions described above and subject to applicable law, we do not have any other significant dividend restrictions. Integrys Holding 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 Integrys Holding or its other subsidiaries. |
RISK MANAGEMENT ACTIVITIES
RISK MANAGEMENT ACTIVITIES | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
RISK MANAGEMENT ACTIVITIES | Risk Management Activities We use physical and financial derivative contracts to manage commodity costs. None of these derivatives are designated as hedges for accounting purposes. We use financial derivative contracts to manage the risks associated with the market price volatility of natural gas supply costs and to reduce price risk related to coal transportation costs. Financial transmission rights (FTRs) are used to manage electric transmission congestion costs in the MISO market. The tables below show our assets and liabilities from risk management activities: June 30, 2015 (Millions) Balance Sheet Presentation * Assets Liabilities Natural gas contracts Other current $ 0.6 $ 0.8 Natural gas contracts Other long-term — 0.1 FTRs Other current 4.1 — Petroleum product contracts Other current — 0.3 Coal contracts Other current — 4.1 Coal contracts Other long-term — 2.1 Other current 4.7 5.2 Other long-term — 2.2 Total $ 4.7 $ 7.4 * We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts. December 31, 2014 (Millions) Balance Sheet Presentation * Assets Liabilities Natural gas contracts Other current $ 0.1 $ 2.1 Natural gas contracts Other long-term — 0.1 FTRs Other current 2.2 0.3 Petroleum product contracts Other current — 1.1 Coal contracts Other current — 2.4 Coal contracts Other long-term — 1.0 Other current 2.3 5.9 Other long-term — 1.1 Total $ 2.3 $ 7.0 * We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts. The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities: June 30, 2015 (Millions) Gross Amount Potential Effects of Netting, Including Cash Collateral Net Amount Derivative assets subject to master netting or similar arrangements $ 4.7 $ 0.6 $ 4.1 Derivative assets not subject to master netting or similar arrangements — — Total risk management assets $ 4.7 $ 4.1 Derivative liabilities subject to master netting or similar arrangements $ 1.2 $ 1.2 $ — Derivative liabilities not subject to master netting or similar arrangements 6.2 6.2 Total risk management liabilities $ 7.4 $ 6.2 December 31, 2014 (Millions) Gross Amount Potential Effects of Netting, Including Cash Collateral Net Amount Derivative assets subject to master netting or similar arrangements $ 2.3 $ 0.4 $ 1.9 Derivative assets not subject to master netting or similar arrangements — — Total risk management assets $ 2.3 $ 1.9 Derivative liabilities subject to master netting or similar arrangements $ 3.6 $ 3.6 $ — Derivative liabilities not subject to master netting or similar arrangements 3.4 3.4 Total risk management liabilities $ 7.0 $ 3.4 Our master netting and similar arrangements have conditional rights of setoff that can be enforced under a variety of situations, including counterparty default or credit rating downgrade below investment grade. We have trade receivables and trade payables, subject to master netting or similar arrangements, that are not included in the above tables. These amounts may offset (or conditionally offset) the net amounts presented in the above tables. Financial collateral provided is restricted to the extent that it is required per the terms of the related agreements. The following table shows our cash collateral positions: (Millions) June 30, 2015 December 31, 2014 Cash collateral provided to others related to contracts under master netting or similar arrangements * $ 16.9 $ 6.6 * Cash collateral provided to others is reflected in other current assets on the balance sheets. The following table shows the unrealized gains (losses) recorded related to derivative contracts: Three Months Ended June 30 Six Months Ended June 30 (Millions) Financial Statement Presentation 2015 2014 2015 2014 Natural gas Balance Sheet — Regulatory assets $ 0.7 $ (0.3 ) $ 1.6 $ (0.1 ) Natural gas Balance Sheet — Regulatory liabilities 0.1 (0.2 ) — (0.1 ) FTRs Balance Sheet — Regulatory assets (7.2 ) (1.0 ) (7.0 ) (0.9 ) FTRs Balance Sheet — Regulatory liabilities 2.4 1.1 2.0 1.0 Petroleum Balance Sheet — Regulatory assets 0.5 — 0.9 — Coal Balance Sheet — Regulatory assets 0.6 (0.1 ) (4.0 ) 0.5 Coal Balance Sheet — Regulatory liabilities — 0.9 — 2.5 We had the following notional volumes of outstanding derivative contracts: (Millions) June 30, 2015 December 31, 2014 Commodity Purchases Other Transactions Purchases Other Transactions Natural gas (therms) 122.9 N/A 1,025.4 N/A FTRs (kilowatt-hours) N/A 8,577.9 N/A 4,287.7 Petroleum products (barrels) 0.1 N/A — N/A Coal contract (tons) 2.2 N/A 3.0 N/A |
FAIR VALUE
FAIR VALUE | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE | Fair Value A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. 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). 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. 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 methodologies that result in management's best estimate of fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our risk management assets and liabilities include NYMEX futures and options, physical commodity contracts, and financial transmission rights (FTRs) used to manage transmission congestion costs in the MISO market. When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets 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. We have established a risk oversight committee whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department. This department is separate and distinct from the supply function. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis. The following tables show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: June 30, 2015 (Millions) Level 1 Level 2 Level 3 Total Risk management assets Natural gas contracts $ 0.6 $ — $ — $ 0.6 Financial transmission rights (FTRs) — — 4.1 4.1 Total $ 0.6 $ — $ 4.1 $ 4.7 Risk management liabilities Natural gas contracts $ 0.9 $ — $ — $ 0.9 Petroleum product contracts 0.3 — — 0.3 Coal contracts — 0.8 5.4 6.2 Total $ 1.2 $ 0.8 $ 5.4 $ 7.4 December 31, 2014 (Millions) Level 1 Level 2 Level 3 Total Risk management assets Natural gas contracts $ — $ 0.1 $ — $ 0.1 FTRs — — 2.2 2.2 Total $ — $ 0.1 $ 2.2 $ 2.3 Risk management liabilities Natural gas contracts $ 2.2 $ — $ — $ 2.2 FTRs — — 0.3 0.3 Petroleum product contracts 1.1 — — 1.1 Coal contracts — 1.2 2.2 3.4 Total $ 3.3 $ 1.2 $ 2.5 $ 7.0 There were no transfers between the levels of the fair value hierarchy during the three or six months ended June 30, 2015 , and 2014. The amounts listed in the table below represent the range of unobservable inputs used in the valuations that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3 at June 30, 2015 : Fair Value (Millions) Assets Liabilities Valuation Technique Unobservable Input Average or Range FTRs $ 4.1 $ — Market-based Forward market prices ($/megawatt-month) (1) $172.71 Coal contracts — 5.4 Market-based Forward market prices ($/ton) (2) $9.86 – $13.23 (1) Represents forward market prices developed using historical cleared pricing data from MISO. (2) Represents third-party forward market pricing. Significant changes in historical settlement prices or forward coal prices would result in a directionally similar significant change in fair value. The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements: Three Months Ended June 30, 2015 Six Months Ended June 30, 2015 (Millions) FTRs Coal Contracts Total FTRs Coal Contracts Total Balance at the beginning of period $ 0.6 $ (6.2 ) $ (5.6 ) $ 1.9 $ (2.2 ) $ (0.3 ) Net realized losses included in earnings (1.2 ) — (1.2 ) (2.4 ) — (2.4 ) Net unrealized (losses) gains recorded as regulatory assets or liabilities (4.8 ) 0.3 (4.5 ) (5.0 ) (4.0 ) (9.0 ) Purchases 9.8 — 9.8 9.8 — 9.8 Settlements (0.3 ) 0.5 0.2 (0.2 ) 0.8 0.6 Balance at the end of period $ 4.1 $ (5.4 ) $ (1.3 ) $ 4.1 $ (5.4 ) $ (1.3 ) Three Months Ended June 30, 2014 Six Months Ended June 30, 2014 (Millions) FTRs Coal Contracts Total FTRs Coal Contracts Total Balance at the beginning of period $ 0.5 $ 0.3 $ 0.8 $ 1.2 $ (2.5 ) $ (1.3 ) Net realized gains included in earnings 0.1 — 0.1 0.8 — 0.8 Net unrealized gains recorded as regulatory assets or liabilities 0.1 0.8 0.9 0.1 3.0 3.1 Purchases 4.4 — 4.4 4.3 — 4.3 Settlements (1.1 ) (0.2 ) (1.3 ) (2.4 ) 0.4 (2.0 ) Balance at the end of period $ 4.0 $ 0.9 $ 4.9 $ 4.0 $ 0.9 $ 4.9 Unrealized gains and losses on FTRs and coal contracts are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have no impact on earnings. Realized gains and losses on FTRs, as well as the related transmission congestion costs, are recorded in cost of fuel, natural gas, and purchased power on the statements of income. Fair Value of Financial Instruments The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: June 30, 2015 December 31, 2014 (Millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt $ 1,174.6 $ 1,208.6 $ 1,174.5 $ 1,286.2 Long-term debt to parent 3.2 3.3 5.4 5.7 Preferred stock 51.2 53.2 51.2 52.0 The fair values of long-term debt are estimated based on the quoted market price for the same or similar issues, or on the current rates offered to us for debt of the same remaining maturity. The fair values of preferred stock are estimated based on quoted market prices, when available, or by using a perpetual dividend discount model. The fair values of long-term debt instruments and preferred stock are categorized within Level 2 of the fair value hierarchy. 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. |
