Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2015 | Oct. 30, 2015 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | PUBLIC SERVICE CO OF COLORADO | |
Entity Central Index Key | 81,018 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | Yes | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 100 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Operating revenues | ||||
Electric | $ 884,305 | $ 881,102 | $ 2,385,297 | $ 2,376,935 |
Natural gas | 151,553 | 159,808 | 716,731 | 839,332 |
Steam and other | 8,846 | 8,201 | 30,647 | 30,091 |
Total operating revenues | 1,044,704 | 1,049,111 | 3,132,675 | 3,246,358 |
Operating expenses | ||||
Electric fuel and purchased power | 311,347 | 368,860 | 930,107 | 1,052,400 |
Cost of natural gas sold and transported | 44,953 | 60,073 | 354,825 | 487,159 |
Cost of sales — steam and other | 3,596 | 3,538 | 12,938 | 11,951 |
Operating and maintenance expenses | 186,379 | 185,510 | 560,021 | 549,935 |
Demand side management program expenses | 33,040 | 36,120 | 96,622 | 105,993 |
Depreciation and amortization | 104,228 | 95,075 | 305,517 | 283,506 |
Taxes (other than income taxes) | 45,987 | 38,862 | 146,895 | 122,467 |
Total operating expenses | 729,530 | 788,038 | 2,406,925 | 2,613,411 |
Operating income | 315,174 | 261,073 | 725,750 | 632,947 |
Other income, net | 1,222 | 1,720 | 2,674 | 3,429 |
Allowance for funds used during construction — equity | 3,958 | 12,315 | 10,155 | 36,697 |
Interest charges and financing costs | ||||
Interest charges — includes other financing costs of $1,611, $1,546, $4,671 and $4,798, respectively | 44,875 | 42,540 | 131,859 | 128,941 |
Allowance for funds used during construction — debt | (1,467) | (4,564) | (3,890) | (13,584) |
Total interest charges and financing costs | 43,408 | 37,976 | 127,969 | 115,357 |
Income before income taxes | 276,946 | 237,132 | 610,610 | 557,716 |
Income taxes | 103,865 | 82,973 | 228,063 | 195,362 |
Net income | $ 173,081 | $ 154,159 | $ 382,547 | $ 362,354 |
CONSOLIDATED STATEMENTS OF INC3
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Interest charges and financing costs | ||||
Other financing costs | $ 1,611 | $ 1,546 | $ 4,671 | $ 4,798 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Comprehensive income: | ||||
Net income | $ 173,081 | $ 154,159 | $ 382,547 | $ 362,354 |
Derivative instruments: | ||||
Net fair value decrease, net of tax of $(12), $(10), $(10), and $(9), respectively | (17) | (17) | (14) | (15) |
Reclassification of losses (gains) to net income, net of tax of $5, $(72), $(123) and $(217), respectively | 19 | (119) | (192) | (356) |
Other comprehensive income (loss) | 2 | (136) | (206) | (371) |
Comprehensive income | $ 173,083 | $ 154,023 | $ 382,341 | $ 361,983 |
CONSOLIDATED STATEMENTS OF COM5
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Derivative instruments: | ||||
Net fair value (decrease) increase, tax | $ (12) | $ (10) | $ (10) | $ (9) |
Reclassification of losses (gains) to net income, tax | $ 5 | $ (72) | $ (123) | $ (217) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Sep. 30, 2014 | |
Operating activities | ||
Net income | $ 382,547 | $ 362,354 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 309,048 | 287,141 |
Demand side management program amortization | 2,776 | 3,309 |
Deferred income taxes | 185,212 | 120,585 |
Amortization of Investment Tax Credits | (2,200) | (2,202) |
Allowance for equity funds used during construction | (10,155) | (36,697) |
Net realized and unrealized hedging and derivative transactions | 3,255 | (6,946) |
Changes in operating assets and liabilities: | ||
Accounts receivable | 61,044 | 55,070 |
Accrued unbilled revenues | 92,819 | 58,758 |
Inventories | 1,215 | (26,409) |
Prepayments and other | 75,488 | 1,001 |
Accounts payable | (78,610) | (86,984) |
Net regulatory assets and liabilities | 43,125 | 110,692 |
Other current liabilities | (36,587) | (43,323) |
Pension and other employee benefit obligations | (22,653) | (37,769) |
Change in other noncurrent assets | 2,273 | 5,353 |
Change in other noncurrent liabilities | (30,667) | (15,355) |
Net cash provided by operating activities | 977,930 | 748,578 |
Investing activities | ||
Utility capital/construction expenditures | (668,381) | (832,270) |
Allowance for equity funds used during construction | 10,155 | 36,697 |
Investments in utility money pool arrangement | (150,300) | (587,000) |
Repayments from utility money pool arrangement | 166,300 | 659,000 |
Net cash used in investing activities | (642,226) | (723,573) |
Financing activities | ||
(Repayments of) proceeds from short-term borrowings, net | (382,000) | 253,000 |
Borrowings under utility money pool arrangement | 67,000 | 303,000 |
Repayments under utility money pool arrangement | (67,000) | (292,000) |
Proceeds from issuance of long-term debt | 246,826 | 295,601 |
Repayments of Long-term Debt | 0 | (275,000) |
Proceeds from Contributions from Parent | 73,718 | 35,486 |
Dividends paid to parent | (247,174) | (355,547) |
Net cash used in financing activities | (308,630) | (35,460) |
Net change in cash and cash equivalents | 27,074 | (10,455) |
Cash and cash equivalents at beginning of period | 7,635 | 21,089 |
Cash and cash equivalents at end of period | 34,709 | 10,634 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | (145,569) | (136,045) |
Cash received (paid) for income taxes, net | 38,349 | (67,717) |
Supplemental disclosure of non-cash investing transactions: | ||
Property, plant and equipment additions in accounts payable | $ 104,965 | $ 125,498 |
CONSOLIDATED BALANCE SHEETS (UN
CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash and cash equivalents | $ 34,709 | $ 7,635 |
Accounts receivable, net | 256,571 | 322,885 |
Accounts receivable from affiliates | 11,592 | 50,842 |
Investments in utility money pool arrangement | 0 | 16,000 |
Accrued unbilled revenues | 201,230 | 294,049 |
Inventories | 237,764 | 238,979 |
Regulatory assets | 88,275 | 120,120 |
Deferred income taxes | 95,539 | 64,587 |
Derivative instruments | 1,715 | 1,731 |
Prepaid taxes | 17,354 | 90,365 |
Prepayments and other | 21,502 | 23,979 |
Total current assets | 966,251 | 1,231,172 |
Property, plant and equipment, net | 11,966,302 | 11,626,956 |
Other assets | ||
Regulatory assets | 886,072 | 903,973 |
Derivative instruments | 3,890 | 5,176 |
Other | 46,864 | 48,506 |
Total other assets | 936,826 | 957,655 |
Total assets | 13,869,379 | 13,815,783 |
Current liabilities | ||
Current portion of long-term debt | 8,921 | 8,178 |
Short-term Debt | 0 | 382,000 |
Accounts payable | 325,178 | 425,133 |
Accounts payable to affiliates | 33,430 | 46,736 |
Regulatory liabilities | 152,901 | 134,459 |
Taxes accrued | 132,251 | 159,470 |
Accrued interest | 27,043 | 48,409 |
Dividends payable to parent | 83,672 | 83,652 |
Derivative instruments | 6,437 | 5,774 |
Other | 80,419 | 72,002 |
Total current liabilities | 850,252 | 1,365,813 |
Deferred credits and other liabilities | ||
Deferred income taxes | 2,658,792 | 2,437,641 |
Deferred investment tax credits | 34,072 | 36,273 |
Regulatory liabilities | 450,014 | 464,421 |
Asset retirement obligations | 239,643 | 225,296 |
Derivative instruments | 14,317 | 18,257 |
Customer advances | 199,799 | 229,990 |
Pension and employee benefit obligations | 179,276 | 202,031 |
Other | 67,871 | 68,171 |
Total deferred credits and other liabilities | $ 3,843,784 | $ 3,682,080 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | $ 4,125,159 | $ 3,882,051 |
Common stock — 100 shares authorized at $0.01 par value; 100 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively | 0 | 0 |
Additional paid in capital | 3,551,986 | 3,522,788 |
Retained earnings | 1,522,282 | 1,386,929 |
Accumulated other comprehensive loss | (24,084) | (23,878) |
Total common stockholder’s equity | 5,050,184 | 4,885,839 |
Total liabilities and equity | $ 13,869,379 | $ 13,815,783 |
CONSOLIDATED BALANCE SHEETS (U8
CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares | Sep. 30, 2015 | Dec. 31, 2014 |
Capitalization, Long-term Debt and Equity [Abstract] | ||
Common stock, shares authorized (in shares) | 100 | 100 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares outstanding (in shares) | 100 | 100 |
Management's Opinion
Management's Opinion | 9 Months Ended |
Sep. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Management's Opinion | In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of PSCo and its subsidiaries as of Sept. 30, 2015 and Dec. 31, 2014 ; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2015 and 2014 ; and its cash flows for the nine months ended Sept. 30, 2015 and 2014 . All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2015 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014 . These notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014 , filed with the SEC on Feb. 20, 2015. Due to the seasonality of PSCo’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies The significant accounting policies set forth in Note 1 to the consolidated financial statements in the PSCo Annual Report on Form 10-K for the year ended Dec. 31, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference. |
Accounting Pronouncements
Accounting Pronouncements | 9 Months Ended |
Sep. 30, 2015 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Accounting Pronouncements | Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09) , which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. PSCo is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements. Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02) , which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. PSCo does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements. Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03) , which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, PSCo does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements. Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, PSCo does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 277,134 $ 346,007 Less allowance for bad debts (20,563 ) (23,122 ) $ 256,571 $ 322,885 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 58,532 $ 55,491 Fuel 90,135 80,963 Natural gas 89,097 102,525 $ 237,764 $ 238,979 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 11,689,760 $ 10,927,867 Natural gas plant 3,341,157 3,210,242 Common and other property 823,239 827,708 Plant to be retired (a) 42,336 71,534 Construction work in progress 486,133 828,620 Total property, plant and equipment 16,382,625 15,865,971 Less accumulated depreciation (4,416,323 ) (4,239,015 ) $ 11,966,302 $ 11,626,956 (a) PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Except to the extent noted below, Note 7 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. Federal Audit — PSCo is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. As of Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. PSCo is not expected to accrue any income tax expense related to this adjustment. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy's 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . As of Sept. 30, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013. State Audits — PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2015, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009 . There are currently no state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 1.9 $ 1.9 Unrecognized tax benefit — Temporary tax positions 13.8 10.0 Total unrecognized tax benefit $ 15.7 $ 11.9 The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (6.5 ) $ (3.9 ) It is reasonably possible that PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process and audit progress and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2015 or Dec. 31, 2014. |
