Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Aug. 03, 2015 | |
Document and Entity Information [Abstract] | ||
Entity Registrant Name | SOUTHWESTERN PUBLIC SERVICE CO | |
Entity Central Index Key | 92,521 | |
Current Fiscal Year End Date | --12-31 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 100 |
STATEMENTS OF INCOME (UNAUDITED
STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Statement [Abstract] | ||||
Operating revenues | $ 422,985 | $ 492,536 | $ 846,814 | $ 940,936 |
Operating expenses | ||||
Electric fuel and purchased power | 243,026 | 314,146 | 488,825 | 603,350 |
Operating and maintenance expenses | 73,827 | 68,963 | 147,724 | 138,361 |
Demand side management program expenses | 2,760 | 2,849 | 6,429 | 5,913 |
Depreciation and amortization | 36,750 | 35,071 | 72,489 | 65,583 |
Taxes (other than income taxes) | 13,490 | 12,507 | 28,456 | 26,153 |
Total operating expenses | 369,853 | 433,536 | 743,923 | 839,360 |
Operating income | 53,132 | 59,000 | 102,891 | 101,576 |
Other income (expense), net | 156 | (129) | 100 | (88) |
Allowance for funds used during construction — equity | 1,788 | 2,895 | 3,493 | 6,535 |
Interest charges and financing costs | ||||
Interest charges — includes other financing costs of $771, $731, $1,544 and $1,461, respectively | 21,074 | 19,645 | 41,958 | 38,926 |
Allowance for funds used during construction — debt | (1,137) | (1,721) | (2,198) | (3,848) |
Total interest charges and financing costs | 19,937 | 17,924 | 39,760 | 35,078 |
Income before income taxes | 35,139 | 43,842 | 66,724 | 72,945 |
Income taxes | 12,563 | 15,807 | 23,901 | 26,175 |
Net income | $ 22,576 | $ 28,035 | $ 42,823 | $ 46,770 |
STATEMENTS OF INCOME (UNAUDITE3
STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Interest charges and financing costs | ||||
Other financing costs | $ 771 | $ 731 | $ 1,544 | $ 1,461 |
STATEMENTS OF COMPREHENSIVE INC
STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Comprehensive income: | ||||
Net income | $ 22,576 | $ 28,035 | $ 42,823 | $ 46,770 |
Derivative instruments: | ||||
Reclassification of losses to net income, net of tax of $24 and $48 for each of the three and six months ended June 30, 2015 and 2014, respectively | 43 | 42 | 85 | 85 |
Other comprehensive income | 43 | 42 | 85 | 85 |
Comprehensive income | $ 22,619 | $ 28,077 | $ 42,908 | $ 46,855 |
STATEMENTS OF COMPREHENSIVE IN5
STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Derivative instruments: | ||||
Reclassification of losses to net income, tax | $ 24 | $ 24 | $ 48 | $ 48 |
STATEMENTS OF CASH FLOWS (UNAUD
STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
Operating activities | ||
Net income | $ 42,823 | $ 46,770 |
Adjustments to reconcile net income to cash provided by operating activities: | ||
Depreciation and amortization | 73,628 | 66,692 |
Demand side management program amortization | 837 | 837 |
Deferred income taxes | 11,866 | 51,678 |
Amortization of investment tax credits | (170) | (170) |
Allowance for equity funds used during construction | (3,493) | (6,535) |
Net derivative losses | 133 | 133 |
Changes in operating assets and liabilities: | ||
Accounts receivable | (19,478) | (15,131) |
Accrued unbilled revenues | 10,927 | (33,034) |
Inventories | 10,776 | 2,022 |
Prepayments and other | (21,378) | (12,786) |
Accounts payable | (10,210) | 16,949 |
Net regulatory assets and liabilities | 41,291 | (34,055) |
Other current liabilities | 13,510 | 1,536 |
Pension and other employee benefit obligations | (10,435) | (3,122) |
Change in other noncurrent assets | 607 | 3,558 |
Change in other noncurrent liabilities | 606 | 2,198 |
Net cash provided by operating activities | 141,840 | 87,540 |
Investing activities | ||
Utility capital/construction expenditures | (280,615) | (281,398) |
Allowance for equity funds used during construction | 3,493 | 6,535 |
Investments in utility money pool arrangement | (9,000) | (22,000) |
Repayments from utility money pool arrangement | 9,000 | 22,000 |
Net cash used in investing activities | (277,122) | (274,863) |
Financing activities | ||
Proceeds from (repayment of) short-term borrowings, net | 172,000 | 15,000 |
Proceeds from Issuance of Long-term Debt | (85) | 148,510 |
Borrowings under utility money pool arrangement | 163,700 | 382,000 |
Repayments under utility money pool arrangement | (179,700) | (420,000) |
Capital contributions from parent | 34,535 | 100,000 |
Dividends paid to parent | (53,167) | (36,264) |
Net cash provided by financing activities | 137,283 | 189,246 |
Net change in cash and cash equivalents | 2,001 | 1,923 |
Cash and cash equivalents at beginning of period | 596 | 1,011 |
Cash and cash equivalents at end of period | 2,597 | 2,934 |
Supplemental disclosure of cash flow information: | ||
Cash paid for interest (net of amounts capitalized) | (38,527) | (33,668) |
Cash (paid) received for income taxes, net | (36,992) | 8,705 |
Supplemental disclosure of non-cash investing transactions: | ||
Property, plant and equipment additions in accounts payable | $ 26,513 | $ 22,423 |
BALANCE SHEETS (UNAUDITED)
BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Current assets | ||
Cash and cash equivalents | $ 2,597 | $ 596 |
Accounts receivable, net | 78,386 | 71,626 |
Accounts receivable from affiliates | 14,701 | 1,983 |
Accrued unbilled revenues | 118,360 | 129,287 |
Inventories | 32,455 | 43,231 |
Regulatory assets | 36,554 | 52,006 |
Derivative instruments | 19,355 | 23,776 |
Deferred income taxes | 91,672 | 51,854 |
Prepayments and other | 52,854 | 31,476 |
Total current assets | 446,934 | 405,835 |
Property, plant and equipment, net | 3,948,839 | 3,743,141 |
Other assets | ||
Regulatory assets | 308,519 | 323,305 |
Derivative instruments | 29,218 | 33,164 |
Other | 14,918 | 15,859 |
Total other assets | 352,655 | 372,328 |
Total assets | 4,748,428 | 4,521,304 |
Current liabilities | ||
Short-term debt | 209,000 | 37,000 |
Borrowings under utility money pool arrangement | 0 | 16,000 |
Accounts payable | 148,722 | 160,762 |
Accounts payable to affiliates | 14,970 | 19,790 |
Regulatory liabilities | 115,316 | 87,723 |
Taxes accrued | 24,017 | 27,208 |
Accrued interest | 17,071 | 17,057 |
Dividends payable | 23,025 | 27,828 |
Derivative instruments | 3,565 | 3,565 |
Other | 90,838 | 80,211 |
Total current liabilities | 646,524 | 477,144 |
Deferred credits and other liabilities | ||
Deferred income taxes | 899,063 | 849,145 |
Regulatory liabilities | 105,051 | 115,188 |
Asset retirement obligations | 26,713 | 26,031 |
Derivative instruments | 28,860 | 30,643 |
Pension and employee benefit obligations | 93,166 | 103,670 |
Other | 9,643 | 9,320 |
Total deferred credits and other liabilities | $ 1,162,496 | $ 1,133,997 |
Commitments and contingencies | ||
Capitalization | ||
Long-term debt | $ 1,349,858 | $ 1,349,691 |
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively | 0 | 0 |
Additional paid in capital | 1,199,998 | 1,165,463 |
Retained earnings | 390,456 | 395,998 |
Accumulated other comprehensive loss | (904) | (989) |
Total common stockholder’s equity | 1,589,550 | 1,560,472 |
Total liabilities and equity | $ 4,748,428 | $ 4,521,304 |
BALANCE SHEETS (UNAUDITED) (Par
BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares | Jun. 30, 2015 | Dec. 31, 2014 |
Capitalization, Long-term Debt and Equity [Abstract] | ||
Common stock, shares authorized (in shares) | 200 | 200 |
Common stock, par value (in dollars per share) | $ 1 | $ 1 |
Common stock, shares outstanding (in shares) | 100 | 100 |
Management's Opinion
Management's Opinion | 6 Months Ended |
Jun. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Management's Opinion | In the opinion of management, the accompanying unaudited 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 SPS as of June 30, 2015 , and Dec. 31, 2014 ; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2015 and 2014 ; and its cash flows for the six months ended June 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 June 30, 2015 up to the date of issuance of these 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 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014 . These notes to the 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 financial statements and notes thereto included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014 , filed with the SEC on Feb. 23, 2015. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 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 financial statements in the SPS 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 | 6 Months Ended |
Jun. 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. SPS is currently evaluating the impact of adopting ASU 2014-09 on its 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. SPS is currently evaluating the impact of adopting ASU 2015-02 on its 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 balance sheets, SPS does not expect the implementation of ASU 2015-03 to have a material impact on its 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 (Accounting Standards Update (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, SPS does not expect the implementation of ASU 2015-07 to have a material impact on its financial statements. |