MISCELLANEOUS INCOME
MISCELLANEOUS INCOME | 6 Months Ended |
Jun. 30, 2015 | |
Other Income and Expenses [Abstract] | |
MISCELLANEOUS INCOME | Miscellaneous Income Total miscellaneous income was as follows: Three Months Ended June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 Equity portion of allowance for funds used during construction $ 3.4 $ 2.7 $ 6.3 $ 6.3 Earnings from equity method investment in ATC 2.0 2.5 4.3 5.1 Key executive life insurance for retired employees — 0.7 0.9 1.4 Other 0.9 0.9 1.6 1.5 Total miscellaneous income $ 6.3 $ 6.8 $ 13.1 $ 14.3 |
REGULATORY ENVIRONMENT
REGULATORY ENVIRONMENT | 6 Months Ended |
Jun. 30, 2015 | |
Regulated Operations [Abstract] | |
REGULATORY ENVIRONMENT | Regulatory Environment Wisconsin 2016 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 10.20% return on common equity and a target common equity ratio of 50.52% in our regulatory capital structure. The proposed retail electric rate increase is primarily driven by the 2016 expected completion of the ReACT™ emission control technology at Weston 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 retail electric and natural gas revenues and employee benefit costs. 2015 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 10.20% return on common equity. The order also included a common equity ratio of 50.28% in our regulatory capital structure. The PSCW approved a change in rate design, which includes higher fixed charges to better match the related fixed costs of providing service. 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 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. See Note 7, 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. 2014 Rates In December 2013, the PSCW issued a final written order, effective January 1, 2014. It authorized a net retail electric rate decrease of $12.8 million and a net retail natural gas rate increase of $4.0 million , reflecting a 10.20% return on common equity. The order also included a common equity ratio of 50.14% in our regulatory capital structure. The retail electric rate impact consisted of a rate increase, including recovery of the difference between the 2012 fuel refund and the 2013 rate increase, entirely offset by a portion of estimated fuel cost over-collections from customers in 2013. Retail electric rates were further decreased by 2012 decoupling over-collections to be returned to customers in 2014. The retail natural gas rate impact consisted of a rate decrease, which was more than offset by the positive impact of 2012 decoupling under-collections of approximately $8.0 million to be recovered from customers in 2014. Both the retail electric and retail natural gas rate changes included the recovery of pension and other employee benefit increases that were deferred in the 2013 rate case. The PSCW also authorized the recovery of prudently incurred 2014 environmental mitigation project costs related to compliance with a Consent Decree signed in January 2013 for the Pulliam and Weston sites. See Note 7, Commitments and Contingencies, for more information . Additionally, the order required us to terminate our decoupling mechanism, beginning January 1, 2014 . Michigan 2015 Rates In April 2015, the MPSC issued a final written order, effective April 24, 2015, approving a settlement agreement between us and all parties. 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 10.20% return on common equity and a target common equity ratio of 50.48% in our regulatory capital structure. 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 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 5 and 6 and Weston 1 starting with the actual retirement date in 2015 and concluding by 2023. Lastly, we will not seek to increase retail electric base rates prior to January 1, 2018. |
SEGMENTS OF BUSINESS
SEGMENTS OF BUSINESS | 6 Months Ended |
Jun. 30, 2015 | |
Segment Reporting [Abstract] | |
SEGMENTS OF BUSINESS | Segments of Business At June 30, 2015 , we reported three segments. We manage our reportable segments separately due to their different operating and regulatory environments. Our principal business segments are our 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 (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended June 30, 2015 External revenues $ 277.5 $ 52.8 $ 330.3 $ — $ — $ 330.3 Intersegment revenues — 2.1 2.1 0.2 (2.3 ) — Depreciation and amortization expense 25.8 4.2 30.0 0.1 0.1 30.2 Miscellaneous income 3.6 0.1 3.7 2.6 — 6.3 Interest expense 10.9 2.6 13.5 (0.3 ) — 13.2 Provision for income taxes 12.9 0.1 13.0 0.9 — 13.9 Preferred stock dividend requirements (0.6 ) (0.2 ) (0.8 ) — — (0.8 ) Net income (loss) attributed to common shareholder 20.7 (0.1 ) 20.6 2.0 — 22.6 Regulated (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended June 30, 2014 External revenues $ 291.6 $ 67.4 $ 359.0 $ — $ — $ 359.0 Intersegment revenues — 2.7 2.7 0.4 (3.1 ) — Depreciation and amortization expense 24.9 4.1 29.0 0.2 (0.2 ) 29.0 Miscellaneous income 2.9 0.2 3.1 3.7 — 6.8 Interest expense 11.2 2.6 13.8 0.5 — 14.3 Provision for income taxes 9.7 0.2 9.9 1.0 — 10.9 Preferred stock dividend requirements (0.6 ) (0.2 ) (0.8 ) — — (0.8 ) Net income (loss) attributed to common shareholder 14.9 (0.1 ) 14.8 2.3 — 17.1 Regulated (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Six Months Ended June 30, 2015 External revenues $ 573.6 $ 181.7 $ 755.3 $ — $ — $ 755.3 Intersegment revenues — 4.7 4.7 0.4 (5.1 ) — Depreciation and amortization expense 51.5 8.4 59.9 0.2 — 60.1 Miscellaneous income 6.6 0.2 6.8 6.3 — 13.1 Interest expense 21.8 5.2 27.0 0.1 — 27.1 Provision for income taxes 29.3 5.7 35.0 1.9 — 36.9 Preferred stock dividend requirements (1.3 ) (0.3 ) (1.6 ) — — (1.6 ) Net income attributed to common shareholder 48.6 8.8 57.4 4.2 — 61.6 Regulated (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Six Months Ended June 30, 2014 External revenues $ 613.3 $ 301.7 $ 915.0 $ — $ — $ 915.0 Intersegment revenues — 7.1 7.1 0.7 (7.8 ) — Depreciation and amortization expense 49.2 8.1 57.3 0.4 (0.3 ) 57.4 Miscellaneous income 6.6 0.2 6.8 7.5 — 14.3 Interest expense 22.1 5.2 27.3 1.0 — 28.3 Provision for income taxes 25.2 13.5 38.7 2.0 — 40.7 Preferred stock dividend requirements (1.3 ) (0.3 ) (1.6 ) — — (1.6 ) Net income attributed to common shareholder 42.1 20.6 62.7 4.7 — 67.4 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 6 Months Ended |
Jun. 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 Integrys Holding, its subsidiaries, and other entities in which we have material interests. We provide services to ATC for its transmission facilities under several agreements approved by the PSCW. Services are billed to ATC under this agreement 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 WRPC under these agreements at our fully allocated cost. The table below includes information summarizing transactions entered into with related parties: (Millions) June 30, 2015 December 31, 2014 Notes payable * Integrys Holding $ 3.2 $ 5.4 Accounts Payable Network transmission services from ATC 8.4 8.2 Liability related to income tax allocation Integrys Holding 5.7 6.1 * WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Holding. At June 30, 2015 , and December 31, 2014 , the current portion of the note payable was $3.2 million and $2.5 million , respectively. The following table shows activity associated with related party transactions: Three Months Ended June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 Electric transactions Sales to UPPCO (1) $ — $ 5.8 $ — $ 11.2 Natural gas transactions Sales to IES (2) — 0.1 — 0.2 Purchases from IES (2) — 0.1 — 2.4 Interest expense (3) Integrys Holding 0.1 0.1 0.2 0.2 Transactions with equity method investees Charges from ATC for network transmission services 25.4 24.8 50.7 49.5 Charges to ATC for services and construction 2.2 2.7 4.6 5.1 Purchases of energy from WRPC 1.1 1.1 2.1 2.1 Charges to WRPC for operations 0.2 0.3 0.5 0.7 Equity earnings from WPS Investments, LLC (4) 2.0 2.6 4.3 5.1 Sales of electricity to AMP Trillium, LLC 0.1 — 0.1 — (1) Integrys Holding sold UPPCO in August 2014. (2) Integrys Holding sold IES's retail energy business in November 2014. (3) WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Holding. (4) WPS Investments, LLC is a consolidated subsidiary of Integrys Holding that is jointly owned by Integrys Holding and us. At June 30, 2015 , we had a 10.90% 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 Holding to WPS Investments, LLC. |