Rate Matters
Rate Matters | 9 Months Ended |
Sep. 30, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
Rate Matters | Rate Matters Except to the extent noted below, the circumstances set forth in Note 11 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Note 5 to the consolidated financial statements included in PSCo’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. Pending Regulatory Proceedings — CPUC Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million , or 3.5 percent , in 2015, with subsequent step increases of $7.6 million , or 0.7 percent , in 2016 and $18.1 million , or 1.5 percent , in 2017. The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent . The rate case requests a return on equity (ROE) of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017. PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017. In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request: (Millions of Dollars) 2015 2016 Step 2017 Step Total base rate increase $ 40.5 $ 7.6 $ 18.1 Incremental PSIA rider revenues (0.1 ) 21.7 21.2 Total revenue impact $ 40.4 $ 29.3 $ 39.3 In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC) issued their 2015 base rate recommendations. The following table reflects the current positions of Staff and OCC: (Millions of Dollars) Staff OCC PSCo’s filed 2015 base rate request $ 40.5 $ 40.5 ROE (12.8 ) (13.7 ) Capital structure and cost of debt (12.8 ) (4.8 ) Cherokee pipeline adjustment (11.2 ) 4.8 Move to 2014 HTY (10.5 ) (16.4 ) Operating and maintenance (O&M) expenses (3.5 ) (2.7 ) Other, net (4.4 ) (1.9 ) Total adjustments $ (55.2 ) $ (34.7 ) Recommended (decrease) increase $ (14.7 ) $ 5.8 The Staff’s recommendation for the PSIA rider is as follows: (Millions of Dollars) 2016 2017 PSCo ’ s filed incremental PSIA request $ 21.7 $ 21.2 Transfer PSIA O&M to base rates (24.1 ) (2.0 ) ROE and capital structure (8.2 ) (3.6 ) Transfer meter replacement program from base rates to PSIA 1.7 1.7 Total $ (8.9 ) $ 17.3 In July 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows: (Millions of Dollars) 2015 2016 Step 2017 Step PSCo’s filed base rate request $ 40.5 $ 7.6 $ 18.1 Shift O&M expenses between PSIA and base rates — 7.0 6.4 Rebuttal corrections and adjustments — — (7.7 ) Total base rate request $ 40.5 $ 14.6 $ 16.8 Incremental PSIA rider revenues (0.1 ) 14.7 21.7 Total revenue impact from rebuttal $ 40.4 $ 29.3 $ 38.5 If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017. Interim rates, subject to refund, were also implemented, effective Oct. 1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s Recommended Decision in November 2015. The final CPUC decision is expected no later than January 2016. Annual Electric Earnings Test — In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers’ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of Sept. 30, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test, based on annual forecasted information. Electric, Purchased Gas and Resource Adjustment Clauses Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA) — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million . For the years 2015 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual earnings limit of $84.3 million . In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan: • A 2015 DSM electric budget of $81.6 million ; • A 2015 DSM gas budget of $13.1 million ; • A 2016 DSM electric budget of $78.7 million ; and • A 2016 DSM gas budget of $13.6 million . |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 11 and 12 to the consolidated financial statements included in PSCo’s Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Notes 5 and 6 to the consolidated financial statements included in PSCo's Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to PSCo’s financial position. Purchased Power Agreements (PPAs) Under certain PPAs, PSCo purchases power from independent power producing entities that own natural gas fueled power plants for which PSCo is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which PSCo procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity. PSCo had approximately 1,802 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2015 and Dec. 31, 2014 , with entities that have been determined to be variable interest entities. PSCo has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2032 . Environmental Contingencies Environmental Requirements Water Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 2015, the Environmental Protection Agency (EPA) issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. PSCo is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. PSCo believes that compliance costs would be recoverable through regulatory mechanisms. Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings. Air Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90 -day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which PSCo operates. Until PSCo has reviewed the final rule and has more information about state implementation plans, PSCo cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. PSCo believes that compliance costs will be recoverable through regulatory mechanisms. GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. The final rule was published in October 2015. PSCo does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule was published in October 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if PSCo were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule. Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, PSCo had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. In June 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. PSCo believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows. Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Colorado identified the PSCo facilities that will have to reduce sulfur dioxide (SO 2 ), nitrous oxide (NO x ), and particulate matter emissions under BART and set emissions limits for those facilities. In 2011, the Colorado Air Quality Control Commission approved a SIP that included the Clean Air Clean Jobs Act (CACJA) emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the SIP in 2012. Emission controls at Hayden Unit 1 and Hayden Unit 2 will be placed into service in late 2015 and late 2016, respectively, at an estimated combined cost of $82.4 million . PSCo anticipates these costs will be fully recoverable through regulatory mechanisms. In March 2013, WildEarth Guardians petitioned the U.S Court of Appeals for the 10 th Circuit to review the EPA’s decision approving the SIP. WildEarth Guardians has challenged the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that selective catalytic reduction be added to the units. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October, 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In May 2015, the EPA published its final rule which re-affirmed the approval of the State of Colorado’s BART determination for Comanche Units 1 and 2. The determination found that the controls currently installed on the units for NOx are BART. In July 2015, WildEarth Guardians filed a petition for review of the EPA's May 2015 final rule. In September 2015, in response to a motion filed by WildEarth Guardians and the EPA, the 10 th Circuit issued an order dismissing the case. In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the Clean Air Act (CAA) mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when the DOI will rule on the petition. Implementation of the National Ambient Air Quality Standard (NAAQS) for SO 2 — The EPA adopted a more stringent NAAQS for SO 2 in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where PSCo operates power plants. However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors. Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant. The Pawnee plant recently installed an SO 2 scrubber to reduce SO 2 emissions. The Colorado Department of Health and Environment made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA's final decision is expected by summer 2016. If an area is designated nonattainment, the respective states will need to evaluate all SO 2 sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months , designed to achieve the NAAQS within five years . Revisions to the NAAQS for Ozone — In October 2015, the EPA revised the NAAQS for ozone by lowering the eight -hour standard from 75 parts per billion (ppb) to 70 ppb. In Colorado, the Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard. If not in attainment, impacted areas would study the sources of nonattainment and make emission reduction plans to attain the new standards. These plans would be due to the EPA in 2020. In conjunction with CACJA, PSCo has or plans to shut down coal-fired plants in the Denver area, has installed NOx controls on Pawnee and Hayden Unit 1 and will finish installing NOx controls on Hayden Unit 2 in 2016. The final designation of nonattainment areas will be made in late 2017 based on air quality data years 2014-2016. PSCo cannot evaluate the impacts of this ruling in Colorado until the designation of nonattainment areas is made and any required state plan has been developed. PSCo believes that, should NOx control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows. Legal Contingencies PSCo is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on PSCo’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Employment, Tort and Commercial Litigation Pacific Northwest Federal Energy Regulatory Commission (FERC) Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million . In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued. The FERC issued an order on remand establishing principles for the review proceeding in October 2011. The City of Seattle filed a petition for review with the Court of Appeals for the Ninth Circuit seeking review of FERC’s order on remand. Notwithstanding its petition for review, in September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001. The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million . The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets. PSCo submitted its answering case in December 2012. In April 2013, the FERC issued an order on rehearing. The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds. In addition, the FERC rejected the imposition of any market-wide remedies. Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, the City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive. A hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made to the City of Seattle resulted in an excessive burden to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ concluded that the City of Seattle had failed to establish a causal link between any contracts and any claimed unlawful market activity, the standard required by the FERC in its remand order. The City of Seattle contested the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC. This matter is now pending a decision by the FERC. In addition, on Feb. 17, 2015, the U.S. Court of Appeals of the Ninth Circuit directed parties to the pending FERC proceeding to submit briefs addressing, among other issues, the petition for review filed by the City of Seattle seeking review of FERC’s order on remand. Parties are directed to address whether FERC’s order properly established the scope for the hearing that concluded in October 2013. Respondent-intervenors, including PSCo jointly with others, submitted briefs on May 8, 2015. Oral argument was held on June 16, 2015, and the matter is now pending before the Ninth Circuit. Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest. PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter. In making this assessment, PSCo considered two factors. First, notwithstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty. Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions. If a loss were sustained, PSCo would attempt to recover those losses from other PRPs. No accrual has been recorded for this matter. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 9 Months Ended |
Sep. 30, 2015 | |
Debt Disclosure [Abstract] | |
Borrowings and Other Financing Instruments | Borrowings and Other Financing Instruments Short-Term Borrowings Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 250 $ 250 Amount outstanding at period end — — Average amount outstanding — 4 Maximum amount outstanding 8 97 Weighted average interest rate, computed on a daily basis N/A 0.25 % Weighted average interest rate at period end N/A N/A Commercial Paper — PSCo meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for PSCo was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 700 $ 700 Amount outstanding at period end — 382 Average amount outstanding 8 167 Maximum amount outstanding 67 393 Weighted average interest rate, computed on a daily basis 0.43 % 0.31 % Weighted average interest rate at period end N/A 0.65 Letters of Credit — PSCo uses letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At Sept. 30, 2015 and Dec. 31, 2014 , there were $5 million and $6 million , respectively, of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, PSCo must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. At Sept. 30, 2015 , PSCo had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 700 $ 5 $ 695 (a) This credit facility expires in October 2019. (b) Includes outstanding commercial paper and letters of credit. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. PSCo had no direct advances on the credit facility outstanding at Sept. 30, 2015 and Dec. 31, 2014 . Long-Term Borrowings In May 2015, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025. |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value of Financial Assets and Liabilities | Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Derivative Instruments Fair Value Measurements PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes. At Sept. 30, 2015 , accumulated other comprehensive losses related to interest rate derivatives included $1.0 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — PSCo conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. Commodity Derivatives — PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, and vehicle fuel. At Sept. 30, 2015 , PSCo had various vehicle fuel contracts designated as cash flow hedges extending through December 2016. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three and nine months ended Sept. 30, 2015 and 2014 . At Sept. 30, 2015 , net losses related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur. Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. The following table details the gross notional amounts of commodity forwards and options at Sept. 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) Sept. 30, 2015 Dec. 31, 2014 Million British thermal units of natural gas 9,621 735 Gallons of vehicle fuel 79 127 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2015 and 2014 , on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ 9 (a) $ — $ — Vehicle fuel and other commodity (29 ) — 15 (b) — — Total $ (29 ) $ — $ 24 $ — $ — Other derivative instruments Natural gas commodity $ — $ (2,140 ) $ — $ — $ (405 ) (d) Total $ — $ (2,140 ) $ — $ — $ (405 ) Nine Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Gains Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (353 ) (a) $ — $ — Vehicle fuel and other commodity (24 ) — 38 (b) — — Total $ (24 ) $ — $ (315 ) $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 191 (c) Natural gas commodity — (2,496 ) — 5,460 (d) (5,925 ) (d) Total $ — $ (2,496 ) $ — $ 5,460 $ (5,734 ) Three Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (184 ) (a) $ — $ — Vehicle fuel and other commodity (27 ) — (7 ) (b) — — Total $ (27 ) $ — $ (191 ) $ — $ — Other derivative instruments Natural gas commodity $ — $ (2,126 ) $ — $ — $ (209 ) (c) Total $ — $ (2,126 ) $ — $ — $ (209 ) Nine Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (546 ) (a) $ — $ — Vehicle fuel and other commodity (24 ) — (27 ) (b) — — Total $ (24 ) $ — $ (573 ) $ — $ — Other derivative instruments Natural gas commodity $ — $ 5,784 $ — $ (8,579 ) (d) $ (4,589 ) (d) Total $ — $ 5,784 $ — $ (8,579 ) $ (4,589 ) (a) Recorded to interest charges. (b) Recorded to O&M expenses. (c) Amounts are recorded to electric fuel and purchased power. (d) Amounts for the three and nine months ended Sept. 30, 2015 included $0.4 million and $0.5 million , respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months ended Sept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 2015 and 2014 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. PSCo had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2015 and 2014 . Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Consideration of Credit Risk and Concentrations — PSCo continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. PSCo employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. PSCo’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities. At Sept. 30, 2015 , four of PSCo’s 10 most significant counterparties, comprising $5.6 million or 10 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Five of the 10 most significant counterparties, comprising $23.9 million or 42 percent of this credit exposure, were not rated by these agencies, but based on PSCo’s internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $5.7 million or 10 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities. Credit Related Contingent Features — Contract provisions for derivative instruments that PSCo enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale contracts and therefore not reflected on the balance sheet, may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unable to maintain its credit ratings. At Sept. 30, 2015 and Dec. 31, 2014 , there were no derivative instruments with contract provisions that required the posting of collateral or settlement of the contracts. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. PSCo had no collateral posted related to adequate assurance clauses in derivative contracts as of Sept. 30, 2015 and Dec. 31, 2014 . Recurring Fair Value Measurements — The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2015 : Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Natural gas commodity $ — $ 1,668 $ — $ 1,668 $ (1,668 ) $ — Total current derivative assets $ — $ 1,668 $ — $ 1,668 $ (1,668 ) — PPAs (a) 1,715 Current derivative instruments $ 1,715 Noncurrent derivative assets PPAs (a) $ 3,890 Noncurrent derivative instruments $ 3,890 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 70 $ — $ 70 $ — $ 70 Other derivative instruments: Natural gas commodity — 2,000 — 2,000 (1,668 ) 332 Other commodity — 844 — 844 — 844 Total current derivative liabilities $ — $ 2,914 $ — $ 2,914 $ (1,668 ) 1,246 PPAs (a) 5,191 Current derivative instruments $ 6,437 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 16 $ — $ 16 $ — $ 16 Other derivative instruments: Other commodity — 18 — 18 — 18 Total noncurrent derivative liabilities $ — $ 34 $ — $ 34 $ — 34 PPAs (a) 14,283 Noncurrent derivative instruments $ 14,317 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015 . At Sept. 30, 2015 , derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014 : Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Natural gas commodity $ — $ 33 $ — $ 33 $ (18 ) $ 15 Total current derivative assets $ — $ 33 $ — $ 33 $ (18 ) 15 PPAs (a) 1,716 Current derivative instruments $ 1,731 Noncurrent derivative assets PPAs (a) $ 5,176 Noncurrent derivative instruments $ 5,176 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 53 $ — $ 53 $ — $ 53 Other derivative instruments: Natural gas commodity — 548 — 548 (18 ) 530 Total current derivative liabilities $ — $ 601 $ — $ 601 $ (18 ) 583 PPAs (a) 5,191 Current derivative instruments $ 5,774 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 46 $ — $ 46 $ — $ 46 Other derivative instruments: Natural gas commodity — 35 — 35 — 35 Total noncurrent derivative liabilities $ — $ 81 $ — $ 81 $ — 81 PPAs (a) 18,176 Noncurrent derivative instruments $ 18,257 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014 . At Dec. 31, 2014 , derivative assets and liabilities included no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. There were no changes in Level 3 recurring fair value measurements for the three and nine months ended Sept. 30, 2015 and 2014 . PSCo recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2015 and 2014 . Fair Value of Long-Term Debt As of Sept. 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 4,134,080 $ 4,429,648 $ 3,890,229 $ 4,328,968 The fair value of PSCo’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Sept. 30, 2015 and Dec. 31, 2014 , and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2. |