Selected Balance Sheet Data
Selected Balance Sheet Data | 6 Months Ended |
Jun. 30, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Selected Balance Sheet Data | Selected Balance Sheet Data (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 84,326 $ 77,465 Less allowance for bad debts (5,940 ) (5,839 ) $ 78,386 $ 71,626 (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 25,018 $ 24,738 Fuel 7,437 18,493 $ 32,455 $ 43,231 (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 5,580,225 $ 5,376,606 Construction work in progress 291,565 238,519 Total property, plant and equipment 5,871,790 5,615,125 Less accumulated depreciation (1,922,951 ) (1,871,984 ) $ 3,948,839 $ 3,743,141 |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Except to the extent noted below, Note 6 to the financial statements included in SPS’ 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 — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including a 2009 carryback claim. As of June 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. SPS is not expected to accrue any income tax expense related to this adjustment. As of June 30, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution are uncertain. State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2015, SPS’ 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) June 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 1.6 $ 1.5 Unrecognized tax benefit — Temporary tax positions 12.6 11.7 Total unrecognized tax benefit $ 14.2 $ 13.2 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) June 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (6.0 ) $ (4.8 ) It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process progresses 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 $2 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 June 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014. |
Rate Matters
Rate Matters | 6 Months Ended |
Jun. 30, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
Rate Matters | Rate Matters Except to the extent noted below, the circumstances set forth in Note 10 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT) Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million , or 6.7 percent . The filing was based on a historic test year ending June 2014, adjusted for known and measurable changes, a return on equity (ROE) of 10.25 percent , an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent . In March 2015, SPS revised its requested increase to $58.9 million based on updated information. SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014. In May 2015, several intervenors filed direct testimony in response to SPS’ rate request, including the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), and the PUCT Staff (Staff). • AXM recommended a rate decrease of $13.6 million , an ROE of 9.40 percent and an equity ratio of 53.97 percent . • The OPUC recommended a rate increase of $1.8 million , an ROE of 9.20 percent and an equity ratio of 52.38 percent . • The Staff recommended a rate decrease of $2.6 million , an ROE of 9.30 percent and an equity ratio of 53.97 percent . In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42 million , or 4.4 percent . SPS Rebuttal Testimony (Millions of Dollars) AXM OPUC Staff SPS’ revised rate request $ 58.9 $ 58.9 $ 58.9 $ 58.9 Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) — Lower ROE (10.9 ) (13.5 ) (12.1 ) — Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 ) — — O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 ) Depreciation expense (13.3 ) — — — Property taxes — (1.2 ) (4.4 ) (1.8 ) Revenue adjustments (2.2 ) (0.2 ) — — Wholesale load reductions (13.2 ) — (11.1 ) — Southwest Power Pool (SPP) transmission expansion plan — — — (7.3 ) Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 ) Total recommendation $ (13.6 ) $ 1.8 $ (2.6 ) $ 46.4 Adjustment to move rate case expenses to a separate docket — — — (4.3 ) Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8 $ (2.6 ) $ 42.1 New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. Hearings were completed in July 2015. A PUCT decision is expected in the fourth quarter of 2015. Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC) New Mexico 2015 Electric Rate Case — In June 2015, SPS filed an electric rate case with the NMPRC for an increase in non-fuel base rates of $31.5 million and a base fuel decrease of $30.1 million . The rate filing was based on a 2016 forecast test year (FTY), a requested return on equity of 10.25 percent , a jurisdictional electric rate base of $777.9 million and an equity ratio of 53.97 percent . In June 2015, SPS’ rate case application was dismissed by the NMPRC. The NMPRC determined that the filing did not comply with its new interpretation of the statute regarding FTY periods and the corresponding timing of a rate case submission in relation to the FTY used in the case. This new interpretation occurred during the recent Public Service Company of New Mexico rate case. In July, SPS filed an appeal with the New Mexico Supreme Court. In addition, SPS plans to file a rate case later this year. Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC) Wholesale Rate ROE Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent , and the SPS transmission base formula rate ROE of 10.77 percent , are unjust and unreasonable, and asking that the ROEs be reduced to 9.15 percent and 9.65 percent , respectively, effective April 20, 2012. In July 2013, Golden Spread filed a second complaint, again asking that the ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent , respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures. A third rate complaint was filed in October 2014 by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in certain SPS production formula rates for Golden Spread and the New Mexico cooperatives and transmission formula rates be reduced, this time to 8.61 percent and 9.11 percent , respectively, effective Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. The FERC established effective dates for refunds of April 20, 2012 (first refund period), July 19, 2013 (second refund period) and Oct. 20, 2014 (third refund period), respectively. SPS sought rehearing of the FERC decisions to allow back-to-back complaints involving the same issue with consecutive 15 month refund periods, asserting this ruling is contrary to the governing statute. On May 12, 2015, FERC denied the rehearing request as it pertained to the first two rate complaints. In July 2015, SPS filed an appeal to the D.C. Circuit Court of Appeals of the FERC orders in the first two rate complaints allowing the sequential complaints and consecutive 15 month refund periods. The D.C. Circuit Court has not established a procedural schedule. FERC action on the similar SPS rehearing request related to the third complaint is pending. In the first half of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs: Refund Period Production ROE Transmission ROE (a) Golden Spread (b) 1 8.78 % 9.28 % 2 8.51 9.01 3 8.45 8.95 SPS 1 10.25 10.39 2 10.25 11.20 3 (c) 10.40 11.20 FERC Staff 1 8.97 9.47 2 8.64 9.14 3 8.53 9.03 (a) Includes a SPP RTO membership adder up to 50 basis points. (b) For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only). (c) In addition to the recommended ROEs, SPS also filed testimony recommending the ROEs remain unchanged. Hearings scheduled for July 2015 for the first two rate complaints were canceled and the parties agreed to file briefs based on pre-filed testimony. An initial ALJ decision on the first two complaints is expected to be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016. A hearing for the third rate complaint is scheduled for Oct. 2015, with an ALJ initial decision expected in January 2016 and a final FERC order no earlier than later in 2016. SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of June 30, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually. 2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS. The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate. In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12 CP system. In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.5 million of principal and interest has been accrued during 2015. 2015 Production Formula Rate Change Filing — In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, certain New Mexico cooperatives and West Texas Municipal Power Agency, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. In March 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties remain engaged in settlement judge procedures. Effective June 1, 2015, the Golden Spread contract demand quantity subject to the formula rate change declined from 500 MW to 300 MW. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 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 Note 5, Notes 10 and 11 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Notes 5 and 6 to SPS’ Quarterly Report on Form 10-Q for the quarterly period ended March 31, 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 SPS’ financial position. Purchased Power Agreements (PPAs) Under certain PPAs, SPS purchases power from independent power producing entities that own natural gas fueled power plants for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS 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. SPS had approximately 827 megawatts (MW) of capacity under long-term PPAs as of June 30, 2015 and Dec. 31, 2014 , with entities that have been determined to be variable interest entities. SPS has concluded that these entities are not required to be consolidated in its 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 2033 . Environmental Contingencies Environmental Requirements Water Federal Clean Water Act (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 will go into effect beginning in August 2015. SPS 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. Air Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO 2 ) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Texas, using an emissions trading program. In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015. Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million or less. 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, SPS had met the EGU MATS rule through a combination of emission control projects and existing controls. Mercury controls were installed in SPS’ Tolk and Harrington plants for a capital cost of $8 million . On June 29, 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. SPS 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), Texas identified the SPS facilities that will have to reduce SO 2 , NOx and PM emissions under BART and set emissions limits for those facilities. Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in December 2015. In May 2014, the EPA issued a request for information under the CAA related to SO 2 control equipment at Tolk Units 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead adopt a Federal Implementation Plan. The EPA proposed to require dry scrubbers on both Tolk units to reduce SO 2 emissions to help achieve reasonable progress goals for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in December 2015. Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million , with an annual operating cost of approximately $10.4 million . SPS believes these costs would be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows. 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 Xcel Energy 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 SPS’ Tolk and Harrington plants. The Tolk and Harrington Plants utilize low sulfur coal to reduce SO 2 emissions. The Texas Commission on Environmental Quality (TCEQ) is expected to make recommendations for nonattainment areas to the EPA in September 2015 with a decision 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. The TCEQ could require additional SO 2 controls on one or more of the units at Tolk and Harrington. SPS cannot evaluate the impacts of this ruling until the designation of nonattainment areas is made and any required state plans are developed. SPS believes that, should SO 2 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 SPS 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 SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. |
Borrowings and Other Financing
Borrowings and Other Financing Instruments | 6 Months Ended |
Jun. 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 SPS were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 100 $ 100 Amount outstanding at period end — 16 Average amount outstanding 4 9 Maximum amount outstanding 36 100 Weighted average interest rate, computed on a daily basis 0.52 % 0.22 % Weighted average interest rate at period end N/A 0.45 Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for SPS was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 400 $ 400 Amount outstanding at period end 209 37 Average amount outstanding 160 83 Maximum amount outstanding 209 241 Weighted average interest rate, computed on a daily basis 0.48 % 0.26 % Weighted average interest rate at period end 0.49 0.47 Letters of Credit — SPS uses letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At June 30, 2015 and Dec. 31, 2014 , there were $36.0 million and $30.0 million of letters of credit outstanding, respectively 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, SPS 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 June 30, 2015 , SPS had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 400 $ 245 $ 155 (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. SPS had no direct advances on the credit facility outstanding at June 30, 2015 and Dec. 31, 2014 . |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities | 6 Months Ended |
Jun. 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. Electric commodity derivatives held by SPS include transmission congestion instruments purchased from the SPP, generally referred to as financial transmission rights (FTRs). FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model - including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the financial statements of SPS. Derivative Instruments Fair Value Measurements SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices. Interest Rate Derivatives — SPS may enter 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 June 30, 2015, accumulated other comprehensive losses related to interest rate derivatives included $0.2 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 unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ 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 — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products and FTRs. The following table details the gross notional amounts of commodity FTRs at June 30, 2015 and Dec. 31, 2014: (Amounts in Thousands) (a) June 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 13,620 6,930 (a) Amounts are not reflective of net positions in the underlying commodities. Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for each of the three and six months ended June 30, 2015 and 2014. During the three and six months ended June 30, 2015, changes in the fair value of FTRs resulted in pre-tax net losses of $1.2 million and $2.0 million , respectively, recognized as regulatory assets and liabilities. For the three and six months ended June 30, 2014, changes in the fair value of FTRs resulted in pre-tax net losses of $1.0 million and $2.4 million , respectively, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms. FTR settlement gains of $1.7 million and $1.6 million , respectively, were recognized for the three and six months ended June 30, 2015, respectively, recorded to electric fuel and purchased power. For the three and six months ended June 30, 2014, FTR settlement losses of $1.9 million and gains of $0.9 million , respectively, were recognized and recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. SPS had no derivative instruments designated as fair value hedges during the three and six months ended June 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 — SPS 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 SPS’ 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 balance sheets. SPS 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. SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At June 30, 2015, one of SPS’ eight most significant counterparties for these activities, comprising $9.6 million or 9 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Six of the eight most significant counterparties, comprising $58.5 million or 54 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $1.3 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis. All eight of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities. Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2015: June 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: Electric commodity $ — $ — $ 21,533 $ 21,533 $ (10,070 ) $ 11,463 Total current derivative assets $ — $ — $ 21,533 $ 21,533 $ (10,070 ) 11,463 PPAs (a) 7,892 Current derivative instruments $ 19,355 Noncurrent derivative assets PPAs (a) $ 29,218 Noncurrent derivative instruments $ 29,218 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 10,070 $ 10,070 $ (10,070 ) $ — Total current derivative liabilities $ — $ — $ 10,070 $ 10,070 $ (10,070 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 28,860 Noncurrent derivative instruments $ 28,860 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS 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 in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS 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) SPS nets derivative instruments and related collateral in its 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 June 30, 2015. At June 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, SPS’ derivative 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: Electric commodity $ — $ — $ 25,774 $ 25,774 $ (9,890 ) $ 15,884 Total current derivative assets $ — $ — $ 25,774 $ 25,774 $ (9,890 ) 15,884 PPAs (a) 7,892 Current derivative instruments $ 23,776 Noncurrent derivative assets PPAs (a) $ 33,164 Noncurrent derivative instruments $ 33,164 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 9,890 $ 9,890 $ (9,890 ) $ — Total current derivative liabilities $ — $ — $ 9,890 $ 9,890 $ (9,890 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 30,643 Noncurrent derivative instruments $ 30,643 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS 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 in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS 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) SPS nets derivative instruments and related collateral in its 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 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 the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2015 and 2014: Three Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at April 1 $ 6,457 $ 5,791 Purchases 17,284 38,419 Settlements (10,022 ) (13,554 ) Net transactions recorded during the period: (Losses) Gains recognized as regulatory assets and liabilities (2,256 ) 3,286 Balance at June 30 $ 11,463 $ 33,942 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 15,884 $ 9,933 Purchases 22,213 39,475 Settlements (18,400 ) (14,655 ) Net transactions recorded during the period: Losses recognized as regulatory assets and liabilities (8,234 ) (811 ) Balance at June 30 $ 11,463 $ 33,942 SPS 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 six months ended June 30, 2015 and 2014. Fair Value of Long-Term Debt As of June 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,349,858 $ 1,491,780 $ 1,349,691 $ 1,572,414 The fair value of SPS’ 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 June 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 (Expense), Net
Other Income (Expense), Net | 6 Months Ended |
Jun. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income (Expense), Net | Other Income (Expense), Net Other income (expense), net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 13 $ 53 $ 45 $ 240 Other nonoperating income 65 2 110 — Insurance policy income (expense) 78 (184 ) (55 ) (328 ) Other income (expense), net $ 156 $ (129 ) $ 100 $ (88 ) |
Benefit Plans and Other Postret
Benefit Plans and Other Postretirement Benefits | 6 Months Ended |
Jun. 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 June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 2,751 $ 2,296 $ 238 $ 311 Interest cost 5,046 5,111 437 643 Expected return on plan assets (7,152 ) (6,545 ) (635 ) (811 ) Amortization of prior service cost (credit) 10 13 (100 ) (101 ) Amortization of net loss (gain) 3,772 3,331 (160 ) (81 ) Net periodic benefit cost (credit) 4,427 4,206 (220 ) (39 ) Credits recognized due to the effects of regulation 686 708 — — Net benefit cost (credit) recognized for financial reporting $ 5,113 $ 4,914 $ (220 ) $ (39 ) Six Months Ended June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 5,503 $ 4,592 $ 477 $ 623 Interest cost 10,092 10,222 873 1,286 Expected return on plan assets (14,305 ) (13,090 ) (1,270 ) (1,623 ) Amortization of prior service cost (credit) 20 27 (200 ) (201 ) Amortization of net loss (gain) 7,544 6,663 (320 ) (161 ) Net periodic benefit cost (credit) 8,854 8,414 (440 ) (76 ) Credits recognized due to the effects of regulation 1,399 1,415 — — Net benefit cost (credit) recognized for financial reporting $ 10,253 $ 9,829 $ (440 ) $ (76 ) In January 2015, contributions of $90.0 million were made across four of Xcel Energys pension plans, of which $11.6 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2015. |
Other Comprehensive Income
Other Comprehensive Income | 6 Months Ended |
Jun. 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 six months ended June 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Accumulated other comprehensive loss at April 1 $ (947 ) $ (1,118 ) Losses reclassified from net accumulated other comprehensive loss 43 42 Net current period other comprehensive income 43 42 Accumulated other comprehensive loss at June 30 $ (904 ) $ (1,076 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (989 ) $ (1,161 ) Losses reclassified from net accumulated other comprehensive loss 85 85 Net current period other comprehensive income 85 85 Accumulated other comprehensive loss at June 30 $ (904 ) $ (1,076 ) Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 67 (a) $ 66 (a) Total, pre-tax 67 66 Tax benefit (24 ) (24 ) Total amounts reclassified, net of tax $ 43 $ 42 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 133 (a) $ 133 (a) Total, pre-tax 133 133 Tax benefit (48 ) (48 ) Total amounts reclassified, net of tax $ 85 $ 85 (a) Included in interest charges. |
Selected Balance Sheet Data (Ta
Selected Balance Sheet Data (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Balance Sheet Related Disclosures [Abstract] | |
Accounts Receivable, Net | (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 84,326 $ 77,465 Less allowance for bad debts (5,940 ) (5,839 ) $ 78,386 $ 71,626 |
Inventories | (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 25,018 $ 24,738 Fuel 7,437 18,493 $ 32,455 $ 43,231 |
Property, Plant and Equipment, Net | (Thousands of Dollars) June 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 5,580,225 $ 5,376,606 Construction work in progress 291,565 238,519 Total property, plant and equipment 5,871,790 5,615,125 Less accumulated depreciation (1,922,951 ) (1,871,984 ) $ 3,948,839 $ 3,743,141 |
Income Taxes (Tables)
Income Taxes (Tables) | 6 Months Ended |
Jun. 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) June 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 1.6 $ 1.5 Unrecognized tax benefit — Temporary tax positions 12.6 11.7 Total unrecognized tax benefit $ 14.2 $ 13.2 |
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) June 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (6.0 ) $ (4.8 ) |
Rate Matters (Tables)
Rate Matters (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Public Utilities, General Disclosures [Abstract] | |
SPS' Texas 2015 Electric Rate Case [Table Text Block] | In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42 million , or 4.4 percent . SPS Rebuttal Testimony (Millions of Dollars) AXM OPUC Staff SPS’ revised rate request $ 58.9 $ 58.9 $ 58.9 $ 58.9 Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) — Lower ROE (10.9 ) (13.5 ) (12.1 ) — Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 ) — — O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 ) Depreciation expense (13.3 ) — — — Property taxes — (1.2 ) (4.4 ) (1.8 ) Revenue adjustments (2.2 ) (0.2 ) — — Wholesale load reductions (13.2 ) — (11.1 ) — Southwest Power Pool (SPP) transmission expansion plan — — — (7.3 ) Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 ) Total recommendation $ (13.6 ) $ 1.8 $ (2.6 ) $ 46.4 Adjustment to move rate case expenses to a separate docket — — — (4.3 ) Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8 $ (2.6 ) $ 42.1 |
FERC Wholesale Rate Complaints [Table Text Block] | In the first half of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs: Refund Period Production ROE Transmission ROE (a) Golden Spread (b) 1 8.78 % 9.28 % 2 8.51 9.01 3 8.45 8.95 SPS 1 10.25 10.39 2 10.25 11.20 3 (c) 10.40 11.20 FERC Staff 1 8.97 9.47 2 8.64 9.14 3 8.53 9.03 (a) Includes a SPP RTO membership adder up to 50 basis points. (b) For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only). (c) In addition to the recommended ROEs, SPS also filed testimony recommending the ROEs remain unchanged. |
Borrowings and Other Financin24
Borrowings and Other Financing Instruments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Borrowings and Other Financing Instruments [Abstract] | |
Credit Facilities | At June 30, 2015 , SPS had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 400 $ 245 $ 155 (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 SPS were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 100 $ 100 Amount outstanding at period end — 16 Average amount outstanding 4 9 Maximum amount outstanding 36 100 Weighted average interest rate, computed on a daily basis 0.52 % 0.22 % Weighted average interest rate at period end N/A 0.45 |
Commercial Paper | |
Borrowings and Other Financing Instruments [Abstract] | |