NEW ACCOUNTING PRONOUCEMENTS
NEW ACCOUNTING PRONOUCEMENTS | 6 Months Ended |
Jun. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
NEW ACCOUNTING PRONOUNCEMENTS | New Accounting Pronouncements Recently Issued Accounting Guidance Not Yet Effective 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. The standard requires retrospective application by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements. In May 2014 the FASB issued ASU 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. 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. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance was originally effective for us for the reporting period ending March 31, 2017; however, in July 2015 the FASB decided to delay the effective date for one year . Companies can still elect to adopt the standard as of the original effective date. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. We are currently evaluating the impact that the adoption of this standard will have on our financial statements. |
BASIS OF PRESENTATION (Policies
BASIS OF PRESENTATION (Policies) | 6 Months Ended |
Jun. 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 WPS. When we refer to the "WEC Merger," we are referring to the acquisition of our parent company, formerly known as Integrys Energy Group, by Wisconsin Energy Corporation, which was completed on June 29, 2015. |
Basis of accounting | We prepare our financial statements in conformity with the rules and regulations of the SEC for Quarterly Reports on Form 10-Q and in accordance with 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. Our balance sheet reflects the historical basis of our assets and liabilities as we 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, these unaudited financial statements include all adjustments necessary for a fair presentation of financial results. All adjustments are normal and recurring, unless otherwise noted. All intercompany transactions have been eliminated in consolidation. |
Reclassifications | Reclassifications As a result of the WEC Merger, we adopted the financial statement presentation policies of WEC. The previously reported items below were reclassified to conform to the current period presentation. Only material reclassifications are quantified below. Statements of Income: • Certain amortizations of deferrals were reclassified from operating and maintenance expense to cost of fuel, natural gas, and purchased power; depreciation and amortization expense; and miscellaneous income. • Payroll taxes of $2.0 million and $4.6 million for the three and six months ended June 30, 2014, respectively, were reclassified from taxes other than income taxes to operating and maintenance expense. The taxes other than income taxes line item was also renamed to property and revenue taxes. • Certain expenses in cost of fuel, natural gas, and purchased power were reclassified to operating revenues, operating and maintenance expense, and depreciation and amortization expense. The amounts reclassified to operating and maintenance expense were $3.4 million and $7.1 million for the three and six months ended June 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, respectively. • Current regulatory liabilities of $6.1 million and $15.1 million were recl assified to other current liabilities and long-t erm regulatory liabilities, respectively. Statements of Cash Flows: • Various line items within the operating, investing, and financing activities sections were reclassified; however, there was no impact on the total cash flows of these sections. |
Cash and cash equivalents | Short-term investments with an original maturity of three months or less are reported as cash equivalents. |
Income taxes | We calculate our interim period provision for income taxes based on our projected annual effective tax rate as adjusted for certain discrete items. |
Fair value measurements | A fair value measurement is required to reflect the assumptions market participants would use in pricing an asset or liability based on the best available information. 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). 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. 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 methodologies that result in management's best estimate of fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our risk management assets and liabilities include NYMEX futures and options, physical commodity contracts, and financial transmission rights (FTRs) used to manage transmission congestion costs in the MISO market. When possible, we base the valuations of our risk management assets and liabilities on quoted prices for identical assets 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. We have established a risk oversight committee whose primary responsibility includes directly or indirectly ensuring that all valuation methods are applied in accordance with predefined policies. The development and maintenance of our forward price curves has been assigned to our risk management department. This department is separate and distinct from the supply function. To validate the reasonableness of our fair value inputs, our risk management department compares changes in valuation and researches any significant differences in order to determine the underlying cause. Changes to the fair value inputs are made if necessary. We conduct a thorough review of fair value hierarchy classifications on a quarterly basis. |
New accounting pronouncements | 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. The standard requires retrospective application by restating each prior period presented in the financial statements. The guidance is effective for us for the reporting period ending March 31, 2016. We are currently evaluating the impact this guidance will have on our financial statements. In May 2014 the FASB issued ASU 2014-09, "Revenue from Contracts with Customers." This ASU supersedes the requirements in the Revenue Recognition Topic of the FASB ASC and most industry-specific guidance throughout the ASC. 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. The standard requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and cash flows from customer contracts. The guidance was originally effective for us for the reporting period ending March 31, 2017; however, in July 2015 the FASB decided to delay the effective date for one year . Companies can still elect to adopt the standard as of the original effective date. The standard requires either retrospective application by restating each prior period presented in the financial statements, or modified retrospective application by recording the cumulative effect of prior reporting periods to beginning retained earnings in the year that the standard becomes effective. We are currently evaluating the impact that the adoption of this standard will have on our financial statements. |
GOODWILL AND OTHER INTANGIBLE26
GOODWILL AND OTHER INTANGIBLE ASSETS (Tables) | 6 Months Ended |
Jun. 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. June 30, 2015 December 31, 2014 (Millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Amortized intangible assets * $ 15.6 $ (5.9 ) $ 9.7 $ 15.6 $ (4.3 ) $ 11.3 Unamortized intangible assets 0.4 — 0.4 — — — Total intangible assets $ 16.0 $ (5.9 ) $ 10.1 $ 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 June 30, 2015 , was approximately four years . |
SHORT-TERM DEBT AND LINES OF 27
SHORT-TERM DEBT AND LINES OF CREDIT (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Short-term Debt [Abstract] | |
Schedule of short-term borrowings | Our outstanding short-term borrowings were as follows: (Millions, except percentages) June 30, 2015 December 31, 2014 Commercial paper $ 164.8 * $ 145.1 Average interest rate on commercial paper outstanding 0.30 % 0.32 % * Maturity dates ranged from July 1, 2015, through July 14, 2015. |
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: (Millions) Maturity June 30, 2015 December 31, 2014 Revolving credit facility 06/13/2017 $ 115.0 $ 115.0 Revolving credit facility 05/08/2019 135.0 135.0 Total short-term credit capacity $ 250.0 $ 250.0 Less: Commercial paper outstanding 164.8 145.1 Available capacity under existing agreements $ 85.2 $ 104.9 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of effective tax rates | The table below shows our effective tax rates: Three Months Ended June 30 Six months ended June 30 2015 2014 2015 2014 Effective tax rate 37.3 % 37.8 % 36.9 % 37.1 % |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum future commitments related to purchase obligations | The following table shows our minimum future commitments related to these purchase obligations as of June 30, 2015 : Payments Due By Period (Millions) Year Contracts Extend Through Total Amounts Committed 2015 2016 2017 2018 2019 Later Years Electric utility Purchased power 2029 $ 816.3 $ 61.4 $ 78.9 $ 54.1 $ 56.8 $ 58.1 $ 507.0 Coal supply and transportation 2019 154.0 35.6 39.0 34.9 33.4 11.1 — Natural gas utility supply and transportation 2024 218.9 20.7 43.8 42.9 42.4 27.1 42.0 Total $ 1,189.2 $ 117.7 $ 161.7 $ 131.9 $ 132.6 $ 96.3 $ 549.0 |