Other Income, Net
Other Income, Net | 9 Months Ended |
Sep. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other Income, Net Other income, net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 162 $ 729 $ 537 $ 1,375 Other nonoperating income 607 573 1,904 2,448 Insurance policy income (expense) 453 418 233 (394 ) Other income, net $ 1,222 $ 1,720 $ 2,674 $ 3,429 |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by PSCo’s chief operating decision maker. PSCo evaluates performance based on profit or loss generated from the product or service provided. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment. PSCo has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • PSCo’s regulated electric utility segment generates, transmits and distributes electricity primarily in portions of Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s commodity trading operations. • PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Colorado. • Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities. Asset and capital expenditure information is not provided for PSCo’s reportable segments because as an integrated electric and natural gas utility, PSCo operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2015 Operating revenues (a)(b) $ 884,305 $ 151,553 $ 8,846 $ — $ 1,044,704 Intersegment revenues 65 9 — (74 ) — Total revenues $ 884,370 $ 151,562 $ 8,846 $ (74 ) $ 1,044,704 Net income $ 167,931 $ 4,548 $ 602 $ — $ 173,081 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2014 Operating revenues (a)(b) $ 881,102 $ 159,808 $ 8,201 $ — $ 1,049,111 Intersegment revenues 95 29 — (124 ) — Total revenues $ 881,197 $ 159,837 $ 8,201 $ (124 ) $ 1,049,111 Net income $ 139,751 $ 7,235 $ 7,173 $ — $ 154,159 (a) Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014 . (b) Operating revenues include $2 million and $1 million of other affiliate revenue for the three months ended Sept. 30, 2015 and 2014 , respectively. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2015 Operating revenues (a)(b) $ 2,385,297 $ 716,731 $ 30,647 $ — $ 3,132,675 Intersegment revenues 222 43 — (265 ) — Total revenues $ 2,385,519 $ 716,774 $ 30,647 $ (265 ) $ 3,132,675 Net income $ 330,276 $ 51,784 $ 487 $ — $ 382,547 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2014 Operating revenues (a)(b) $ 2,376,935 $ 839,332 $ 30,091 $ — $ 3,246,358 Intersegment revenues 254 137 — (391 ) — Total revenues $ 2,377,189 $ 839,469 $ 30,091 $ (391 ) $ 3,246,358 Net income $ 289,460 $ 56,230 $ 16,664 $ — $ 362,354 (a) Operating revenues include $6 million and $8 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014 , respectively. (b) Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2015 and 2014 . |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefit Plans and Other Postretirement Benefits | Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Credit) Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 7,065 $ 5,985 $ 232 $ 479 Interest cost 12,714 13,319 4,375 5,926 Expected return on plan assets (18,147 ) (17,677 ) (5,951 ) (7,554 ) Amortization of prior service credit (784 ) (773 ) (1,562 ) (1,562 ) Amortization of net loss 9,094 8,473 618 1,609 Net periodic benefit cost (credit) 9,942 9,327 (2,288 ) (1,102 ) Cost not recognized due to the effects of regulation (366 ) — — — Net benefit cost (credit) recognized for financial reporting $ 9,576 $ 9,327 $ (2,288 ) $ (1,102 ) Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 21,195 $ 17,955 $ 696 $ 1,436 Interest cost 38,142 39,957 13,124 17,778 Expected return on plan assets (54,442 ) (53,031 ) (17,852 ) (22,661 ) Amortization of prior service credit (2,352 ) (2,319 ) (4,686 ) (4,685 ) Amortization of net loss 27,282 25,419 1,856 4,826 Net periodic benefit cost (credit) 29,825 27,981 (6,862 ) (3,306 ) Cost not recognized due to the effects of regulation (1,098 ) — — — Net benefit cost (credit) recognized for financial reporting $ 28,727 $ 27,981 $ (6,862 ) $ (3,306 ) In January 2015, contributions of $90.0 million were made across four of Xcel Energy’s pension plans, of which $20.0 million was attributable to PSCo. Xcel Energy does not expect additional pension contributions during 2015. |
Other Comprehensive Income
Other Comprehensive Income | 9 Months Ended |
Sep. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
Other Comprehensive Income | Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at July 1 $ (24,086 ) $ (23,573 ) Other comprehensive loss before reclassifications (17 ) (17 ) Losses (gains) reclassified from net accumulated other comprehensive loss 19 (119 ) Net current period other comprehensive income (loss) 2 (136 ) Accumulated other comprehensive loss at Sept. 30 $ (24,084 ) $ (23,709 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (23,878 ) $ (23,338 ) Other comprehensive loss before reclassifications (14 ) (15 ) Gains reclassified from net accumulated other comprehensive loss (192 ) (356 ) Net current period other comprehensive loss (206 ) (371 ) Accumulated other comprehensive loss at Sept. 30 $ (24,084 ) $ (23,709 ) Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Losses (gains) on cash flow hedges: Interest rate derivatives $ 9 (a) $ (184 ) (a) Vehicle fuel derivatives 15 (b) (7 ) (b) Total, pre-tax 24 (191 ) Tax expense (5 ) 72 Total amounts reclassified, net of tax $ 19 $ (119 ) Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ (353 ) (a) $ (546 ) (a) Vehicle fuel derivatives 38 (b) (27 ) (b) Total, pre-tax (315 ) (573 ) Tax expense 123 217 Total amounts reclassified, net of tax $ (192 ) $ (356 ) (a) Included in interest charges. (b) Included in O&M expenses. |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 277,134 $ 346,007 Less allowance for bad debts (20,563 ) (23,122 ) $ 256,571 $ 322,885 |
Inventories | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 58,532 $ 55,491 Fuel 90,135 80,963 Natural gas 89,097 102,525 $ 237,764 $ 238,979 |
Property, Plant and Equipment, Net | (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 11,689,760 $ 10,927,867 Natural gas plant 3,341,157 3,210,242 Common and other property 823,239 827,708 Plant to be retired (a) 42,336 71,534 Construction work in progress 486,133 828,620 Total property, plant and equipment 16,382,625 15,865,971 Less accumulated depreciation (4,416,323 ) (4,239,015 ) $ 11,966,302 $ 11,626,956 (a) PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). Amounts are presented net of accumulated depreciation. |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Reconciliation of Unrecognized Tax Benefits | A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 1.9 $ 1.9 Unrecognized tax benefit — Temporary tax positions 13.8 10.0 Total unrecognized tax benefit $ 15.7 $ 11.9 |
Tax Benefits Associated with NOL and Tax Credit Carryforwards | The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (6.5 ) $ (3.9 ) |
Rate Matters (Tables)
Rate Matters (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
Colorado 2015 Multi-Year Gas Rate Case - Base Rate Answer Testimony [Table Text Block] | The following table reflects the current positions of Staff and OCC: (Millions of Dollars) Staff OCC PSCo’s filed 2015 base rate request $ 40.5 $ 40.5 ROE (12.8 ) (13.7 ) Capital structure and cost of debt (12.8 ) (4.8 ) Cherokee pipeline adjustment (11.2 ) 4.8 Move to 2014 HTY (10.5 ) (16.4 ) Operating and maintenance (O&M) expenses (3.5 ) (2.7 ) Other, net (4.4 ) (1.9 ) Total adjustments $ (55.2 ) $ (34.7 ) Recommended (decrease) increase $ (14.7 ) $ 5.8 |
Colorado 2015 Multi-Year Gas Rate Case [Table Text Block] | The following table summarizes the request: (Millions of Dollars) 2015 2016 Step 2017 Step Total base rate increase $ 40.5 $ 7.6 $ 18.1 Incremental PSIA rider revenues (0.1 ) 21.7 21.2 Total revenue impact $ 40.4 $ 29.3 $ 39.3 |
Colorado 2015 Multi-Year Gas Rate Case - PSIA Rider Answer Testimony [Table Text Block] | The Staff’s recommendation for the PSIA rider is as follows: (Millions of Dollars) 2016 2017 PSCo ’ s filed incremental PSIA request $ 21.7 $ 21.2 Transfer PSIA O&M to base rates (24.1 ) (2.0 ) ROE and capital structure (8.2 ) (3.6 ) Transfer meter replacement program from base rates to PSIA 1.7 1.7 Total $ (8.9 ) $ 17.3 |
Colorado 2015 Multi-Year Gas Rate Case - Rebuttal Testimony [Table Text Block] | PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows: (Millions of Dollars) 2015 2016 Step 2017 Step PSCo’s filed base rate request $ 40.5 $ 7.6 $ 18.1 Shift O&M expenses between PSIA and base rates — 7.0 6.4 Rebuttal corrections and adjustments — — (7.7 ) Total base rate request $ 40.5 $ 14.6 $ 16.8 Incremental PSIA rider revenues (0.1 ) 14.7 21.7 Total revenue impact from rebuttal $ 40.4 $ 29.3 $ 38.5 |
Borrowings and Other Financin25
Borrowings and Other Financing Instruments (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Borrowings and Other Financing Instruments [Abstract] | |
Credit Facilities | At Sept. 30, 2015 , PSCo had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 700 $ 5 $ 695 (a) This credit facility expires in October 2019. (b) Includes outstanding commercial paper and letters of credit. |
Money Pool | |
Borrowings and Other Financing Instruments [Abstract] | |
Short-Term Borrowings | Money pool borrowings for PSCo were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 250 $ 250 Amount outstanding at period end — — Average amount outstanding — 4 Maximum amount outstanding 8 97 Weighted average interest rate, computed on a daily basis N/A 0.25 % Weighted average interest rate at period end N/A N/A |
Commercial Paper | |
Borrowings and Other Financing Instruments [Abstract] | |