Short-Term Borrowings | Commercial paper outstanding for SPS was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 400 $ 400 Amount outstanding at period end 209 37 Average amount outstanding 160 83 Maximum amount outstanding 209 241 Weighted average interest rate, computed on a daily basis 0.48 % 0.26 % Weighted average interest rate at period end 0.49 0.47 |
Fair Value of Financial Asset25
Fair Value of Financial Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Gross Notional Amounts of Commodity FTRs | The following table details the gross notional amounts of commodity FTRs at June 30, 2015 and Dec. 31, 2014: (Amounts in Thousands) (a) June 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 13,620 6,930 (a) Amounts are not reflective of net positions in the underlying commodities. |
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, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2015: June 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: Electric commodity $ — $ — $ 21,533 $ 21,533 $ (10,070 ) $ 11,463 Total current derivative assets $ — $ — $ 21,533 $ 21,533 $ (10,070 ) 11,463 PPAs (a) 7,892 Current derivative instruments $ 19,355 Noncurrent derivative assets PPAs (a) $ 29,218 Noncurrent derivative instruments $ 29,218 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 10,070 $ 10,070 $ (10,070 ) $ — Total current derivative liabilities $ — $ — $ 10,070 $ 10,070 $ (10,070 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 28,860 Noncurrent derivative instruments $ 28,860 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS 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 in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS 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) SPS nets derivative instruments and related collateral in its 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 June 30, 2015. At June 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, SPS’ derivative 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: Electric commodity $ — $ — $ 25,774 $ 25,774 $ (9,890 ) $ 15,884 Total current derivative assets $ — $ — $ 25,774 $ 25,774 $ (9,890 ) 15,884 PPAs (a) 7,892 Current derivative instruments $ 23,776 Noncurrent derivative assets PPAs (a) $ 33,164 Noncurrent derivative instruments $ 33,164 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 9,890 $ 9,890 $ (9,890 ) $ — Total current derivative liabilities $ — $ — $ 9,890 $ 9,890 $ (9,890 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 30,643 Noncurrent derivative instruments $ 30,643 (a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS 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 in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS 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) SPS nets derivative instruments and related collateral in its 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 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. |
Changes in Level 3 Commodity Derivatives | The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2015 and 2014: Three Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at April 1 $ 6,457 $ 5,791 Purchases 17,284 38,419 Settlements (10,022 ) (13,554 ) Net transactions recorded during the period: (Losses) Gains recognized as regulatory assets and liabilities (2,256 ) 3,286 Balance at June 30 $ 11,463 $ 33,942 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 15,884 $ 9,933 Purchases 22,213 39,475 Settlements (18,400 ) (14,655 ) Net transactions recorded during the period: Losses recognized as regulatory assets and liabilities (8,234 ) (811 ) Balance at June 30 $ 11,463 $ 33,942 |
Carrying Amount and Fair Value of Long-term Debt | As of June 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: June 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,349,858 $ 1,491,780 $ 1,349,691 $ 1,572,414 |
Other Income (Expense), Net (Ta
Other Income (Expense), Net (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Other Income and Expenses [Abstract] | |
Other Income (Expense), Net | Other income (expense), net consisted of the following: Three Months Ended June 30 Six Months Ended June 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 13 $ 53 $ 45 $ 240 Other nonoperating income 65 2 110 — Insurance policy income (expense) 78 (184 ) (55 ) (328 ) Other income (expense), net $ 156 $ (129 ) $ 100 $ (88 ) |
Benefit Plans and Other Postr27
Benefit Plans and Other Postretirement Benefits (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Components of Net Periodic Benefit Cost (Credit) | Components of Net Periodic Benefit Cost (Credit) Three Months Ended June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 2,751 $ 2,296 $ 238 $ 311 Interest cost 5,046 5,111 437 643 Expected return on plan assets (7,152 ) (6,545 ) (635 ) (811 ) Amortization of prior service cost (credit) 10 13 (100 ) (101 ) Amortization of net loss (gain) 3,772 3,331 (160 ) (81 ) Net periodic benefit cost (credit) 4,427 4,206 (220 ) (39 ) Credits recognized due to the effects of regulation 686 708 — — Net benefit cost (credit) recognized for financial reporting $ 5,113 $ 4,914 $ (220 ) $ (39 ) Six Months Ended June 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 5,503 $ 4,592 $ 477 $ 623 Interest cost 10,092 10,222 873 1,286 Expected return on plan assets (14,305 ) (13,090 ) (1,270 ) (1,623 ) Amortization of prior service cost (credit) 20 27 (200 ) (201 ) Amortization of net loss (gain) 7,544 6,663 (320 ) (161 ) Net periodic benefit cost (credit) 8,854 8,414 (440 ) (76 ) Credits recognized due to the effects of regulation 1,399 1,415 — — Net benefit cost (credit) recognized for financial reporting $ 10,253 $ 9,829 $ (440 ) $ (76 ) |
Other Comprehensive Income (Tab
Other Comprehensive Income (Tables) | 6 Months Ended |
Jun. 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 six months ended June 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Accumulated other comprehensive loss at April 1 $ (947 ) $ (1,118 ) Losses reclassified from net accumulated other comprehensive loss 43 42 Net current period other comprehensive income 43 42 Accumulated other comprehensive loss at June 30 $ (904 ) $ (1,076 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (989 ) $ (1,161 ) Losses reclassified from net accumulated other comprehensive loss 85 85 Net current period other comprehensive income 85 85 Accumulated other comprehensive loss at June 30 $ (904 ) $ (1,076 ) |
Reclassifications out of Accumulated Other Comprehensive Loss | Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 67 (a) $ 66 (a) Total, pre-tax 67 66 Tax benefit (24 ) (24 ) Total amounts reclassified, net of tax $ 43 $ 42 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 133 (a) $ 133 (a) Total, pre-tax 133 133 Tax benefit (48 ) (48 ) Total amounts reclassified, net of tax $ 85 $ 85 (a) Included in interest charges. |
Selected Balance Sheet Data (De
Selected Balance Sheet Data (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Accounts receivable, net | ||
Accounts receivable | $ 84,326 | $ 77,465 |
Less allowance for bad debts | (5,940) | (5,839) |
Accounts receivable, net | $ 78,386 | $ 71,626 |
Selected Balance Sheet Data Bal
Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 32,455 | $ 43,231 |
Materials and supplies | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | 25,018 | 24,738 |
Fuel | ||
Public Utilities, Inventory [Line Items] | ||
Inventories | $ 7,437 | $ 18,493 |
Selected Balance Sheet Data B31
Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 5,871,790 | $ 5,615,125 |
Less accumulated depreciation | (1,922,951) | (1,871,984) |
Property, plant and equipment, net | 3,948,839 | 3,743,141 |
Electric plant | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | 5,580,225 | 5,376,606 |
Construction work in progress | ||
Public Utility, Property, Plant and Equipment [Line Items] | ||
Property, plant and equipment, gross | $ 291,565 | $ 238,519 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) | 3 Months Ended | 6 Months Ended | |
Sep. 30, 2012 | Jun. 30, 2015 | Dec. 31, 2014 | |
Unrecognized Tax Benefits [Abstract] | |||
Unrecognized tax benefit - Permanent tax positions | $ 1,600,000 | $ 1,500,000 | |
Unrecognized tax benefit - Temporary tax positions | 12,600,000 | 11,700,000 | |
Total unrecognized tax benefit | 14,200,000 | 13,200,000 | |
NOL and tax credit carryforwards | (6,000,000) | $ (4,800,000) | |
Upper bound of decrease in unrecognized tax benefit that is reasonably possible | 2,000,000 | ||
Amounts accrued for penalties related to unrecognized tax benefits | $ 0 | ||
Internal Revenue Service (IRS) | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,009 | ||
Year(s) under examination | 2010 and 2011 | ||
Year of carryback claim under examination | 2,009 | ||
Potential Tax Adjustments | $ 12,000,000 | ||
State Jurisdiction (Texas) | |||
Tax Audits [Abstract] | |||
Earliest year subject to examination | 2,009 |
Rate Matters (Details)