Schedule of reserves and regulatory assets related to manufactured gas plant sites | We established the following reserves and regulatory assets related to manufactured gas plant sites: (Millions) June 30, 2015 December 31, 2014 Regulatory assets $ 100.4 $ 102.3 Reserves for future remediation 81.8 86.3 |
EMPLOYEE BENEFIT PLANS (Tables)
EMPLOYEE BENEFIT PLANS (Tables) | 6 Months Ended |
Jun. 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 benefit cost (including amounts capitalized to our balance sheets) for our benefit plans: Pension Benefits Other Postretirement Benefits Three Months Ended June 30 Six Months Ended June 30 Three Months Ended June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 2015 2014 2015 2014 Service cost $ 2.7 $ 1.9 $ 5.4 $ 4.3 $ 2.1 $ 1.4 $ 4.3 $ 3.9 Interest cost 7.8 8.5 15.8 17.2 2.6 2.2 5.2 6.1 Expected return on plan assets (16.0 ) (15.8 ) (32.4 ) (32.0 ) (4.0 ) (3.4 ) (8.0 ) (8.0 ) Loss on plan settlement — 0.4 0.1 0.4 — — — — Amortization of prior service cost (credit) 0.1 0.2 0.1 0.3 (2.3 ) (2.3 ) (4.6 ) (3.4 ) Amortization of net actuarial loss 5.6 3.8 10.5 7.5 0.9 0.7 1.9 1.3 Net periodic benefit cost (credit) $ 0.2 $ (1.0 ) $ (0.5 ) $ (2.3 ) $ (0.7 ) $ (1.4 ) $ (1.2 ) $ (0.1 ) |
STOCK-BASED COMPENSATION (Table
STOCK-BASED COMPENSATION (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [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 six months ended June 30 : Three Months Ended June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 Stock options $ — $ 0.2 $ — $ 0.3 Performance stock rights 1.1 3.6 1.3 3.8 Restricted share units 2.1 1.0 3.5 2.0 Total stock-based compensation expense $ 3.2 $ 4.8 $ 4.8 $ 6.1 Deferred income tax benefit $ 1.3 $ 1.9 $ 1.9 $ 2.4 |
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 six months ended June 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 June 30, 2015 — — — * The intrinsic value of restricted share 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. |
RISK MANAGEMENT ACTIVITIES (Tab
RISK MANAGEMENT ACTIVITIES (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Assets and liabilities from risk management activities | The tables below show our assets and liabilities from risk management activities: June 30, 2015 (Millions) Balance Sheet Presentation * Assets Liabilities Natural gas contracts Other current $ 0.6 $ 0.8 Natural gas contracts Other long-term — 0.1 FTRs Other current 4.1 — Petroleum product contracts Other current — 0.3 Coal contracts Other current — 4.1 Coal contracts Other long-term — 2.1 Other current 4.7 5.2 Other long-term — 2.2 Total $ 4.7 $ 7.4 * We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts. December 31, 2014 (Millions) Balance Sheet Presentation * Assets Liabilities Natural gas contracts Other current $ 0.1 $ 2.1 Natural gas contracts Other long-term — 0.1 FTRs Other current 2.2 0.3 Petroleum product contracts Other current — 1.1 Coal contracts Other current — 2.4 Coal contracts Other long-term — 1.0 Other current 2.3 5.9 Other long-term — 1.1 Total $ 2.3 $ 7.0 * We classify assets and liabilities from risk management activities as current or long-term based upon the maturities of the underlying contracts. |
Potential effect of netting arrangements for recognized derivative assets and liabilities | The following tables show the potential effect on our financial position of netting arrangements for recognized derivative assets and liabilities: June 30, 2015 (Millions) Gross Amount Potential Effects of Netting, Including Cash Collateral Net Amount Derivative assets subject to master netting or similar arrangements $ 4.7 $ 0.6 $ 4.1 Derivative assets not subject to master netting or similar arrangements — — Total risk management assets $ 4.7 $ 4.1 Derivative liabilities subject to master netting or similar arrangements $ 1.2 $ 1.2 $ — Derivative liabilities not subject to master netting or similar arrangements 6.2 6.2 Total risk management liabilities $ 7.4 $ 6.2 December 31, 2014 (Millions) Gross Amount Potential Effects of Netting, Including Cash Collateral Net Amount Derivative assets subject to master netting or similar arrangements $ 2.3 $ 0.4 $ 1.9 Derivative assets not subject to master netting or similar arrangements — — Total risk management assets $ 2.3 $ 1.9 Derivative liabilities subject to master netting or similar arrangements $ 3.6 $ 3.6 $ — Derivative liabilities not subject to master netting or similar arrangements 3.4 3.4 Total risk management liabilities $ 7.0 $ 3.4 |
Cash collateral positions | The following table shows our cash collateral positions: (Millions) June 30, 2015 December 31, 2014 Cash collateral provided to others related to contracts under master netting or similar arrangements * $ 16.9 $ 6.6 * Cash collateral provided to others is reflected in other current assets on the balance sheets. |
Unrealized gains (losses) related to derivatives | The following table shows the unrealized gains (losses) recorded related to derivative contracts: Three Months Ended June 30 Six Months Ended June 30 (Millions) Financial Statement Presentation 2015 2014 2015 2014 Natural gas Balance Sheet — Regulatory assets $ 0.7 $ (0.3 ) $ 1.6 $ (0.1 ) Natural gas Balance Sheet — Regulatory liabilities 0.1 (0.2 ) — (0.1 ) FTRs Balance Sheet — Regulatory assets (7.2 ) (1.0 ) (7.0 ) (0.9 ) FTRs Balance Sheet — Regulatory liabilities 2.4 1.1 2.0 1.0 Petroleum Balance Sheet — Regulatory assets 0.5 — 0.9 — Coal Balance Sheet — Regulatory assets 0.6 (0.1 ) (4.0 ) 0.5 Coal Balance Sheet — Regulatory liabilities — 0.9 — 2.5 |
Notional volumes of outstanding derivative contracts | We had the following notional volumes of outstanding derivative contracts: (Millions) June 30, 2015 December 31, 2014 Commodity Purchases Other Transactions Purchases Other Transactions Natural gas (therms) 122.9 N/A 1,025.4 N/A FTRs (kilowatt-hours) N/A 8,577.9 N/A 4,287.7 Petroleum products (barrels) 0.1 N/A — N/A Coal contract (tons) 2.2 N/A 3.0 N/A |
FAIR VALUE (Tables)
FAIR VALUE (Tables) | 6 Months Ended |
Jun. 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 show assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy: June 30, 2015 (Millions) Level 1 Level 2 Level 3 Total Risk management assets Natural gas contracts $ 0.6 $ — $ — $ 0.6 Financial transmission rights (FTRs) — — 4.1 4.1 Total $ 0.6 $ — $ 4.1 $ 4.7 Risk management liabilities Natural gas contracts $ 0.9 $ — $ — $ 0.9 Petroleum product contracts 0.3 — — 0.3 Coal contracts — 0.8 5.4 6.2 Total $ 1.2 $ 0.8 $ 5.4 $ 7.4 December 31, 2014 (Millions) Level 1 Level 2 Level 3 Total Risk management assets Natural gas contracts $ — $ 0.1 $ — $ 0.1 FTRs — — 2.2 2.2 Total $ — $ 0.1 $ 2.2 $ 2.3 Risk management liabilities Natural gas contracts $ 2.2 $ — $ — $ 2.2 FTRs — — 0.3 0.3 Petroleum product contracts 1.1 — — 1.1 Coal contracts — 1.2 2.2 3.4 Total $ 3.3 $ 1.2 $ 2.5 $ 7.0 |
Significant internally-developed unobservable inputs used in the valuation of derivatives categorized in Level 3 | The amounts listed in the table below represent the range of unobservable inputs used in the valuations that individually had a significant impact on the fair value determination and caused a derivative to be classified as Level 3 at June 30, 2015 : Fair Value (Millions) Assets Liabilities Valuation Technique Unobservable Input Average or Range FTRs $ 4.1 $ — Market-based Forward market prices ($/megawatt-month) (1) $172.71 Coal contracts — 5.4 Market-based Forward market prices ($/ton) (2) $9.86 – $13.23 (1) Represents forward market prices developed using historical cleared pricing data from MISO. (2) Represents third-party forward market pricing. |
Reconciliation of changes in the fair value of items categorized as Level 3 measurements | The following tables set forth a reconciliation of changes in the fair value of items categorized as Level 3 measurements: Three Months Ended June 30, 2015 Six Months Ended June 30, 2015 (Millions) FTRs Coal Contracts Total FTRs Coal Contracts Total Balance at the beginning of period $ 0.6 $ (6.2 ) $ (5.6 ) $ 1.9 $ (2.2 ) $ (0.3 ) Net realized losses included in earnings (1.2 ) — (1.2 ) (2.4 ) — (2.4 ) Net unrealized (losses) gains recorded as regulatory assets or liabilities (4.8 ) 0.3 (4.5 ) (5.0 ) (4.0 ) (9.0 ) Purchases 9.8 — 9.8 9.8 — 9.8 Settlements (0.3 ) 0.5 0.2 (0.2 ) 0.8 0.6 Balance at the end of period $ 4.1 $ (5.4 ) $ (1.3 ) $ 4.1 $ (5.4 ) $ (1.3 ) Three Months Ended June 30, 2014 Six Months Ended June 30, 2014 (Millions) FTRs Coal Contracts Total FTRs Coal Contracts Total Balance at the beginning of period $ 0.5 $ 0.3 $ 0.8 $ 1.2 $ (2.5 ) $ (1.3 ) Net realized gains included in earnings 0.1 — 0.1 0.8 — 0.8 Net unrealized gains recorded as regulatory assets or liabilities 0.1 0.8 0.9 0.1 3.0 3.1 Purchases 4.4 — 4.4 4.3 — 4.3 Settlements (1.1 ) (0.2 ) (1.3 ) (2.4 ) 0.4 (2.0 ) Balance at the end of period $ 4.0 $ 0.9 $ 4.9 $ 4.0 $ 0.9 $ 4.9 |