Short-Term Borrowings | Commercial paper outstanding for PSCo was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 700 $ 700 Amount outstanding at period end — 382 Average amount outstanding 8 167 Maximum amount outstanding 67 393 Weighted average interest rate, computed on a daily basis 0.43 % 0.31 % Weighted average interest rate at period end N/A 0.65 |
Fair Value of Financial Asset26
Fair Value of Financial Assets and Liabilities (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Gross Notional Amounts of Commodity Forwards and Options | The following table details the gross notional amounts of commodity forwards and options at Sept. 30, 2015 and Dec. 31, 2014 : (Amounts in Thousands) (a)(b) Sept. 30, 2015 Dec. 31, 2014 Million British thermal units of natural gas 9,621 735 Gallons of vehicle fuel 79 127 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income | The following tables detail the impact of derivative activity during the three and nine months ended Sept. 30, 2015 and 2014 , on accumulated other comprehensive loss, regulatory assets and liabilities, and income: Three Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ 9 (a) $ — $ — Vehicle fuel and other commodity (29 ) — 15 (b) — — Total $ (29 ) $ — $ 24 $ — $ — Other derivative instruments Natural gas commodity $ — $ (2,140 ) $ — $ — $ (405 ) (d) Total $ — $ (2,140 ) $ — $ — $ (405 ) Nine Months Ended Sept. 30, 2015 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Gains Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (353 ) (a) $ — $ — Vehicle fuel and other commodity (24 ) — 38 (b) — — Total $ (24 ) $ — $ (315 ) $ — $ — Other derivative instruments Commodity trading $ — $ — $ — $ — $ 191 (c) Natural gas commodity — (2,496 ) — 5,460 (d) (5,925 ) (d) Total $ — $ (2,496 ) $ — $ 5,460 $ (5,734 ) Three Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (184 ) (a) $ — $ — Vehicle fuel and other commodity (27 ) — (7 ) (b) — — Total $ (27 ) $ — $ (191 ) $ — $ — Other derivative instruments Natural gas commodity $ — $ (2,126 ) $ — $ — $ (209 ) (c) Total $ — $ (2,126 ) $ — $ — $ (209 ) Nine Months Ended Sept. 30, 2014 Pre-Tax Fair Value Gains (Losses) Recognized During the Period in: Pre-Tax (Gains) Losses Reclassified into Income During the Period from: (Thousands of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities Accumulated Other Comprehensive Loss Regulatory Assets and (Liabilities) Pre-Tax Losses Recognized During the Period in Income Derivatives designated as cash flow hedges Interest rate $ — $ — $ (546 ) (a) $ — $ — Vehicle fuel and other commodity (24 ) — (27 ) (b) — — Total $ (24 ) $ — $ (573 ) $ — $ — Other derivative instruments Natural gas commodity $ — $ 5,784 $ — $ (8,579 ) (d) $ (4,589 ) (d) Total $ — $ 5,784 $ — $ (8,579 ) $ (4,589 ) (a) Recorded to interest charges. (b) Recorded to O&M expenses. (c) Amounts are recorded to electric fuel and purchased power. (d) Amounts for the three and nine months ended Sept. 30, 2015 included $0.4 million and $0.5 million , respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months ended Sept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 2015 and 2014 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level | Recurring Fair Value Measurements — The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2015 : Sept. 30, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Natural gas commodity $ — $ 1,668 $ — $ 1,668 $ (1,668 ) $ — Total current derivative assets $ — $ 1,668 $ — $ 1,668 $ (1,668 ) — PPAs (a) 1,715 Current derivative instruments $ 1,715 Noncurrent derivative assets PPAs (a) $ 3,890 Noncurrent derivative instruments $ 3,890 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 70 $ — $ 70 $ — $ 70 Other derivative instruments: Natural gas commodity — 2,000 — 2,000 (1,668 ) 332 Other commodity — 844 — 844 — 844 Total current derivative liabilities $ — $ 2,914 $ — $ 2,914 $ (1,668 ) 1,246 PPAs (a) 5,191 Current derivative instruments $ 6,437 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 16 $ — $ 16 $ — $ 16 Other derivative instruments: Other commodity — 18 — 18 — 18 Total noncurrent derivative liabilities $ — $ 34 $ — $ 34 $ — 34 PPAs (a) 14,283 Noncurrent derivative instruments $ 14,317 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015 . At Sept. 30, 2015 , derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. The following table presents, for each of the fair value hierarchy levels, PSCo’s assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014 : Dec. 31, 2014 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Natural gas commodity $ — $ 33 $ — $ 33 $ (18 ) $ 15 Total current derivative assets $ — $ 33 $ — $ 33 $ (18 ) 15 PPAs (a) 1,716 Current derivative instruments $ 1,731 Noncurrent derivative assets PPAs (a) $ 5,176 Noncurrent derivative instruments $ 5,176 Current derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 53 $ — $ 53 $ — $ 53 Other derivative instruments: Natural gas commodity — 548 — 548 (18 ) 530 Total current derivative liabilities $ — $ 601 $ — $ 601 $ (18 ) 583 PPAs (a) 5,191 Current derivative instruments $ 5,774 Noncurrent derivative liabilities Derivatives designated as cash flow hedges: Vehicle fuel and other commodity $ — $ 46 $ — $ 46 $ — $ 46 Other derivative instruments: Natural gas commodity — 35 — 35 — 35 Total noncurrent derivative liabilities $ — $ 81 $ — $ 81 $ — 81 PPAs (a) 18,176 Noncurrent derivative instruments $ 18,257 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. (b) PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014 . At Dec. 31, 2014 , derivative assets and liabilities included no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. |
Carrying Amount and Fair Value of Long-term Debt | As of Sept. 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 4,134,080 $ 4,429,648 $ 3,890,229 $ 4,328,968 |
Other Income, Net (Tables)
Other Income, Net (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income, Net | Other income, net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 162 $ 729 $ 537 $ 1,375 Other nonoperating income 607 573 1,904 2,448 Insurance policy income (expense) 453 418 233 (394 ) Other income, net $ 1,222 $ 1,720 $ 2,674 $ 3,429 |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Segment Reporting [Abstract] | |
Results by Reportable Segment | (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2015 Operating revenues (a)(b) $ 884,305 $ 151,553 $ 8,846 $ — $ 1,044,704 Intersegment revenues 65 9 — (74 ) — Total revenues $ 884,370 $ 151,562 $ 8,846 $ (74 ) $ 1,044,704 Net income $ 167,931 $ 4,548 $ 602 $ — $ 173,081 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Three Months Ended Sept. 30, 2014 Operating revenues (a)(b) $ 881,102 $ 159,808 $ 8,201 $ — $ 1,049,111 Intersegment revenues 95 29 — (124 ) — Total revenues $ 881,197 $ 159,837 $ 8,201 $ (124 ) $ 1,049,111 Net income $ 139,751 $ 7,235 $ 7,173 $ — $ 154,159 (a) Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014 . (b) Operating revenues include $2 million and $1 million of other affiliate revenue for the three months ended Sept. 30, 2015 and 2014 , respectively. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2015 Operating revenues (a)(b) $ 2,385,297 $ 716,731 $ 30,647 $ — $ 3,132,675 Intersegment revenues 222 43 — (265 ) — Total revenues $ 2,385,519 $ 716,774 $ 30,647 $ (265 ) $ 3,132,675 Net income $ 330,276 $ 51,784 $ 487 $ — $ 382,547 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total Nine Months Ended Sept. 30, 2014 Operating revenues (a)(b) $ 2,376,935 $ 839,332 $ 30,091 $ — $ 3,246,358 Intersegment revenues 254 137 — (391 ) — Total revenues $ 2,377,189 $ 839,469 $ 30,091 $ (391 ) $ 3,246,358 Net income $ 289,460 $ 56,230 $ 16,664 $ — $ 362,354 (a) Operating revenues include $6 million and $8 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014 , respectively. (b) Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2015 and 2014 . |
Benefit Plans and Other Postr29
Benefit Plans and Other Postretirement Benefits (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Components of Net Periodic Benefit Cost (Credit) | Components of Net Periodic Benefit Cost (Credit) Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 7,065 $ 5,985 $ 232 $ 479 Interest cost 12,714 13,319 4,375 5,926 Expected return on plan assets (18,147 ) (17,677 ) (5,951 ) (7,554 ) Amortization of prior service credit (784 ) (773 ) (1,562 ) (1,562 ) Amortization of net loss 9,094 8,473 618 1,609 Net periodic benefit cost (credit) 9,942 9,327 (2,288 ) (1,102 ) Cost not recognized due to the effects of regulation (366 ) — — — Net benefit cost (credit) recognized for financial reporting $ 9,576 $ 9,327 $ (2,288 ) $ (1,102 ) Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Service cost $ 21,195 $ 17,955 $ 696 $ 1,436 Interest cost 38,142 39,957 13,124 17,778 Expected return on plan assets (54,442 ) (53,031 ) (17,852 ) (22,661 ) Amortization of prior service credit (2,352 ) (2,319 ) (4,686 ) (4,685 ) Amortization of net loss 27,282 25,419 1,856 4,826 Net periodic benefit cost (credit) 29,825 27,981 (6,862 ) (3,306 ) Cost not recognized due to the effects of regulation (1,098 ) — — — Net benefit cost (credit) recognized for financial reporting $ 28,727 $ 27,981 $ (6,862 ) $ (3,306 ) |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 9 Months Ended |
Sep. 30, 2015 | |
Stockholders' Equity Note [Abstract] | |
Changes in Accumulated Other Comprehensive Loss, Net of Tax | Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at July 1 $ (24,086 ) $ (23,573 ) Other comprehensive loss before reclassifications (17 ) (17 ) Losses (gains) reclassified from net accumulated other comprehensive loss 19 (119 ) Net current period other comprehensive income (loss) 2 (136 ) Accumulated other comprehensive loss at Sept. 30 $ (24,084 ) $ (23,709 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (23,878 ) $ (23,338 ) Other comprehensive loss before reclassifications (14 ) (15 ) Gains reclassified from net accumulated other comprehensive loss (192 ) (356 ) Net current period other comprehensive loss (206 ) (371 ) Accumulated other comprehensive loss at Sept. 30 $ (24,084 ) $ (23,709 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Losses (gains) on cash flow hedges: Interest rate derivatives $ 9 (a) $ (184 ) (a) Vehicle fuel derivatives 15 (b) (7 ) (b) Total, pre-tax 24 (191 ) Tax expense (5 ) 72 Total amounts reclassified, net of tax $ 19 $ (119 ) Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 (Gains) losses on cash flow hedges: Interest rate derivatives $ (353 ) (a) $ (546 ) (a) Vehicle fuel derivatives 38 (b) (27 ) (b) Total, pre-tax (315 ) (573 ) Tax expense 123 217 Total amounts reclassified, net of tax $ (192 ) $ (356 ) (a) Included in interest charges. (b) Included in O&M expenses. |