Rate Matters (Details) $ in Thousands | Jun. 08, 2015USD ($) | Jun. 01, 2015MW | May. 12, 2015 | Jul. 31, 2015 | Jun. 30, 2015USD ($) | May. 31, 2015USD ($) | Mar. 31, 2015USD ($) | Jan. 31, 2015 | Dec. 31, 2014USD ($) | Oct. 31, 2014 | Aug. 31, 2013Factor | Jul. 31, 2013 | Apr. 30, 2012 | Jun. 30, 2015USD ($) | Jun. 30, 2015USD ($) | |
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Other Liabilities, Current | $ 90,838 | $ 80,211 | $ 90,838 | $ 90,838 | ||||||||||||
Texas 2015 Electric Rate Case | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 64,800 | |||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 6.70% | |||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | |||||||||||||||
Public Utilities, Requested Rate Base, Amount | $ 1,600,000 | |||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | |||||||||||||||
Public Utilities, Revised requested rate increase (decrease) | $ 58,900 | |||||||||||||||
Public Utilities, Additional capital investment | $ 392,000 | |||||||||||||||
FERC Proceeding - FERC Orders | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Number of components included in regulatory proceeding | Factor | 2 | |||||||||||||||
Other Liabilities, Current | $ 50,400 | |||||||||||||||
Current year increase (decrease) to pre-tax earnings resulting from regulatory proceedings | $ 1,500 | |||||||||||||||
Number of customers for which a public utility proposes to revise formula rates | 6 | |||||||||||||||
Federal Energy Regulatory Commission (FERC) | FERC Proceeding - FERC Orders | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Number of coincident peaks used as demand allocator, revised | 3 | |||||||||||||||
Number of coincident peaks used as demand allocator, original | 12 | |||||||||||||||
SPS | Wholesale Electric Rate Complaint, April 20, 2012 through July 18, 2013 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, First refund period | 1 | |||||||||||||||
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage | 10.25% | |||||||||||||||
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage | [1] | 10.39% | ||||||||||||||
SPS | Wholesale Electric Rate Complaints | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Base return on equity charged to customers through production formula rates, Percentage | 10.25% | |||||||||||||||
Public Utilities, Base return on equity charged to customers through transmission formula rates, Percentage | 10.77% | |||||||||||||||
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage | 8.61% | 9.15% | 9.15% | |||||||||||||
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage | 9.11% | 9.65% | 9.65% | |||||||||||||
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties | 50 | |||||||||||||||
SPS | Wholesale Electric Rate Complaints, Refunds as of April 20, 2012 and July 19, 2013 | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
FERC denied the rehearing request as it pertained to the first two rate complaints | 2 | |||||||||||||||
Public Utilities, rehearing sought in FERC decision regarding number of consecutive month periods | 15 months | |||||||||||||||
Number of hearings scheduled that were canceled and parties agreed to file briefs based on pre-filed testimony | 2 | |||||||||||||||
Number of complaints where decision is expected by ALJ in the future | 2 | |||||||||||||||
SPS | Texas 2015 Electric Rate Case | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 42,000 | |||||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Percentage | 4.40% | |||||||||||||||
Public Utilities, Revised requested rate increase (decrease) | 58,900 | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by rebuttal testimony | $ 46,400 | |||||||||||||||
Public Utilities, Post test year adjustment related to capital expenditures | 0 | |||||||||||||||
Public Utilities, ROE | 0 | |||||||||||||||
Rate base adjustments (largely the removal of the prepaid pension asset) | 0 | |||||||||||||||
Public Utilities, Operating and maintenance expenses | (1,600) | |||||||||||||||
Public Utilities, Depreciation expense | 0 | |||||||||||||||
Public Utilities, Property taxes | (1,800) | |||||||||||||||
Public Utilities, Revenue adjustments | 0 | |||||||||||||||
Public Utilities, Wholesale load reductions | 0 | |||||||||||||||
Public Utilities, SPP transmission expansion plan | (7,300) | |||||||||||||||
Public Utilities, Other net | (1,800) | |||||||||||||||
Public Utilities, Adjustment to move rate case expenses to separate docket | (4,300) | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by rebuttal testimony, excluding rate case expenses | $ 42,100 | |||||||||||||||
SPS | New Mexico 2014 Electric Rate Case | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Requested Return on Equity, Percentage | 10.25% | |||||||||||||||
Public Utilities, Jurisdictional electric rate base | $ 777,900 | |||||||||||||||
Public Utilities, Requested Equity Capital Structure, Percentage | 53.97% | |||||||||||||||
Public Utilities, Non-fuel proposed base rate increase (decrease) | $ 31,500 | |||||||||||||||
Public Utilities, Proposed base fuel rate increase (decrease) | $ (30,100) | |||||||||||||||
SPS | FERC Proceeding - FERC Orders | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Number of coincident peaks used as demand allocator, original | 12 | |||||||||||||||
Golden Spread contract demand quantity subject to the formula rate change prior to June 1, 2015 | MW | 500 | |||||||||||||||
Change in Golden Spread contract demand quantity subject to the formula rate change | MW | 300 | |||||||||||||||
SPS | Wholesale Electric Rate Complaint, July 19, 2013 through Oct. 19, 2014 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage | 10.25% | |||||||||||||||
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage | [1] | 11.20% | ||||||||||||||
Public Utilities, Second refund period | 2 | |||||||||||||||
SPS | Wholesale Electric Rate Complaint, Oct. 20, 2014 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage | [2] | 10.40% | ||||||||||||||
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage | [1],[2] | 11.20% | ||||||||||||||
Public Utilities, Third refund period | 3 | |||||||||||||||
SPS | Golden Spread [Member] | Wholesale Electric Rate Complaint, April 20, 2012 through July 18, 2013 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, First refund period | [3] | 1 | ||||||||||||||
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage | [3] | 8.78% | ||||||||||||||
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage | [1],[3] | 9.28% | ||||||||||||||
SPS | Golden Spread [Member] | Wholesale Electric Rate Complaint, July 19, 2013 through Oct. 19, 2014 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage | [3] | 8.51% | ||||||||||||||
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage | [1],[3] | 9.01% | ||||||||||||||
Public Utilities, Second refund period | [3] | 2 | ||||||||||||||
SPS | Golden Spread [Member] | Wholesale Electric Rate Complaint, Oct. 20, 2014 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage | [3] | 8.45% | ||||||||||||||
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage | [1],[3] | 8.95% | ||||||||||||||
Public Utilities, Third refund period | [3] | 3 | ||||||||||||||
SPS | Alliance of Xcel Municipalities [Member] | Texas 2015 Electric Rate Case | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Revised requested rate increase (decrease) | 58,900 | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties | $ (13,600) | |||||||||||||||
Public utilities, ROE recommended by third parties | 9.40% | |||||||||||||||
Public Utilities, Equity capital structure recommended by third parties | 53.97% | |||||||||||||||
Public Utilities, Post test year adjustment related to capital expenditures | $ (11,300) | |||||||||||||||
Public Utilities, ROE | (10,900) | |||||||||||||||
Rate base adjustments (largely the removal of the prepaid pension asset) | (6,200) | |||||||||||||||
Public Utilities, Operating and maintenance expenses | (13,700) | |||||||||||||||
Public Utilities, Depreciation expense | (13,300) | |||||||||||||||
Public Utilities, Property taxes | 0 | |||||||||||||||
Public Utilities, Revenue adjustments | (2,200) | |||||||||||||||
Public Utilities, Wholesale load reductions | (13,200) | |||||||||||||||
Public Utilities, SPP transmission expansion plan | 0 | |||||||||||||||
Public Utilities, Other net | (1,700) | |||||||||||||||
Public Utilities, Adjustment to move rate case expenses to separate docket | 0 | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties excluding rate case expenses | (13,600) | |||||||||||||||
SPS | Office of Public Utility Counsel [Member] | Texas 2015 Electric Rate Case | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Revised requested rate increase (decrease) | 58,900 | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties | $ 1,800 | |||||||||||||||
Public utilities, ROE recommended by third parties | 9.20% | |||||||||||||||
Public Utilities, Equity capital structure recommended by third parties | 52.38% | |||||||||||||||