Schedule of carrying value and estimated fair value of financial instruments not recorded at fair value | The following table shows the financial instruments included on our balance sheets that are not recorded at fair value: June 30, 2015 December 31, 2014 (Millions) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt $ 1,174.6 $ 1,208.6 $ 1,174.5 $ 1,286.2 Long-term debt to parent 3.2 3.3 5.4 5.7 Preferred stock 51.2 53.2 51.2 52.0 |
MISCELLANEOUS INCOME (Tables)
MISCELLANEOUS INCOME (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Schedule of Other Nonoperating Income (Expense) | Total miscellaneous income was as follows: Three Months Ended June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 Equity portion of allowance for funds used during construction $ 3.4 $ 2.7 $ 6.3 $ 6.3 Earnings from equity method investment in ATC 2.0 2.5 4.3 5.1 Key executive life insurance for retired employees — 0.7 0.9 1.4 Other 0.9 0.9 1.6 1.5 Total miscellaneous income $ 6.3 $ 6.8 $ 13.1 $ 14.3 |
SEGMENTS OF BUSINESS (Tables)
SEGMENTS OF BUSINESS (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Segment Reporting [Abstract] | |
Schedule of information related to reportable segments | The tables below present information related to our reportable segments: Regulated (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended June 30, 2015 External revenues $ 277.5 $ 52.8 $ 330.3 $ — $ — $ 330.3 Intersegment revenues — 2.1 2.1 0.2 (2.3 ) — Depreciation and amortization expense 25.8 4.2 30.0 0.1 0.1 30.2 Miscellaneous income 3.6 0.1 3.7 2.6 — 6.3 Interest expense 10.9 2.6 13.5 (0.3 ) — 13.2 Provision for income taxes 12.9 0.1 13.0 0.9 — 13.9 Preferred stock dividend requirements (0.6 ) (0.2 ) (0.8 ) — — (0.8 ) Net income (loss) attributed to common shareholder 20.7 (0.1 ) 20.6 2.0 — 22.6 Regulated (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Three Months Ended June 30, 2014 External revenues $ 291.6 $ 67.4 $ 359.0 $ — $ — $ 359.0 Intersegment revenues — 2.7 2.7 0.4 (3.1 ) — Depreciation and amortization expense 24.9 4.1 29.0 0.2 (0.2 ) 29.0 Miscellaneous income 2.9 0.2 3.1 3.7 — 6.8 Interest expense 11.2 2.6 13.8 0.5 — 14.3 Provision for income taxes 9.7 0.2 9.9 1.0 — 10.9 Preferred stock dividend requirements (0.6 ) (0.2 ) (0.8 ) — — (0.8 ) Net income (loss) attributed to common shareholder 14.9 (0.1 ) 14.8 2.3 — 17.1 Regulated (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Six Months Ended June 30, 2015 External revenues $ 573.6 $ 181.7 $ 755.3 $ — $ — $ 755.3 Intersegment revenues — 4.7 4.7 0.4 (5.1 ) — Depreciation and amortization expense 51.5 8.4 59.9 0.2 — 60.1 Miscellaneous income 6.6 0.2 6.8 6.3 — 13.1 Interest expense 21.8 5.2 27.0 0.1 — 27.1 Provision for income taxes 29.3 5.7 35.0 1.9 — 36.9 Preferred stock dividend requirements (1.3 ) (0.3 ) (1.6 ) — — (1.6 ) Net income attributed to common shareholder 48.6 8.8 57.4 4.2 — 61.6 Regulated (Millions) Electric Utility Natural Gas Utility Total Utility Other Reconciling Eliminations WPS Consolidated Six Months Ended June 30, 2014 External revenues $ 613.3 $ 301.7 $ 915.0 $ — $ — $ 915.0 Intersegment revenues — 7.1 7.1 0.7 (7.8 ) — Depreciation and amortization expense 49.2 8.1 57.3 0.4 (0.3 ) 57.4 Miscellaneous income 6.6 0.2 6.8 7.5 — 14.3 Interest expense 22.1 5.2 27.3 1.0 — 28.3 Provision for income taxes 25.2 13.5 38.7 2.0 — 40.7 Preferred stock dividend requirements (1.3 ) (0.3 ) (1.6 ) — — (1.6 ) Net income attributed to common shareholder 42.1 20.6 62.7 4.7 — 67.4 |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Related Party Transactions [Abstract] | |
Schedule of information related to transactions entered into with related parties | The table below includes information summarizing transactions entered into with related parties: (Millions) June 30, 2015 December 31, 2014 Notes payable * Integrys Holding $ 3.2 $ 5.4 Accounts Payable Network transmission services from ATC 8.4 8.2 Liability related to income tax allocation Integrys Holding 5.7 6.1 * WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Holding. At June 30, 2015 , and December 31, 2014 , the current portion of the note payable was $3.2 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 June 30 Six Months Ended June 30 (Millions) 2015 2014 2015 2014 Electric transactions Sales to UPPCO (1) $ — $ 5.8 $ — $ 11.2 Natural gas transactions Sales to IES (2) — 0.1 — 0.2 Purchases from IES (2) — 0.1 — 2.4 Interest expense (3) Integrys Holding 0.1 0.1 0.2 0.2 Transactions with equity method investees Charges from ATC for network transmission services 25.4 24.8 50.7 49.5 Charges to ATC for services and construction 2.2 2.7 4.6 5.1 Purchases of energy from WRPC 1.1 1.1 2.1 2.1 Charges to WRPC for operations 0.2 0.3 0.5 0.7 Equity earnings from WPS Investments, LLC (4) 2.0 2.6 4.3 5.1 Sales of electricity to AMP Trillium, LLC 0.1 — 0.1 — (1) Integrys Holding sold UPPCO in August 2014. (2) Integrys Holding sold IES's retail energy business in November 2014. (3) WPS Leasing, our consolidated subsidiary, has a note payable to our parent company, Integrys Holding. (4) WPS Investments, LLC is a consolidated subsidiary of Integrys Holding that is jointly owned by Integrys Holding and us. At June 30, 2015 , we had a 10.90% 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 Holding to WPS Investments, LLC. |
BASIS OF PRESENTATION (Details)
BASIS OF PRESENTATION (Details) - Reclassification - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2014 | |
Income statement | |||
Reclassifications | |||
Reclassification from taxes other than income taxes to operating and maintenance expense | $ 2 | $ 4.6 | |
Reclassification from cost of fuel, natural gas, and purchased power to operating and maintenance expense | $ 3.4 | $ 7.1 | |
Balance sheet | |||
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 |
CASH AND CASH EQUIVALENTS (Deta
CASH AND CASH EQUIVALENTS (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Cash and Cash Equivalents [Abstract] | ||
Construction costs funded through accounts payable | $ 45 | $ 46.3 |
GOODWILL AND OTHER INTANGIBLE39
GOODWILL AND OTHER INTANGIBLE ASSETS (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2015 | Jun. 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 | (5.9) | (5.9) | $ (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 | 10.1 | 10.1 | 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 | (5.9) | (5.9) | (4.3) | |
Amortized intangible assets, net carrying amount | $ 9.7 | $ 9.7 | $ 11.3 | |
Remaining weighted-average amortization period | 4 years |
SHORT-TERM DEBT AND LINES OF 40
SHORT-TERM DEBT AND LINES OF CREDIT - SHORT-TERM BORROWINGS (Details) - USD ($) $ in Millions | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Short-term borrowings | |||
Short-term borrowings outstanding | $ 164.8 | $ 145.1 | |
Commercial paper | |||
Short-term borrowings | |||
Short-term borrowings outstanding | $ 164.8 | $ 145.1 | |
Average interest rate (as a percent) | 0.30% | 0.32% | |
Average amount of short-term borrowings outstanding | $ 110.4 | $ 18.5 |
SHORT-TERM DEBT AND LINES OF 41
SHORT-TERM DEBT AND LINES OF CREDIT - REVOLVING CREDIT FACILITIES (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Short-term borrowings | ||
Total short-term credit capacity | $ 250 | $ 250 |
Commercial paper outstanding | 164.8 | 145.1 |
Available capacity under existing agreements | 85.2 | 104.9 |
Revolving credit facility maturing on June 13, 2017 | ||
Short-term borrowings | ||
Total short-term credit capacity | 115 | 115 |
Revolving Credit Facility, Maturing May 8, 2019 | ||
Short-term borrowings | ||
Total short-term credit capacity | $ 135 | $ 135 |
INCOME TAXES (Details)
INCOME TAXES (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |||||
Effective tax rate (as a percent) | 37.30% | 37.80% | 36.90% | 37.10% | |
Federal statutory tax rate (as a percent) | 35.00% | 35.00% | 35.00% | 35.00% | |
Unrecognized Tax Benefits | $ 0 | $ 0 | $ 0 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - UNCONDITIONAL PURCHASE OBLIGATIONS (Details) $ in Millions | Jun. 30, 2015USD ($) |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | $ 1,189.2 |
2,015 | 117.7 |
2,016 | 161.7 |
2,017 | 131.9 |
2,018 | 132.6 |
2,019 | 96.3 |
Later Years | 549 |
Purchased power | Electric Utility | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 816.3 |
2,015 | 61.4 |
