10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended Sept. 30, 2017

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-03789

Southwestern Public Service Company

(Exact name of registrant as specified in its charter)

New Mexico	75-0575400
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
790 South Buchanan Street
Amarillo, Texas	79101
(Address of principal executive offices)	(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller reporting company ¨
(Do not check if smaller reporting company)	Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at Oct. 27, 2017
Common Stock, $1 par value	100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l     —	Financial Statements (Unaudited)	3
Item 2    —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 4    —	Controls and Procedures	24
PART II — OTHER INFORMATION
Item 1     —	Legal Proceedings	25
Item 1A  —	Risk Factors	25
Item 6    —	Exhibits	26
SIGNATURES		27
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and SPS.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
	2017			2016			2017			2016
Operating revenues	$	551,623		$	554,926		$	1,491,491		$	1,386,210
Operating expenses
Electric fuel and purchased power	294,400			297,587			816,027			757,537
Operating and maintenance expenses	66,289			71,699			213,348			202,410
Demand side management expenses	4,236			5,663			11,802			12,279
Depreciation and amortization	47,548			42,026			144,781			123,250
Taxes (other than income taxes)	16,743			15,589			50,222			46,417
Total operating expenses	429,216			432,564			1,236,180			1,141,893
Operating income	122,407			122,362			255,311			244,317
Other income, net	285			137			452			563
Allowance for funds used during construction — equity	2,453			2,632			6,457			7,348
Interest charges and financing costs
Interest charges — includes other financing costs of $625, $828, $1,781, and $2,461, respectively	21,444			23,343			66,128			67,350
Allowance for funds used during construction — debt	(1,349		)	(1,422		)	(3,816		)	(4,146		)
Total interest charges and financing costs	20,095			21,921			62,312			63,204
Income before income taxes	105,050			103,210			199,908			189,024
Income taxes	37,269			34,864			71,710			65,944
Net income	$	67,781		$	68,346		$	128,198		$	123,080

See Notes to Financial Statements

3

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
	2017		2016		2017		2016
Net income	$	67,781	$	68,346	$	128,198	$	123,080
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $9, $6, $27 and $19, respectively	16		12		46		35
Derivative instruments:
Reclassification of losses to net income, net of tax of $6, $25, $18 and $74, respectively	10		44		29		129
Other comprehensive income	26		56		75		164
Comprehensive income	$	67,807	$	68,402	$	128,273	$	123,244

See Notes to Financial Statements

4

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Nine Months Ended Sept. 30
	2017			2016
Operating activities
Net income	$	128,198		$	123,080
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	144,664			123,820
Demand side management program amortization	1,255			1,255
Deferred income taxes	101,388			99,882
Amortization of investment tax credits	(99		)	(160		)
Allowance for equity funds used during construction	(6,457		)	(7,348		)
Net derivative losses	47			203
Other	9			122
Changes in operating assets and liabilities:
Accounts receivable	(25,134		)	(22,160		)
Accrued unbilled revenues	(13,682		)	(18,307		)
Inventories	(2,845		)	(1,491		)
Prepayments and other	19,361			24,172
Accounts payable	7,817			19,690
Net regulatory assets and liabilities	24,856			(18,480		)
Other current liabilities	19,748			18,989
Pension and other employee benefit obligations	(21,638		)	(15,606		)
Change in other noncurrent assets	(1,697		)	(537		)
Change in other noncurrent liabilities	(18,690		)	3,916
Net cash provided by operating activities	357,101			331,040
Investing activities
Utility capital/construction expenditures	(400,957		)	(371,994		)
Proceeds from insurance recoveries	—			987
Allowance for equity funds used during construction	6,457			7,348
Investments in utility money pool arrangement	—			(75,000		)
Repayments from utility money pool arrangement	—			75,000
Other	(493		)	(1,174		)
Net cash used in investing activities	(394,993		)	(364,833		)
Financing activities
Proceeds from short-term borrowings, net	(50,000		)	(15,000		)
Proceeds from issuance of long-term debt, net	442,651			296,152
Borrowings under utility money pool arrangement	323,000			505,000
Repayments under utility money pool arrangement	(323,000		)	(505,000		)
Capital contributions from parent	45,000			16,225
Repayment of long-term debt, including reacquisition premiums	(271,613		)	—
Dividends paid to parent	(82,599		)	(57,570		)
Net cash provided by financing activities	83,439			239,807
Net change in cash and cash equivalents	45,547			206,014
Cash and cash equivalents at beginning of period	844			834
Cash and cash equivalents at end of period	$	46,391		$	206,848
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(58,581	)	$	(47,787	)
Cash received for income taxes, net	37,899			49,402
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	40,861		$	25,445