Public Utilities, Post test year adjustment related to capital expenditures | $ (23,800) | |||||||||||||||
Public Utilities, ROE | (13,500) | |||||||||||||||
Rate base adjustments (largely the removal of the prepaid pension asset) | (6,800) | |||||||||||||||
Public Utilities, Operating and maintenance expenses | (11,000) | |||||||||||||||
Public Utilities, Depreciation expense | 0 | |||||||||||||||
Public Utilities, Property taxes | (1,200) | |||||||||||||||
Public Utilities, Revenue adjustments | (200) | |||||||||||||||
Public Utilities, Wholesale load reductions | 0 | |||||||||||||||
Public Utilities, SPP transmission expansion plan | 0 | |||||||||||||||
Public Utilities, Other net | (600) | |||||||||||||||
Public Utilities, Adjustment to move rate case expenses to separate docket | 0 | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties excluding rate case expenses | 1,800 | |||||||||||||||
SPS | Public Utility Commission of Texas Staff [Member] | Texas 2015 Electric Rate Case | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Revised requested rate increase (decrease) | $ 58,900 | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties | $ (2,600) | |||||||||||||||
Public utilities, ROE recommended by third parties | 9.30% | |||||||||||||||
Public Utilities, Equity capital structure recommended by third parties | 53.97% | |||||||||||||||
Public Utilities, Post test year adjustment related to capital expenditures | $ (23,800) | |||||||||||||||
Public Utilities, ROE | (12,100) | |||||||||||||||
Rate base adjustments (largely the removal of the prepaid pension asset) | 0 | |||||||||||||||
Public Utilities, Operating and maintenance expenses | (7,900) | |||||||||||||||
Public Utilities, Depreciation expense | 0 | |||||||||||||||
Public Utilities, Property taxes | (4,400) | |||||||||||||||
Public Utilities, Revenue adjustments | 0 | |||||||||||||||
Public Utilities, Wholesale load reductions | (11,100) | |||||||||||||||
Public Utilities, SPP transmission expansion plan | 0 | |||||||||||||||
Public Utilities, Other net | (2,200) | |||||||||||||||
Public Utilities, Adjustment to move rate case expenses to separate docket | 0 | |||||||||||||||
Public Utilities, Rate increase (decrease) recommended by third parties excluding rate case expenses | $ (2,600) | |||||||||||||||
SPS | FERC Staff [Member] | Wholesale Electric Rate Complaint, April 20, 2012 through July 18, 2013 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, First refund period | 1 | |||||||||||||||
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage | 8.97% | |||||||||||||||
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage | [1] | 9.47% | ||||||||||||||
SPS | FERC Staff [Member] | Wholesale Electric Rate Complaint, July 19, 2013 through Oct. 19, 2014 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage | 8.64% | |||||||||||||||
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage | [1] | 9.14% | ||||||||||||||
Public Utilities, Second refund period | 2 | |||||||||||||||
SPS | FERC Staff [Member] | Wholesale Electric Rate Complaint, Oct. 20, 2014 Impact | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage | 8.53% | |||||||||||||||
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage | [1] | 9.03% | ||||||||||||||
Public Utilities, Third refund period | 3 | |||||||||||||||
Minimum | SPS | Wholesale Electric Rate Complaints | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Increase (Decrease) of transmission and production revenues, net of expense due to potential ROE adjustments | $ (4,000) | |||||||||||||||
Maximum | SPS | Wholesale Electric Rate Complaints | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Increase (Decrease) of transmission and production revenues, net of expense due to potential ROE adjustments | $ (6,000) | |||||||||||||||
Subsequent Event | SPS | Wholesale Electric Rate Complaints, Refunds as of April 20, 2012 and July 19, 2013 | ||||||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||||||
Public Utilities, Number of rate complaints where appeal was filed with the D.C. Circuit Court of Appeals due to the FERC orders to allow back-to-back complaints for consecutive month refund periods | 2 | |||||||||||||||
Public Utilities, appeal of the number of months refund period | 15 months | |||||||||||||||
[1] | Includes a SPP RTO membership adder up to 50 basis points. | |||||||||||||||
[2] | In addition to the recommended ROEs, SPS also filed testimony recommending the ROEs remain unchanged. | |||||||||||||||
[3] | For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only). |
Commitments and Contingencies,
Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW | 3 Months Ended | 12 Months Ended |
Jun. 30, 2015 | Dec. 31, 2014 | |
Purchased Power Agreements [Abstract] | ||
Generating capacity (in MW) | 827 | 827 |
Purchase Power Agreement Duration, Maximum (year) | 2,033 | 2,033 |
Commitments and Contingencies35
Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions | 1 Months Ended | 6 Months Ended | |||
Dec. 31, 2014 | Apr. 30, 2012MW | Jun. 30, 2015USD ($)MW | Apr. 30, 2015USD ($) | Apr. 30, 2014Issue | |
Cross-State Air Pollution Rule | |||||
Environmental Requirements [Abstract] | |||||
Number of issues on which the D.C. Circuit overturned the CSAPR | Issue | 2 | ||||
Generating capacity (in MW) | MW | 700 | ||||
Electric Generating Unit Mercury and Air Toxics Standards Rule [Member] | |||||
Environmental Requirements [Abstract] | |||||
Generating capacity (in MW) | MW | 25 | ||||
Number of years before affected facilities must demonstrate compliance, low end of range | 3 years | ||||
Number of years before affected facilities must demonstrate compliance, high end of range | 4 years | ||||
Cost of capital incurred for installed mercury controls | $ 8 | ||||
Regional Haze Rules | |||||
Environmental Requirements [Abstract] | |||||
Number of years to comply with proposed regulation | 5 years | ||||
Implementation of the National Ambient Air Quality Standard for sulfur dioxide [Member] | |||||
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 | ||||
Number of units which sulfur dioxide controls could be required by the Texas Commission on Environmental Quality | 1 | ||||
Capital Addition Purchase Commitments | Cross-State Air Pollution Rule | |||||
Environmental Requirements [Abstract] | |||||
Liability for estimated cost to comply with regulation, Maximum | $ 7 | ||||
Capital Addition Purchase Commitments | Regional Haze Rules | |||||
Environmental Requirements [Abstract] | |||||
Liability for estimated cost to comply with regulation, Maximum | 600 | ||||
Estimated annual operating cost to comply with proposed regulation | $ 10.4 |
Borrowings and Other Financin36
Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Jun. 30, 2015 | Dec. 31, 2014 | |
Short-term Debt [Line Items] | ||
Amount outstanding at period end | $ 209,000 | $ 37,000 |
Money Pool | ||
Short-term Debt [Line Items] | ||
Borrowing limit | 100,000 | 100,000 |
Amount outstanding at period end | 0 | 16,000 |
Average amount outstanding | 4,000 | 9,000 |
Maximum amount outstanding | $ 36,000 | $ 100,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.52% | 0.22% |
Weighted average interest rate at period end (percentage) | 0.45% | |
Commercial Paper | ||
Short-term Debt [Line Items] | ||
Borrowing limit | $ 400,000 | $ 400,000 |
Amount outstanding at period end | 209,000 | 37,000 |
Average amount outstanding | 160,000 | 83,000 |
Maximum amount outstanding | $ 209,000 | $ 241,000 |
Weighted average interest rate, computed on a daily basis (percentage) | 0.48% | 0.26% |
Weighted average interest rate at period end (percentage) | 0.49% | 0.47% |
Borrowings and Other Financin37
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Dec. 31, 2014 | |
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 209,000 | $ 37,000 |
Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Amount outstanding at period end | $ 36,000 | $ 30,000 |
Letter of Credit | Letter of Credit | ||
Line of Credit Facility [Line Items] | ||
Term of letters of credit (in years) | 1 year |
Borrowings and Other Financin38
Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility | Jun. 30, 2015USD ($) | |
Line of Credit Facility [Line Items] | ||
Credit Facility | [1] | $ 400,000,000 |
Drawn | [2] | 245,000,000 |
Available | 155,000,000 | |
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. |
Fair Value of Financial Asset39
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions | Jun. 30, 2015USD ($)MWhCounterparty | Dec. 31, 2014MWh | |
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 | 8 | ||
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 | 1 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 9.6 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 9.00% | ||
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 | 6 | ||
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $ 58.5 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 54.00% | ||