2,016 | 78.9 |
2,017 | 54.1 |
2,018 | 56.8 |
2,019 | 58.1 |
Later Years | 507 |
Coal supply and transportation | Electric Utility | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 154 |
2,015 | 35.6 |
2,016 | 39 |
2,017 | 34.9 |
2,018 | 33.4 |
2,019 | 11.1 |
Later Years | 0 |
Natural gas utility supply and transportation | Natural Gas Utility | |
Minimum future commitments for purchase obligations | |
Total Amounts Committed | 218.9 |
2,015 | 20.7 |
2,016 | 43.8 |
2,017 | 42.9 |
2,018 | 42.4 |
2,019 | 27.1 |
Later Years | $ 42 |
COMMITMENTS AND CONTINGENCIES44
COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL MATTERS (Details) $ in Millions | 1 Months Ended | |||||
Aug. 31, 2014 | Jun. 30, 2013USD ($) | Mar. 31, 2013USD ($) | Jun. 30, 2015USD ($) | Jun. 01, 2015USD ($) | Dec. 31, 2014USD ($) | |
Weston and Pulliam plants | Electric Utility | ||||||
Air Permitting Violation Claims | ||||||
Beneficial environmental project amount | $ 6 | |||||
Civil penalty and/or legal fees | $ 1.2 | |||||
Regulatory asset for undepreciated book value of retired plants | $ 11.5 | |||||
Columbia and Edgewater jointly-owned plants | Electric Utility | ||||||
Air Permitting Violation Claims | ||||||
Beneficial environmental project amount | $ 1.3 | |||||
Civil penalty and/or legal fees | $ 0.4 | |||||
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% | |||||
Clean Water Act 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 recorded for cash and estimated future remediation expenditures, net of insurance recoveries received | $ 100.4 | $ 102.3 | ||||
Liabilities estimated and accrued for future undiscounted investigation and cleanup costs for all sites | $ 81.8 | $ 86.3 |
EMPLOYEE BENEFIT PLANS (Details
EMPLOYEE BENEFIT PLANS (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Pension Benefits | ||||
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | ||||
Service cost | $ 2.7 | $ 1.9 | $ 5.4 | $ 4.3 |
Interest cost | 7.8 | 8.5 | 15.8 | 17.2 |
Expected return on plan assets | (16) | (15.8) | (32.4) | (32) |
Loss on plan settlement | 0 | 0.4 | 0.1 | 0.4 |
Amortization of prior service cost (credit) | 0.1 | 0.2 | 0.1 | 0.3 |
Amortization of net actuarial loss | 5.6 | 3.8 | 10.5 | 7.5 |
Net periodic benefit (credit) cost | 0.2 | (1) | (0.5) | (2.3) |
Other Postretirement Benefits | ||||
Components of net periodic benefit cost (including amounts capitalized to the balance sheets) | ||||
Service cost | 2.1 | 1.4 | 4.3 | 3.9 |
Interest cost | 2.6 | 2.2 | 5.2 | 6.1 |
Expected return on plan assets | (4) | (3.4) | (8) | (8) |
Loss on plan settlement | 0 | 0 | 0 | 0 |
Amortization of prior service cost (credit) | (2.3) | (2.3) | (4.6) | (3.4) |
Amortization of net actuarial loss | 0.9 | 0.7 | 1.9 | 1.3 |
Net periodic benefit (credit) cost | $ (0.7) | $ (1.4) | $ (1.2) | $ (0.1) |
STOCK-BASED COMPENSATION _ STOC
STOCK-BASED COMPENSATION – STOCK-BASED COMPENSATION EXPENSE (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Information related to share based awards | ||||
Total stock-based compensation expense | $ 3.2 | $ 4.8 | $ 4.8 | $ 6.1 |
Deferred income tax benefit | 1.3 | 1.9 | 1.9 | 2.4 |
Stock options | ||||
Information related to share based awards | ||||
Total stock-based compensation expense | 0 | 0.2 | 0 | 0.3 |
Performance stock rights | ||||
Information related to share based awards | ||||
Total stock-based compensation expense | 1.1 | 3.6 | 1.3 | 3.8 |
Restricted share units | ||||
Information related to share based awards | ||||
Total stock-based compensation expense | $ 2.1 | $ 1 | $ 3.5 | $ 2 |
STOCK-BASED COMPENSATION _ ST47
STOCK-BASED COMPENSATION – STOCK OPTIONS, PERFORMANCE STOCK RIGHTS, AND RESTRICTED SHARE UNIT ACTIVITY (Details) - 6 months ended Jun. 30, 2015 - USD ($) $ in Millions | Total |
Stock options | |
Stock Options | |
Outstanding, at the beginning of the period (in shares) | 5,714 |
Granted (in shares) | 0 |
Exercised (in shares) | (2,752) |
Transferred (in shares) | 0 |
Canceled due to WEC Merger (in shares) | (2,962) |
Outstanding, at the end of the periods (in shares) | 0 |
Performance stock rights | |
Performance Stock Rights and Restricted Share Unit Awards | |
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 |
Canceled due to WEC Merger (in shares) | (21,263) |
Outstanding at the end of the period (in shares) | 0 |
Additional Disclosures | |
Intrinsic value of awards canceled due to WEC merger | $ 1.5 |
Restricted share units | |
Performance Stock Rights and Restricted Share Unit Awards | |
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) |
Canceled due to WEC Merger (in shares) | (73,391) |
Outstanding at the end of the period (in shares) | 0 |
Additional Disclosures | |
Intrinsic value of awards canceled due to WEC merger | $ 5.2 |
Intrinsic value of restricted share units vested and released | $ 2.2 |
COMMON EQUITY (Details)
COMMON EQUITY (Details) - Jun. 30, 2015 - USD ($) $ in Millions | Total |
Dividend Payment Restrictions | |
Maximum debt to capitalization ratio required to be maintained (as a percent) | 65.00% |
Total restricted retained earnings | $ 525.2 |
Equity in undistributed earnings of 50% or less owned investees accounted under equity method investments | $ 32.7 |
Maximum | |
Dividend Payment Restrictions | |
Equity method investment, ownership interest (as a percent) | 50.00% |
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% |
RISK MANAGEMENT ACTIVITIES - RI
RISK MANAGEMENT ACTIVITIES - RISK MANAGEMENT ASSETS AND LIABILITIES (Details) $ in Millions | Jun. 30, 2015USD ($)derivative | Dec. 31, 2014USD ($) |
Derivative Asset [Abstract] | ||
Risk Management Asset | $ 4.7 | $ 2.3 |
Derivative Liability [Abstract] | ||
Risk Management Liability | $ 7.4 | 7 |
Designated as hedging instrument | ||
Derivative, Number of Instruments Held [Abstract] | ||
Number of derivative instruments held | derivative | 0 | |
Non-hedge derivatives | ||
Derivative Asset [Abstract] | ||
Other current assets from risk management activities | $ 4.7 | 2.3 |
Other long-term assets from risk management activities | 0 | 0 |
Risk Management Asset | 4.7 | 2.3 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 5.2 | 5.9 |
Other long-term liabilities from risk management activities | 2.2 | 1.1 |
Risk Management Liability | 7.4 | 7 |
Non-hedge derivatives | Natural gas contracts | ||
Derivative Asset [Abstract] | ||
Other current assets from risk management activities | 0.6 | 0.1 |
Other long-term assets from risk management activities | 0 | 0 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0.8 | 2.1 |
Other long-term liabilities from risk management activities | 0.1 | 0.1 |
Non-hedge derivatives | FTRs | ||
Derivative Asset [Abstract] | ||
Other current assets from risk management activities | 4.1 | 2.2 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0 | 0.3 |
Non-hedge derivatives | Petroleum product contracts | ||
Derivative Asset [Abstract] | ||
Other current assets from risk management activities | 0 | 0 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 0.3 | 1.1 |
Non-hedge derivatives | Coal contracts | ||
Derivative Asset [Abstract] | ||
Other current assets from risk management activities | 0 | 0 |
Other long-term assets from risk management activities | 0 | 0 |
Derivative Liability [Abstract] | ||
Other current liabilities from risk management activities | 4.1 | 2.4 |
Other long-term liabilities from risk management activities | $ 2.1 | $ 1 |
RISK MANAGEMENT ACTIVITIES - NE
RISK MANAGEMENT ACTIVITIES - NETTING ARRANGEMENTS AND CASH COLLATERAL (Details) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Assets | ||
Derivative assets subject to master netting or similar arrangements, gross amount | $ 4.7 | $ 2.3 |
Potential effects of netting, including cash collateral | 0.6 | 0.4 |
Derivative assets subject to master netting or similar arrangements, net amount | 4.1 | 1.9 |
Derivative assets not subject to master netting arrangement | 0 | 0 |
Risk Management Asset | 4.7 | 2.3 |
Total Risk Management Assets, Net Amount | 4.1 | 1.9 |
Liabilities | ||
Derivative liabilities subject to master netting or similar arrangements, gross amount | 1.2 | 3.6 |
Potential effects of netting, including cash collateral | 1.2 | 3.6 |
Derivative liabilities subject to master netting or similar arrangements, net amount | 0 | 0 |
Derivative liabilities not subject to master netting arrangement | 6.2 | 3.4 |
Risk Management Liability | 7.4 | 7 |
Total Risk Management Liabilities, Net Amount | 6.2 | 3.4 |
Cash collateral | ||
Cash collateral provided to others related to contracts under master netting or similar arrangements | $ 16.9 | $ 6.6 |
RISK MANAGEMENT ACTIVITIES - UN
RISK MANAGEMENT ACTIVITIES - UNREALIZED GAINS AND LOSSES (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Natural gas contracts | Balance Sheet - Regulatory assets | ||||
Risk management activities | ||||
Unrealized gain (loss) related to non-hedge derivative contracts | $ 0.7 | $ (0.3) | $ 1.6 | $ (0.1) |