Selected Balance Sheet Data (De
Selected Balance Sheet Data (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Accounts receivable, net | ||
Accounts receivable | $ 277,134 | $ 346,007 |
Less allowance for bad debts | (20,563) | (23,122) |
Accounts receivable, net | $ 256,571 | $ 322,885 |
Selected Balance Sheet Data Bal
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 237,764 | $ 238,979 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 58,532 | 55,491 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 90,135 | 80,963 |
Natural gas | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 89,097 | $ 102,525 |
Selected Balance Sheet Data B33
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | |
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 16,382,625 | $ 15,865,971 | |
Less accumulated depreciation | (4,416,323) | (4,239,015) | |
Property, plant and equipment, net | 11,966,302 | 11,626,956 | |
Electric plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 11,689,760 | 10,927,867 | |
Natural gas plant | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 3,341,157 | 3,210,242 | |
Common and other property | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | 823,239 | 827,708 | |
Plant to be retired | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | [1] | 42,336 | 71,534 |
Construction work in progress | |||
Public Utility, Property, Plant and Equipment [Line Items] | |||
Property, plant and equipment, gross | $ 486,133 | $ 828,620 | |
[1] | o |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2012 | Sep. 30, 2015 | Dec. 31, 2014 | |
Unrecognized Tax Benefits [Abstract] | |||
Unrecognized tax benefit — Permanent tax positions | $ 1,900,000 | $ 1,900,000 | |
Unrecognized tax benefit — Temporary tax positions | 13,800,000 | 10,000,000 | |
Total unrecognized tax benefit | 15,700,000 | 11,900,000 | |
NOL and tax credit carryforwards | (6,500,000) | (3,900,000) | |
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | 1,000,000 | ||
Amounts accrued for penalties related to unrecognized tax benefits | $ 0 | $ 0 | |
Internal Revenue Service (IRS) | |||
Tax Audits [Abstract] | |||
Year(s) under examination | 2010 and 2011 | 2012 and 2013 | |
Year of carryback claim under examination | 2,009 | ||
Potential Tax Adjustments | $ 13,000,000 | ||
State Jurisdiction (Colorado) | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,009 |
Rate Matters (Details)
Rate Matters (Details) $ in Millions | 1 Months Ended | 9 Months Ended | 12 Months Ended | |||
Jul. 31, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Feb. 28, 2015 | Sep. 30, 2015USD ($)GWh | Dec. 31, 2014GWh | |
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 56.00% | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 40.5 | |||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 3.50% | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.10% | |||||
Public Utilities, Requested Rate Base, Amount | $ 1,260 | |||||
Public Utilities, Total Revenue Impact | 40.4 | |||||
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates | $ 0 | |||||
Public Utilities, Decrease In Request By Corrections And Adjustments Based On Rebuttal Testimony | 0 | |||||
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony | 40.5 | |||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 40.4 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2016 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 7.6 | |||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 0.70% | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.10% | |||||
Public Utilities, Requested Rate Base, Amount | $ 1,310 | |||||
Public Utilities, Total Revenue Impact | 29.3 | |||||
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates | 7 | |||||
Public Utilities, Decrease In Request By Corrections And Adjustments Based On Rebuttal Testimony | 0 | |||||
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony | 14.6 | |||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 29.3 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2017 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 18.1 | |||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 1.50% | |||||
Public Utilities, Requested Return on Equity, Percentage | 10.30% | |||||
Public Utilities, Requested Rate Base, Amount | $ 1,360 | |||||
Public Utilities, Total Revenue Impact | 39.3 | |||||
Public Utilities, Increase In Request By Shift In O&M Expenses Between Rider And Base Rates | 6.4 | |||||
Public Utilities, Decrease In Request By Corrections And Adjustments Based On Rebuttal Testimony | (7.7) | |||||
Public Utilities, Increase To Base Rate Request From Rebuttal Testimony | 16.8 | |||||
Public Utilities, Total Revenue Impact From Rebuttal Testimony | 38.5 | |||||
Demand Side Management Cost Adjustment 2014 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Maximum Savings Goal (In GWh) | GWh | 384 | |||||
Demand Side Management Cost Adjustment, 2015 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Maximum Savings Goal (In GWh) | GWh | 400 | |||||
Public Utilities, Approved Electric Demand Side Management Budget | 81.6 | |||||
Public Utilities, Approved Gas Demand Side Management Budget | 13.1 | |||||
Demand Side Management Cost Adjustment [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Incentive Award Upon Achieving Savings Goal | $ 5 | |||||
Public Utilities, Percentage Of Net Economic Benefits On Which Incentive Is Earned | 5.00% | |||||
Public Utilities, Maximum Annual Incentive | $ 30 | |||||
Demand Side Management Cost Adjustment, 2016 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Approved Electric Demand Side Management Budget | 78.7 | |||||
Public Utilities, Approved Gas Demand Side Management Budget | 13.6 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2015 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | (0.1) | |||||
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony | (0.1) | |||||
Public Utilities, Revenue Projection Of Requested Rider | 67 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2016 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | 21.7 | |||||
Public Utilities, Decrease In Request By Transfer Of Operating And Maintenance Expense To Base Rates | $ (24.1) | |||||
Public Utilities, Decrease To Return On Equity And Capital Structure | (8.2) | |||||
Public Utilities, Increase in Request By Transfer meter replacement program from base rates to rider | 1.7 | |||||
Public Utilities, Recommended Rider Increase (Decrease) | (8.9) | |||||
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony | 14.7 | |||||
Public Utilities, Revenue Projection Of Requested Rider | 81.7 | |||||
CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates PSIA Rider 2017 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Revenue Impact Of Requested Rider | 21.2 | |||||
Public Utilities, Decrease In Request By Transfer Of Operating And Maintenance Expense To Base Rates | (2) | |||||
Public Utilities, Decrease To Return On Equity And Capital Structure | (3.6) | |||||
Public Utilities, Increase in Request By Transfer meter replacement program from base rates to rider | 1.7 | |||||
Public Utilities, Recommended Rider Increase (Decrease) | 17.3 | |||||
Public Utilities, Increase (Decrease) To Rider Revenues Request Related To Rebuttal Testimony | $ 21.7 | |||||
Public Utilities, Revenue Projection Of Requested Rider | 103.4 | |||||
CPUC Proceeding - Annual Electric Earnings Test | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Return On Equity Threshold For Earnings Sharing For 2015 Through 2017 | 9.83% | |||||
Colorado Public Utilities Commission Staff (CPUC) | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | 40.5 | |||||
Public Utilities, Decrease To Requested Return On Equity | (12.8) | |||||
Public Utilities, Decrease To Cost Of Debt And Capital Structure | (12.8) | |||||
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment | (11.2) | |||||
Public Utilities, Decrease In Request To Move To Historical Test Year | (10.5) | |||||
Public Utilities, Decrease To O&M Expenses | (3.5) | |||||
Public Utilities, Decrease Related To Other, Net | (4.4) | |||||
Public Utilities, Total Decrease Adjustment Related To Requested Rate Increase | (55.2) | |||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | (14.7) | |||||
Colorado Public Utilities Commission Staff (CPUC) | Demand Side Management Cost Adjustment, 2015 through 2020 [Member] | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Maximum Savings Goal (In GWh) | GWh | 400 | |||||
Public Utilities, Annual Earnings Limit | $ 84.3 | |||||
Office of Consumer Counsel [Member] | CPUC Proceeding - Colorado 2015 Multi-Year Gas Rate Case, Gas Rates 2015 | ||||||
Rate Matters [Abstract] | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 40.5 | |||||
Public Utilities, Decrease To Requested Return On Equity | (13.7) | |||||
Public Utilities, Decrease To Cost Of Debt And Capital Structure | (4.8) | |||||
Public Utilities, Increase (Decrease) Related to Pipeline Adjustment | 4.8 | |||||
Public Utilities, Decrease In Request To Move To Historical Test Year | (16.4) | |||||
Public Utilities, Decrease To O&M Expenses | (2.7) | |||||
Public Utilities, Decrease Related To Other, Net | (1.9) | |||||
Public Utilities, Total Decrease Adjustment Related To Requested Rate Increase | (34.7) | |||||
Public Utilities, Recommended Rate Increase (Decrease), Amount | $ 5.8 |
Commitments and Contingencies,
Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW | 9 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Purchased Power Agreements [Abstract] | ||
Generating capacity under long term purchased power agreements | 1,802 | 1,802 |
Purchase Power Agreement Duration, Maximum (year) | 2,032 | 2,032 |
Commitments and Contingencies37
Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions | 1 Months Ended | 9 Months Ended | |||
Oct. 31, 2015 | Apr. 30, 2012MW | Sep. 30, 2015USD ($) | Oct. 30, 2015Period | Dec. 31, 2010KilnGroupBoiler | |
Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||
Environmental Requirements [Abstract] | |||||
Generating capacity (in MW) | MW | 25 | ||||
Regional Haze Rules | |||||
Environmental Requirements [Abstract] | |||||
Number of environmental groups who petitioned the U.S. Department of the Interior | 2 | ||||
Number of coal-fired boilers | Boiler | 12 | ||||
Number of coal-fired cement kilns | Kiln | 1 | ||||
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide | |||||
Environmental Requirements [Abstract] | |||||