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 | $ 1.3 | ||
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths) | 1.00% | ||
Interest Rate Swap | |||
Interest Rate Derivatives [Abstract] | |||
Amount of accumulated other comprehensive losses related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ (0.2) | ||
Electric Commodity (in megawatt hours) | |||
Gross Notional Amounts of Commodity FTRs [Abstract] | |||
Derivative, Nonmonetary Notional amount | MWh | [1] | 13,620 | 6,930 |
[1] | (a) Amounts are not reflective of net positions in the underlying commodities. |
Fair Value of Financial Asset40
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 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 |
Cash Flow Hedges | Interest Rate | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax losses reclassified into income during the period from accumulated other comprehensive loss | (100,000) | (100,000) | (100,000) | (100,000) |
Other Derivative Instruments | Electric Commodity | ||||
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract] | ||||
Pre-tax fair value losses recognized during the period in regulatory assets and liabilities | (1,200,000) | (1,000,000) | (2,000,000) | (2,400,000) |
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) | $ (1,700,000) | $ 1,900,000 | $ (1,600,000) | $ (900,000) |
Fair Value of Financial Asset41
Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) - USD ($) | Jun. 30, 2015 | Dec. 31, 2014 | ||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Collateral, Obligation to Return Cash, Offset | $ 0 | $ 0 | ||
Derivative Liability, Collateral, Right to Reclaim Cash, Offset | 0 | 0 | ||
Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 19,355,000 | 23,776,000 | ||
Other Noncurrent Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 29,218,000 | 33,164,000 | ||
Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 3,565,000 | 3,565,000 | ||
Other Noncurrent Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 28,860,000 | 30,643,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 11,463,000 | 15,884,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 11,463,000 | 15,884,000 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric 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 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 | Electric 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 | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 0 | 0 | ||
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric 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 Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 21,533,000 | 25,774,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 21,533,000 | 25,774,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 10,070,000 | 9,890,000 | ||
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 10,070,000 | 9,890,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 21,533,000 | 25,774,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 21,533,000 | 25,774,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 10,070,000 | 9,890,000 | ||
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 10,070,000 | 9,890,000 | ||
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | (10,070,000) | [1] | (9,890,000) | [2] |
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | (10,070,000) | [1] | (9,890,000) | [2] |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | (10,070,000) | [1] | (9,890,000) | [2] |
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | (10,070,000) | [1] | (9,890,000) | [2] |
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 7,892,000 | [3] | 7,892,000 | [4] |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Asset, Fair Value, Gross Asset | 29,218,000 | [3] | 33,164,000 | [4] |
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | 3,565,000 | [3] | 3,565,000 | [4] |
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements | ||||
Derivatives, Fair Value [Line Items] | ||||
Derivative Liability, Fair Value, Gross Liability | $ 28,860,000 | [3] | $ 30,643,000 | [4] |
[1] | SPS nets derivative instruments and related collateral in its 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 June 30, 2015. At June 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] | SPS nets derivative instruments and related collateral in its 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 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. | |||
[3] | In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS 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 in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS 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, SPS 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 in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS 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 Asset42
Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward] | ||||
Balance at beginning of period | $ 6,457,000 | $ 5,791,000 | $ 15,884,000 | $ 9,933,000 |
Purchases | 17,284,000 | 38,419,000 | 22,213,000 | 39,475,000 |
Settlements | (10,022,000) | (13,554,000) | (18,400,000) | (14,655,000) |
Losses recognized as regulatory assets and liabilities | (2,256,000) | 3,286,000 | (8,234,000) | (811,000) |
Balance at end of period | 11,463,000 | 33,942,000 | 11,463,000 | 33,942,000 |
Transfers into Level 3 | 0 | 0 | 0 | 0 |
Transfers out of Level 3 | $ 0 | $ 0 | $ 0 | $ 0 |
Fair Value of Financial Asset43
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Carrying Amount | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 1,349,858 | $ 1,349,691 |
Fair Value | ||
Financial Liabilities, Balance Sheet Groupings [Abstract] | ||
Long-term debt, including current portion | $ 1,491,780 | $ 1,572,414 |
Other Income (Expense), Net (De
Other Income (Expense), Net (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Other Income and Expenses [Abstract] | ||||
Interest income | $ 13 | $ 53 | $ 45 | $ 240 |
Other nonoperating income | 65 | 2 | 110 | 0 |
Insurance policy income (expense) | 78 | (184) | (55) | (328) |
Other income (expense), net | $ 156 | $ (129) | $ 100 | $ (88) |
Benefit Plans and Other Postr45
Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||
Jan. 31, 2015USD ($)Plan | Jun. 30, 2015USD ($) | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($) | Jun. 30, 2014USD ($) | |
Pension Benefits | |||||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | $ 2,751 | $ 2,296 | $ 5,503 | $ 4,592 | |
Interest cost | 5,046 | 5,111 | 10,092 | 10,222 | |
Expected return on plan assets | (7,152) | (6,545) | (14,305) | (13,090) | |
Amortization of prior service cost (credit) | 10 | 13 | 20 | 27 | |
Amortization of net loss (gain) | 3,772 | 3,331 | 7,544 | 6,663 | |
Net periodic benefit cost (credit) | 4,427 | 4,206 | 8,854 | 8,414 | |
Credits recognized (costs not recognized) due to the effects of regulation | 686 | 708 | 1,399 | 1,415 | |
Net benefit cost (credit) recognized for financial reporting | 5,113 | 4,914 | 10,253 | 9,829 | |
Total contributions to the pension plans during the period | $ 11,600 | ||||
Postretirement Health Care Benefits | |||||
Components of Net Periodic Benefit Cost (Credit) [Abstract] | |||||
Service cost | 238 | 311 | 477 | 623 | |
Interest cost | 437 | 643 | 873 | 1,286 | |
Expected return on plan assets | (635) | (811) | (1,270) | (1,623) | |
Amortization of prior service cost (credit) | (100) | (101) | (200) | (201) | |
Amortization of net loss (gain) | (160) | (81) | (320) | (161) | |
Net periodic benefit cost (credit) | (220) | (39) | (440) | (76) | |
Credits recognized (costs not recognized) due to the effects of regulation | 0 | 0 | 0 | 0 | |
Net benefit cost (credit) recognized for financial reporting | $ (220) | $ (39) | $ (440) | $ (76) | |
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 | 6 Months Ended | |||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward] | |||||
Accumulated other comprehensive loss at beginning of period | $ (989) | ||||
Accumulated other comprehensive loss at end of period | $ (904) | (904) | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||||
Total, pre-tax | (35,139) | $ (43,842) | (66,724) | $ (72,945) | |
Tax benefit | 12,563 | 15,807 | 23,901 | 26,175 | |
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 | (947) | (1,118) | (989) | (1,161) | |
Losses reclassified from net accumulated other comprehensive loss | 43 | 42 | 85 | 85 | |
Net current period other comprehensive income | 43 | 42 | 85 | 85 | |
Accumulated other comprehensive loss at end of period | (904) | (1,076) | (904) | (1,076) | |
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 | 67 | 66 | 133 | 133 | |
Tax benefit | (24) | (24) | (48) | (48) | |
Total, net of tax | 43 | 42 | 85 | 85 | |
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] | $ 67 | $ 66 | $ 133 | $ 133 |
[1] | Included in interest charges. |