Natural gas contracts | Balance Sheet - Regulatory liabilities | ||||
Risk management activities | ||||
Unrealized gain (loss) related to non-hedge derivative contracts | 0.1 | (0.2) | 0 | (0.1) |
FTRs | Balance Sheet - Regulatory assets | ||||
Risk management activities | ||||
Unrealized gain (loss) related to non-hedge derivative contracts | (7.2) | (1) | (7) | (0.9) |
FTRs | Balance Sheet - Regulatory liabilities | ||||
Risk management activities | ||||
Unrealized gain (loss) related to non-hedge derivative contracts | 2.4 | 1.1 | 2 | 1 |
Petroleum product contracts | Balance Sheet - Regulatory assets | ||||
Risk management activities | ||||
Unrealized gain (loss) related to non-hedge derivative contracts | 0.5 | 0 | 0.9 | 0 |
Coal contracts | Balance Sheet - Regulatory assets | ||||
Risk management activities | ||||
Unrealized gain (loss) related to non-hedge derivative contracts | 0.6 | (0.1) | (4) | 0.5 |
Coal contracts | Balance Sheet - Regulatory liabilities | ||||
Risk management activities | ||||
Unrealized gain (loss) related to non-hedge derivative contracts | $ 0 | $ 0.9 | $ 0 | $ 2.5 |
RISK MANAGEMENT ACTIVITIES - NO
RISK MANAGEMENT ACTIVITIES - NOTIONAL VOLUMES (Details) - Non-hedge derivatives MMBTU in Thousands, kWh in Millions, bbl in Millions, T in Millions | 6 Months Ended | 12 Months Ended |
Jun. 30, 2015kWhMMBTUTbbl | Dec. 31, 2014kWhMMBTUTbbl | |
Natural gas contracts | Purchases | ||
Risk management activities | ||
Notional volume of outstanding derivative contracts (mmbtu or kwh) | MMBTU | 12,290 | 102,540 |
FTRs | Other Transactions | ||
Risk management activities | ||
Notional volume of outstanding derivative contracts (mmbtu or kwh) | kWh | 8,577.9 | 4,287.7 |
Petroleum product contracts | Purchases | ||
Risk management activities | ||
Notional volume of outstanding derivative contracts (barrels) | 0.1 | 0 |
Coal contracts | Purchases | ||
Risk management activities | ||
Notional volume of outstanding derivative contracts (tons) | T | 2.2 | 3 |
FAIR VALUE - ASSETS AND LIABILI
FAIR VALUE - ASSETS AND LIABILITIES MEASURED ON A RECURRING BASIS (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Assets | |||||
Risk Management Asset | $ 4.7 | $ 4.7 | $ 2.3 | ||
Liabilities | |||||
Risk Management Liability | 7.4 | 7.4 | 7 | ||
Transfers Between the Levels of the Fair Value Hierarchy | |||||
Fair Value Transfers, Amount | 0 | $ 0 | 0 | $ 0 | |
Fair value measurements on a recurring basis | Level 1 | |||||
Assets | |||||
Risk Management Asset | 0.6 | 0.6 | 0 | ||
Liabilities | |||||
Risk Management Liability | 1.2 | 1.2 | 3.3 | ||
Fair value measurements on a recurring basis | Level 2 | |||||
Assets | |||||
Risk Management Asset | 0 | 0 | 0.1 | ||
Liabilities | |||||
Risk Management Liability | 0.8 | 0.8 | 1.2 | ||
Fair value measurements on a recurring basis | Level 3 | |||||
Assets | |||||
Risk Management Asset | 4.1 | 4.1 | 2.2 | ||
Liabilities | |||||
Risk Management Liability | 5.4 | 5.4 | 2.5 | ||
Fair value measurements on a recurring basis | Total | |||||
Assets | |||||
Risk Management Asset | 4.7 | 4.7 | 2.3 | ||
Liabilities | |||||
Risk Management Liability | 7.4 | 7.4 | 7 | ||
Fair value measurements on a recurring basis | Natural gas contracts | Level 1 | |||||
Assets | |||||
Risk Management Asset | 0.6 | 0.6 | 0 | ||
Liabilities | |||||
Risk Management Liability | 0.9 | 0.9 | 2.2 | ||
Fair value measurements on a recurring basis | Natural gas contracts | Level 2 | |||||
Assets | |||||
Risk Management Asset | 0 | 0 | 0.1 | ||
Liabilities | |||||
Risk Management Liability | 0 | 0 | 0 | ||
Fair value measurements on a recurring basis | Natural gas contracts | Level 3 | |||||
Assets | |||||
Risk Management Asset | 0 | 0 | 0 | ||
Liabilities | |||||
Risk Management Liability | 0 | 0 | 0 | ||
Fair value measurements on a recurring basis | Natural gas contracts | Total | |||||
Assets | |||||
Risk Management Asset | 0.6 | 0.6 | 0.1 | ||
Liabilities | |||||
Risk Management Liability | 0.9 | 0.9 | 2.2 | ||
Fair value measurements on a recurring basis | FTRs | Level 1 | |||||
Assets | |||||
Risk Management Asset | 0 | 0 | 0 | ||
Liabilities | |||||
Risk Management Liability | 0 | ||||
Fair value measurements on a recurring basis | FTRs | Level 2 | |||||
Assets | |||||
Risk Management Asset | 0 | 0 | 0 | ||
Liabilities | |||||
Risk Management Liability | 0 | ||||
Fair value measurements on a recurring basis | FTRs | Level 3 | |||||
Assets | |||||
Risk Management Asset | 4.1 | 4.1 | 2.2 | ||
Liabilities | |||||
Risk Management Liability | 0 | 0 | 0.3 | ||
Fair value measurements on a recurring basis | FTRs | Total | |||||
Assets | |||||
Risk Management Asset | 4.1 | 4.1 | 2.2 | ||
Liabilities | |||||
Risk Management Liability | 0.3 | ||||
Fair value measurements on a recurring basis | Petroleum product contracts | Level 1 | |||||
Liabilities | |||||
Risk Management Liability | 0.3 | 0.3 | 1.1 | ||
Fair value measurements on a recurring basis | Petroleum product contracts | Level 2 | |||||
Liabilities | |||||
Risk Management Liability | 0 | 0 | 0 | ||
Fair value measurements on a recurring basis | Petroleum product contracts | Level 3 | |||||
Liabilities | |||||
Risk Management Liability | 0 | 0 | 0 | ||
Fair value measurements on a recurring basis | Petroleum product contracts | Total | |||||
Liabilities | |||||
Risk Management Liability | 0.3 | 0.3 | 1.1 | ||
Fair value measurements on a recurring basis | Coal contracts | Level 1 | |||||
Liabilities | |||||
Risk Management Liability | 0 | 0 | 0 | ||
Fair value measurements on a recurring basis | Coal contracts | Level 2 | |||||
Liabilities | |||||
Risk Management Liability | 0.8 | 0.8 | 1.2 | ||
Fair value measurements on a recurring basis | Coal contracts | Level 3 | |||||
Assets | |||||
Risk Management Asset | 0 | 0 | |||
Liabilities | |||||
Risk Management Liability | 5.4 | 5.4 | 2.2 | ||
Fair value measurements on a recurring basis | Coal contracts | Total | |||||
Liabilities | |||||
Risk Management Liability | $ 6.2 | $ 6.2 | $ 3.4 |
FAIR VALUE - SIGNIFICANT UNOBSE
FAIR VALUE - SIGNIFICANT UNOBSERVABLE INPUTS (Details) $ in Millions | 6 Months Ended | |
Jun. 30, 2015USD ($)$ / T$ / MWM | Dec. 31, 2014USD ($) | |
Fair Value Inputs Assets and Liabilities Quantitative Information | ||
Risk Management Asset | $ 4.7 | $ 2.3 |
Risk Management Liability | 7.4 | 7 |
Fair value measurements on a recurring basis | Level 3 | ||
Fair Value Inputs Assets and Liabilities Quantitative Information | ||
Risk Management Asset | 4.1 | 2.2 |
Risk Management Liability | 5.4 | 2.5 |
Fair value measurements on a recurring basis | FTRs | Level 3 | ||
Fair Value Inputs Assets and Liabilities Quantitative Information | ||
Risk Management Asset | 4.1 | 2.2 |
Risk Management Liability | $ 0 | 0.3 |
Fair value measurements on a recurring basis | FTRs | Level 3 | Valuation Technique: Market-based | Average | ||
Fair Value Inputs | ||
Forward market prices (in dollars per megawatt-month or ton) | $ / MWM | 172.71 | |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | ||
Fair Value Inputs Assets and Liabilities Quantitative Information | ||
Risk Management Asset | $ 0 | |
Risk Management Liability | $ 5.4 | $ 2.2 |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | Valuation Technique: Market-based | Minimum | ||
Fair Value Inputs | ||
Forward market prices (in dollars per megawatt-month or ton) | $ / T | 9.86 | |
Fair value measurements on a recurring basis | Coal contracts | Level 3 | Valuation Technique: Market-based | Maximum | ||
Fair Value Inputs | ||
Forward market prices (in dollars per megawatt-month or ton) | $ / T | 13.23 |
FAIR VALUE - LEVEL 3 RECONCILIA
FAIR VALUE - LEVEL 3 RECONCILIATION (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements | ||||
Balance at the beginning of period | $ (5.6) | $ 0.8 | $ (0.3) | $ (1.3) |
Net realized gains (losses) included in earnings | (1.2) | 0.1 | (2.4) | 0.8 |
Net unrealized gains (losses) recorded as regulatory assets or liabilities | (4.5) | 0.9 | (9) | 3.1 |
Purchases | 9.8 | 4.4 | 9.8 | 4.3 |
Settlements | 0.2 | (1.3) | 0.6 | (2) |
Balance at the end of the period | (1.3) | 4.9 | (1.3) | 4.9 |
Impact on earnings of unrealized gains (losses) on level 3 instruments | 0 | 0 | 0 | 0 |
FTRs | ||||
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements | ||||
Balance at the beginning of period | 0.6 | 0.5 | 1.9 | 1.2 |
Net realized gains (losses) included in earnings | (1.2) | 0.1 | (2.4) | 0.8 |
Net unrealized gains (losses) recorded as regulatory assets or liabilities | (4.8) | 0.1 | (5) | 0.1 |
Purchases | 9.8 | 4.4 | 9.8 | 4.3 |
Settlements | (0.3) | (1.1) | (0.2) | (2.4) |
Balance at the end of the period | 4.1 | 4 | 4.1 | 4 |
Coal contracts | ||||
Changes in the fair value of items measured on a recurring basis and categorized as Level 3 measurements | ||||
Balance at the beginning of period | (6.2) | 0.3 | (2.2) | (2.5) |