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment | 3 | ||||
Number of months in which the state would have to submit an implementation plan for the respective nonattainment areas | 18 months | ||||
Number of years for the state to achieve the designated attainment standard | 5 years | ||||
Capital Addition Purchase Commitments | Regional Haze Rules | |||||
Environmental Requirements [Abstract] | |||||
Liability for estimated cost to comply with regulation | $ | $ 82.4 | ||||
Subsequent Event | Green House Gas Emission Standard for Existing Sources | |||||
Environmental Requirements [Abstract] | |||||
Duration for public comment (in days) | 90 days | ||||
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants | 50.00% | ||||
Subsequent Event | National Ambient Air Quality Standards for Ozone | |||||
Environmental Requirements [Abstract] | |||||
Number of hours measured for standard | Period | 8 | ||||
Current level of air quality concentrations (in parts per billion) | 75 | ||||
Proposed level of air quality concentrations (in parts per billion) | 70 | ||||
Maximum | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||
Environmental Requirements [Abstract] | |||||
Number of years before affected facilities must demonstrate compliance | 4 years | ||||
Minimum | Electric Generating Unit Mercury and Air Toxics Standards Rule | |||||
Environmental Requirements [Abstract] | |||||
Number of years before affected facilities must demonstrate compliance | 3 years |
Commitments and Contingencies38
Commitments and Contingencies, Legal Contingencies (Details) | 3 Months Ended | 9 Months Ended | 13 Months Ended | ||
Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($)Factor | Sep. 30, 2014USD ($) | Jun. 30, 2001USD ($) | |
Legal Contingencies [Abstract] | |||||
Sales to the City of Seattle | $ 1,044,704,000 | $ 1,049,111,000 | $ 3,132,675,000 | $ 3,246,358,000 | |
Pacific Northwest FERC Refund Proceeding | |||||
Legal Contingencies [Abstract] | |||||
Accrual for legal contingency | 0 | 0 | |||
PSCo | Pacific Northwest FERC Refund Proceeding | |||||
Legal Contingencies [Abstract] | |||||
Minimum amount of damages claimed by plaintiff | 34,000,000 | 34,000,000 | |||
Sales to the City of Seattle | $ 50,000,000 | ||||
Estimated City of Seattle's claim for refunds not including interest | 28,000,000 | $ 28,000,000 | |||
Number of factors considered in assessment | Factor | 2 | ||||
Accrual for legal contingency | $ 0 | $ 0 |
Borrowings and Other Financin39
Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Sep. 30, 2015 | Dec. 31, 2014 | |
Short-term Debt [Line Items] | ||
Amount outstanding at period end | $ 0 | $ 382,000 |
Money Pool | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 250,000 | 250,000 |
Amount outstanding at period end | 0 | 0 |
Average amount outstanding | 0 | 4,000 |
Maximum amount outstanding | 8,000 | $ 97,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.25% | |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 700,000 | $ 700,000 |
Amount outstanding at period end | 0 | 382,000 |
Average amount outstanding | 8,000 | 167,000 |
Maximum amount outstanding | $ 67,000 | $ 393,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.43% | 0.31% |
Weighted average interest rate at period end (percentage) | 0.65% |
Borrowings and Other Financin40
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 0 | $ 382,000 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 5,000 | $ 6,000 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin41
Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility | Sep. 30, 2015USD ($) | |
Line of Credit Facility [Line Items] | ||
Credit Facility | $ 700,000,000 | [1] |
Drawn | 5,000,000 | [2] |
Available | 695,000,000 | |
Direct advances on the credit facility outstanding | $ 0 | |
[1] | This credit facility expires in October 2019. | |
[2] | Includes outstanding commercial paper and letters of credit. |
Borrowings and Other Financin42
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - PSCo - Bonds [Member] - Series Due May 15, 2025 [Member] $ in Millions | May. 31, 2015USD ($) |
Debt Instrument [Line Items] | |
Debt Instrument, Face Amount | $ 250 |
Debt Instrument, Interest Rate, Stated Percentage | 2.90% |
Fair Value of Financial Asset43
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) gal in Thousands, MMBTU in Thousands, $ in Millions | Sep. 30, 2015USD ($)galMMBTUCounterparty | Dec. 31, 2014galMMBTU | |
Commodity Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to commodity derivatives expected to be reclassified into earnings within the next twelve months | $ (0.1) | ||
Credit Concentration Risk | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 10 | ||
Credit Concentration Risk | External Credit Rating, Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 4 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 5.6 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 10.00% | ||
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty | 5 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 23.9 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 42.00% | ||
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member] | |||
Consideration of Credit Risk and Concentrations [Abstract] | |||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 5.7 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 10.00% | ||
Interest Rate Swap | |||
Interest Rate Derivatives [Abstract] | |||
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ (1) | ||
Natural Gas Commodity (in million British thermal units) | |||
Gross Notional Amounts of Commodity Forwards and Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | MMBTU | [1],[2] | 9,621 | 735 |
Vehicle Fuel Commodity (in gallons) | |||
Gross Notional Amounts of Commodity Forwards and Options [Abstract] | |||
Derivative, Nonmonetary Notional amount | gal | [1],[2] | 79 | 127 |
[1] | Amounts are not reflective of net positions in the underlying commodities. | ||
[2] | Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. |
Fair Value of Financial Asset44
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 3 Months Ended | 9 Months Ended | |||||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||||||
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract] | |||||||||
Derivative instruments designated as fair value hedges | $ 0 | $ 0 | $ 0 | $ 0 | |||||
Recognized gains (losses) from fair value hedges or related hedged transactions | 0 | 0 | 0 | 0 | |||||
Designated as Hedging Instrument | Cash Flow Hedges | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | (29,000) | (27,000) | (24,000) | (24,000) | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 24,000 | (191,000) | (315,000) | (573,000) | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | ||||||
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [1] | 9,000 | (184,000) | (353,000) | (546,000) | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | ||||||
Designated as Hedging Instrument | Cash Flow Hedges | Vehicle Fuel And Other Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | (29,000) | (27,000) | (24,000) | (24,000) | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | [2] | 15,000 | (7,000) | 38,000 | (27,000) | ||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 0 | 0 | |||||
Pre-tax gains (losses) recognized during the period in income | 0 | 0 | 0 | ||||||
Other Derivative Instruments | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (2,140,000) | (2,126,000) | (2,496,000) | 5,784,000 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 5,460,000 | (8,579,000) | |||||
Pre-tax gains (losses) recognized during the period in income | (405,000) | (209,000) | (5,734,000) | (4,589,000) | |||||
Other Derivative Instruments | Commodity Trading | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | ||||||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | 0 | ||||||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | ||||||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | ||||||||
Pre-tax gains (losses) recognized during the period in income | [3] | 191,000 | |||||||
Other Derivative Instruments | Natural Gas Commodity | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities | (2,140,000) | (2,126,000) | (2,496,000) | 5,784,000 | |||||
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss | 0 | 0 | 0 | 0 | |||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | 0 | 0 | 5,460,000 | [4] | (8,579,000) | [4] | |||
Pre-tax gains (losses) recognized during the period in income | (405,000) | [4] | $ (209,000) | [3] | (5,925,000) | [4] | $ (4,589,000) | [4] | |
Other Derivative Instruments | Natural Gas Commodity for Electric Generation [Member] | |||||||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | |||||||||
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | $ 400,000 | $ 500,000 | |||||||
[1] | Recorded to interest charges. | ||||||||
[2] | Recorded to O&M expenses. | ||||||||
[3] | Amounts are recorded to electric fuel and purchased power. | ||||||||
[4] | Amounts for the three and nine months ended Sept. 30, 2015 included $0.4 million and $0.5 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Losses for the nine months ended Sept. 30, 2014 included immaterial settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. The remaining derivative settlement gains and losses for the three and nine months ended Sept. 30, 2015 and 2014 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate. |
Fair Value of Financial Asset45
Fair Value of Financial Assets and Liabilities, Credit Related Contingent Features (Details) - USD ($) | Sep. 30, 2015 | Dec. 31, 2014 |
Fair Value Disclosures [Abstract] | ||
Derivative instruments in a gross liability position | $ 0 | $ 0 |
Collateral posted on derivative instruments | 0 | 0 |
Collateral posted related to adequate assurance clauses in derivative contracts | $ 0 | $ 0 |
Fair Value of Financial Asset46
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 | |||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 | |||
Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,715 | 1,731 | |||
Other Noncurrent Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 3,890 | 5,176 | |||
Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 6,437 | 5,774 | |||
Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 14,317 | 18,257 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 15 | |||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 15 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 1,246 | 583 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 70 | 53 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 332 | 530 | |||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 844 | ||||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 34 | 81 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 16 | 46 | |||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 1 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,668 | 33 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,668 | 33 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,914 | 601 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 70 | 53 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,000 | 548 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 844 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 34 | 81 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 16 | 46 | |||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Level 2 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | |||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Level 3 | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,668 | 33 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,668 | 33 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,914 | 601 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 70 | 53 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 2,000 | 548 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 844 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 34 | 81 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 16 | 46 | |||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 35 | ||||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 18 | ||||
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (1,668) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | (1,668) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (1,668) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | (1,668) | [1] | (18) | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [1] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Designated as Hedging Instrument | Vehicle Fuel And Other Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 0 | [1] | 0 | [2] | |
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Natural Gas Commodity | Cash Flow Hedges | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [2] | 0 | |||
Fair Value Measured on a Recurring Basis | Netting | Other Noncurrent Liabilities | Other Derivative Instruments | Other Commodity | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | [1] | 0 | |||
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 1,715 | [3] | 1,716 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Asset, Fair Value, Gross Asset | 3,890 | [3] | 5,176 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | 5,191 | [3] | 5,191 | [4] | |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | |||||
Derivatives, Fair Value [Line Items] | |||||
Derivative Liability, Fair Value, Gross Liability | $ 14,283 | [3] | $ 18,176 | [4] | |
[1] | PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2015. At Sept. 30, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[2] | PSCo nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities included no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. | ||||
[3] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. | ||||
[4] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, PSCo began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, PSCo qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. |
Fair Value of Financial Asset47
Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items] | ||||
Transfers into Level 3 | $ 0 | $ 0 | $ 0 | $ 0 |
Transfers out of Level 3 | $ 0 | $ 0 | $ 0 | $ 0 |
Fair Value of Financial Asset48
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Sep. 30, 2015 | Dec. 31, 2014 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 4,134,080 | $ 3,890,229 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 4,429,648 | $ 4,328,968 |
Other Income, Net (Details)
Other Income, Net (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |
Other Income and Expenses [Abstract] | ||||
Interest income | $ 162 | $ 729 | $ 537 | $ 1,375 |
Other nonoperating income | 607 | 573 | 1,904 | 2,448 |
Insurance policy income (expense) | 453 | 418 | 233 | (394) |
Other income, net | $ 1,222 | $ 1,720 | $ 2,674 | $ 3,429 |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | |||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | $ 1,044,704 | $ 1,049,111 | $ 3,132,675 | $ 3,246,358 | ||||
Net income (loss) | 173,081 | 154,159 | 382,547 | 362,354 | ||||
Affiliate electric revenue | 2,000 | 2,000 | 6,000 | 8,000 | ||||
Affiliate other revenue | 2,000 | 1,000 | 3,000 | 3,000 | ||||
Regulated Electric | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 884,370 | 881,197 | 2,385,519 | 2,377,189 | ||||
Net income (loss) | 167,931 | 139,751 | 330,276 | 289,460 | ||||
Regulated Natural Gas | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 151,562 | 159,837 | 716,774 | 839,469 | ||||
Net income (loss) | 4,548 | 7,235 | 51,784 | 56,230 | ||||
All Other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 8,846 | 8,201 | 30,647 | 30,091 | ||||
Net income (loss) | 602 | 7,173 | 487 | 16,664 | ||||
Operating Segments | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 1,044,704 | [1],[2] | 1,049,111 | [1],[2] | 3,132,675 | [3],[4] | 3,246,358 | [3],[4] |
Operating Segments | Regulated Electric | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 884,305 | [2] | 881,102 | [2] | 2,385,297 | [4] | 2,376,935 | [4] |
Operating Segments | Regulated Natural Gas | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 151,553 | 159,808 | 716,731 | 839,332 | ||||
Operating Segments | All Other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 8,846 | [1] | 8,201 | [1] | 30,647 | [3] | 30,091 | [3] |
Intersegment Eliminations | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | (74) | (124) | (265) | (391) | ||||
Net income (loss) | 0 | 0 | 0 | 0 | ||||
Intersegment Eliminations | Regulated Electric | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 65 | 95 | 222 | 254 | ||||
Intersegment Eliminations | Regulated Natural Gas | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | 9 | 29 | 43 | 137 | ||||
Intersegment Eliminations | All Other | ||||||||
Segment Reporting Information [Line Items] | ||||||||
Operating revenues | $ 0 | $ 0 | $ 0 | $ 0 | ||||
[1] | Operating revenues include $2 million and $1 million of other affiliate revenue for the three months ended Sept. 30, 2015 and 2014, respectively. | |||||||
[2] | Operating revenues include $2 million of affiliate electric revenue for the three months ended Sept. 30, 2015 and 2014. | |||||||
[3] | Operating revenues include $3 million of other affiliate revenue for the nine months ended Sept. 30, 2015 and 2014. | |||||||
[4] | Operating revenues include $6 million and $8 million of affiliate electric revenue for the nine months ended Sept. 30, 2015 and 2014 |
Benefit Plans and Other Postr51
Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | ||
Jan. 31, 2015USD ($)Plan | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | Sep. 30, 2015USD ($) | Sep. 30, 2014USD ($) | |
Pension Benefits | |||||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | $ 7,065 | $ 5,985 | $ 21,195 | $ 17,955 | |
Interest cost | 12,714 | 13,319 | 38,142 | 39,957 | |
Expected return on plan assets | (18,147) | (17,677) | (54,442) | (53,031) | |
Amortization of prior service credit | (784) | (773) | (2,352) | (2,319) | |
Amortization of net loss | 9,094 | 8,473 | 27,282 | 25,419 | |
Net periodic benefit cost (credit) | 9,942 | 9,327 | 29,825 | 27,981 | |
Costs not recognized due to the effects of regulation | (366) | 0 | (1,098) | 0 | |
Net benefit cost (credit) recognized for financial reporting | 9,576 | 9,327 | 28,727 | 27,981 | |
Total contributions to the pension plans during the period | $ 20,000 | ||||
Postretirement Health Care Benefits | |||||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | 232 | 479 | 696 | 1,436 | |
Interest cost | 4,375 | 5,926 | 13,124 | 17,778 | |
Expected return on plan assets | (5,951) | (7,554) | (17,852) | (22,661) | |
Amortization of prior service credit | (1,562) | (1,562) | (4,686) | (4,685) | |
Amortization of net loss | 618 | 1,609 | 1,856 | 4,826 | |
Net periodic benefit cost (credit) | (2,288) | (1,102) | (6,862) | (3,306) | |
Costs not recognized due to the effects of regulation | 0 | 0 | 0 | 0 | |
Net benefit cost (credit) recognized for financial reporting | $ (2,288) | $ (1,102) | $ (6,862) | $ (3,306) | |
Xcel Energy Inc. | Pension Benefits | |||||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Total contributions to the pension plans during the period | $ 90,000 | ||||
Number of Xcel Energy's pension plans to which contributions were made | Plan | 4 |
Other Comprehensive Income (Det
Other Comprehensive Income (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2015 | Sep. 30, 2014 | Sep. 30, 2015 | Sep. 30, 2014 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive loss at beginning of period | $ (23,878) | ||||
Accumulated other comprehensive loss at end of period | $ (24,084) | (24,084) | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Operating and maintenance expenses | 186,379 | $ 185,510 | 560,021 | $ 549,935 | |
Total, pre-tax | (276,946) | (237,132) | (610,610) | (557,716) | |
Tax expense | 103,865 | 82,973 | 228,063 | 195,362 | |
Gains and Losses on Cash Flow Hedges | |||||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive loss at beginning of period | (24,086) | (23,573) | (23,878) | (23,338) | |
Other comprehensive income (loss) before reclassifications | (17) | (17) | (14) | (15) | |
Gains reclassified from net accumulated other comprehensive loss | 19 | (119) | (192) | (356) | |
Net current period other comprehensive loss | 2 | (136) | (206) | (371) | |
Accumulated other comprehensive loss at end of period | (24,084) | (23,709) | (24,084) | (23,709) | |
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | 24 | (191) | (315) | (573) | |
Tax expense | (5) | 72 | 123 | 217 | |
Total, net of tax | 19 | (119) | (192) | (356) | |
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Interest charges | [1] | 9 | (184) | (353) | (546) |
Gains and Losses on Cash Flow Hedges | Vehicle Fuel Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss | |||||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Operating and maintenance expenses | [2] | $ 15 | $ (7) | $ 38 | $ (27) |
[1] | Included in interest charges. | ||||
[2] | Included in O&M expenses |