Net realized gains (losses) included in earnings | 0 | 0 | 0 | 0 |
Net unrealized gains (losses) recorded as regulatory assets or liabilities | 0.3 | 0.8 | (4) | 3 |
Purchases | 0 | 0 | 0 | 0 |
Settlements | 0.5 | (0.2) | 0.8 | 0.4 |
Balance at the end of the period | $ (5.4) | $ 0.9 | $ (5.4) | $ 0.9 |
FAIR VALUE - FINANCIAL INSTRUME
FAIR VALUE - FINANCIAL INSTRUMENTS NOT RECORDED AT FAIR VALUE (Details) - USD ($) $ in Millions | Jun. 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 | 3.2 | 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 | 1,174.6 | 1,174.5 |
Long-term debt to parent | 3.2 | 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 | 1,208.6 | 1,286.2 |
Long-term debt to parent | 3.3 | 5.7 |
Preferred stock – $100 par value; 1,000,000 shares authorized; 511,882 shares issued and outstanding | $ 53.2 | $ 52 |
MISCELLANEOUS INCOME (Details)
MISCELLANEOUS INCOME (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Other Income and Expenses [Abstract] | ||||
Equity portion of allowance for funds used during construction | $ 3.4 | $ 2.7 | $ 6.3 | $ 6.3 |
Earnings from equity method investment in ATC | 2 | 2.5 | 4.3 | 5.1 |
Key executive life insurance for retired employees | 0 | 0.7 | 0.9 | 1.4 |
Other | 0.9 | 0.9 | 1.6 | 1.5 |
Total miscellaneous income | $ 6.3 | $ 6.8 | $ 13.1 | $ 14.3 |
REGULATORY ENVIRONMENT (Details
REGULATORY ENVIRONMENT (Details) - USD ($) $ in Millions | 1 Months Ended | |||
May. 31, 2015 | Apr. 30, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Public Service Commission of Wisconsin (PSCW) | 2016 rates | ||||
Regulatory environment | ||||
Requested return on common equity (as a percent) | 10.20% | |||
Requested percent of capital structure composed of common equity | 50.52% | |||
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 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) | 2015 rates | ||||
Regulatory environment | ||||
Approved return on common equity (as a percent) | 10.20% | |||
Approved percent of capital structure composed of common equity | 50.28% | |||
Public Service Commission of Wisconsin (PSCW) | 2015 rates | Retail electric rates | ||||
Regulatory environment | ||||
Approved annual increase (decrease) in rates | $ 24.6 | |||
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 | ||||
Regulatory environment | ||||
Approved return on common equity (as a percent) | 10.20% | |||
Approved percent of capital structure composed of common equity | 50.14% | |||
Public Service Commission of Wisconsin (PSCW) | 2014 rates | Retail electric rates | ||||
Regulatory environment | ||||
Approved annual increase (decrease) in rates | $ (12.8) | |||
Customer recoveries (refunds) related to decoupling | (13) | |||
Public Service Commission of Wisconsin (PSCW) | 2014 rates | Retail natural gas rates | ||||
Regulatory environment | ||||
Approved annual increase (decrease) in rates | 4 | |||
Customer recoveries (refunds) related to decoupling | $ 8 | $ 8 | ||
Michigan Public Service Commission (MPSC) | 2015 rates | Retail electric rates | ||||
Regulatory environment | ||||
Approved annual increase (decrease) in rates | $ 4 | |||
Approved return on common equity (as a percent) | 10.20% | |||
Approved percent of capital structure composed of common equity | 50.48% | |||
Period of rate implementation | 3 years |
SEGMENTS OF BUSINESS (Details)
SEGMENTS OF BUSINESS (Details) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015USD ($) | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($)segment | Jun. 30, 2014USD ($) | |
Segment Reporting [Abstract] | ||||
Number of reportable segments | segment | 3 | |||
Segment reporting information | ||||
Revenues | $ 330.3 | $ 359 | $ 755.3 | $ 915 |
Depreciation and amortization expense | 30.2 | 29 | 60.1 | 57.4 |
Miscellaneous income | 6.3 | 6.8 | 13.1 | 14.3 |
Interest expense | 13.2 | 14.3 | 27.1 | 28.3 |
Provision for income taxes | 13.9 | 10.9 | 36.9 | 40.7 |
Preferred stock dividend requirements | (0.8) | (0.8) | (1.6) | (1.6) |
Net income (loss) attributed to common shareholder | 22.6 | 17.1 | 61.6 | 67.4 |
Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Reconciling Eliminations | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Depreciation and amortization expense | 0.1 | (0.2) | 0 | (0.3) |
Miscellaneous income | 0 | 0 | 0 | 0 |
Interest expense | 0 | 0 | 0 | 0 |
Provision for income taxes | 0 | 0 | 0 | 0 |
Preferred stock dividend requirements | 0 | 0 | 0 | 0 |
Net income (loss) attributed to common shareholder | 0 | 0 | 0 | 0 |
Reconciling Eliminations | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | (2.3) | (3.1) | (5.1) | (7.8) |
Utility Segments | ||||
Segment reporting information | ||||
Revenues | 330.3 | 359 | 755.3 | 915 |
Depreciation and amortization expense | 30 | 29 | 59.9 | 57.3 |
Miscellaneous income | 3.7 | 3.1 | 6.8 | 6.8 |
Interest expense | 13.5 | 13.8 | 27 | 27.3 |
Provision for income taxes | 13 | 9.9 | 35 | 38.7 |
Preferred stock dividend requirements | (0.8) | (0.8) | (1.6) | (1.6) |
Net income (loss) attributed to common shareholder | 20.6 | 14.8 | 57.4 | 62.7 |
Utility Segments | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 2.1 | 2.7 | 4.7 | 7.1 |
Utility Segments | Electric Utility | ||||
Segment reporting information | ||||
Revenues | 277.5 | 291.6 | 573.6 | 613.3 |
Depreciation and amortization expense | 25.8 | 24.9 | 51.5 | 49.2 |
Miscellaneous income | 3.6 | 2.9 | 6.6 | 6.6 |
Interest expense | 10.9 | 11.2 | 21.8 | 22.1 |
Provision for income taxes | 12.9 | 9.7 | 29.3 | 25.2 |
Preferred stock dividend requirements | (0.6) | (0.6) | (1.3) | (1.3) |
Net income (loss) attributed to common shareholder | 20.7 | 14.9 | 48.6 | 42.1 |
Utility Segments | Electric Utility | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Utility Segments | Natural Gas Utility | ||||
Segment reporting information | ||||
Revenues | 52.8 | 67.4 | 181.7 | 301.7 |
Depreciation and amortization expense | 4.2 | 4.1 | 8.4 | 8.1 |
Miscellaneous income | 0.1 | 0.2 | 0.2 | 0.2 |
Interest expense | 2.6 | 2.6 | 5.2 | 5.2 |
Provision for income taxes | 0.1 | 0.2 | 5.7 | 13.5 |
Preferred stock dividend requirements | (0.2) | (0.2) | (0.3) | (0.3) |
Net income (loss) attributed to common shareholder | (0.1) | (0.1) | 8.8 | 20.6 |
Utility Segments | Natural Gas Utility | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | 2.1 | 2.7 | 4.7 | 7.1 |
Nonutility Segments | Other | ||||
Segment reporting information | ||||
Revenues | 0 | 0 | 0 | 0 |
Depreciation and amortization expense | 0.1 | 0.2 | 0.2 | 0.4 |
Miscellaneous income | 2.6 | 3.7 | 6.3 | 7.5 |
Interest expense | (0.3) | 0.5 | 0.1 | 1 |
Provision for income taxes | 0.9 | 1 | 1.9 | 2 |
Preferred stock dividend requirements | 0 | 0 | 0 | 0 |
Net income (loss) attributed to common shareholder | 2 | 2.3 | 4.2 | 4.7 |
Nonutility Segments | Other | Intersegment revenues | ||||
Segment reporting information | ||||
Revenues | $ 0.2 | $ 0.4 | $ 0.4 | $ 0.7 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Related party transactions | |||||
Notes payable to parent | $ 3.2 | $ 3.2 | $ 5.4 | ||
Current portion of notes payable to parent | 3.2 | 3.2 | 2.5 | ||
Equity earnings from WPS Investments, LLC | 2 | $ 2.5 | 4.3 | $ 5.1 | |
ATC | |||||
Related party transactions | |||||
Accounts payable to related party | 8.4 | 8.4 | 8.2 | ||
Charges from equity method investee for network transmission services | 25.4 | 24.8 | 50.7 | 49.5 | |
Charges to equity method investee for services, construction, and/or operations | 2.2 | 2.7 | 4.6 | 5.1 | |
WRPC | |||||
Related party transactions | |||||
Purchases from related party | 1.1 | 1.1 | 2.1 | 2.1 | |
Charges to equity method investee for services, construction, and/or operations | 0.2 | 0.3 | 0.5 | 0.7 | |
WPS Investments, LLC | |||||
Related party transactions | |||||
Equity earnings from WPS Investments, LLC | $ 2 | 2.6 | $ 4.3 | 5.1 | |
Equity method investment, ownership interest (as a percent) | 10.90% | 10.90% | |||
AMP Trillium, LLC | Electric transactions | |||||
Related party transactions | |||||
Sales to related party | $ 0.1 | 0 | $ 0.1 | 0 | |
Integrys Holding | |||||
Related party transactions | |||||
Liability related to income tax allocation | 5.7 | 5.7 | 6.1 | ||
Integrys Holding | WPS Leasing | |||||
Related party transactions | |||||
Notes payable to parent | 3.2 | 3.2 | 5.4 | ||
Current portion of notes payable to parent | 3.2 | 3.2 | $ 2.5 | ||
Interest expense | 0.1 | 0.1 | 0.2 | 0.2 | |
UPPCO | Electric transactions | |||||
Related party transactions | |||||
Sales to related party | 0 | 5.8 | 0 | 11.2 | |
IES | Natural gas transactions | |||||
Related party transactions | |||||
Sales to related party | 0 | 0.1 | 0 | 0.2 | |
Purchases from related party | $ 0 | $ 0.1 | $ 0 | $ 2.4 |
NEW ACCOUNTING PRONOUNCEMENTS (
NEW ACCOUNTING PRONOUNCEMENTS (Details) | 6 Months Ended |
Jun. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Deferral of effective date | 1 year |