See Notes to Financial Statements

5

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	Sept. 30, 2017			Dec. 31, 2016
Assets
Current assets
Cash and cash equivalents	$	46,391		$	844
Accounts receivable, net	96,614			74,190
Accounts receivable from affiliates	3,737			949
Accrued unbilled revenues	133,100			119,418
Inventories	41,350			38,505
Regulatory assets	38,021			38,721
Derivative instruments	23,597			5,114
Prepaid taxes	3,233			21,779
Prepayments and other	7,040			7,855
Total current assets	393,083			307,375
Property, plant and equipment, net	4,947,114			4,695,819
Other assets
Regulatory assets	343,685			346,683
Derivative instruments	19,743			22,113
Other	12,193			7,477
Total other assets	375,621			376,273
Total assets	$	5,715,818		$	5,379,467
Liabilities and Equity
Current liabilities
Short-term debt	$	—		$	50,000
Accounts payable	183,437			176,157
Accounts payable to affiliates	11,935			14,414
Regulatory liabilities	70,355			41,577
Taxes accrued	56,386			39,742
Accrued interest	21,430			19,162
Dividends payable	26,166			30,870
Derivative instruments	3,565			3,565
Other	27,723			29,703
Total current liabilities	400,997			405,190
Deferred credits and other liabilities
Deferred income taxes	1,090,921			989,137
Regulatory liabilities	222,956			233,454
Asset retirement obligations	29,808			28,663
Derivative instruments	20,840			23,513
Pension and employee benefit obligations	86,291			107,872
Other	8,307			24,084
Total deferred credits and other liabilities	1,459,123			1,406,723
Commitments and contingencies
Capitalization
Long-term debt	1,829,965			1,635,858
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively	—			—
Additional paid in capital	1,489,882			1,446,223
Retained earnings	537,066			486,763
Accumulated other comprehensive loss	(1,215		)	(1,290		)
Total common stockholder’s equity	2,025,733			1,931,696
Total liabilities and equity	$	5,715,818		$	5,379,467

See Notes to Financial Statements

6

SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

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 Sept. 30, 2017 and Dec. 31, 2016; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2017 and 2016; and its cash flows for the nine months endedSept. 30, 2017 and 2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2017 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, 2016 balance sheet information has been derived from the audited 2016 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2016. 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, 2016, filed with the SEC on Feb. 24, 2017. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.

1. 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, 2016, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. 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 new framework for the recognition of revenue. SPS expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. SPS currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. SPS expects that the overall impacts of the Jan. 1, 2018 adoption will not be material.

Leases —In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. SPS has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. SPS expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the new standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.

7

Presentation of Net Periodic Benefit Cost —In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. SPS expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment and that the impacts of adoption will be limited to changes in classification of non-service costs in the statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$	103,704		$	80,569
Less allowance for bad debts	(7,090		)	(6,379		)
	$	96,614		$	74,190

(Thousands of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Inventories
Materials and supplies	$	26,877	$	25,453
Fuel	14,473		13,052
	$	41,350	$	38,505

(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Property, plant and equipment, net
Electric plant	$	6,653,228		$	6,362,189
Construction work in progress	312,445			260,327
Total property, plant and equipment	6,965,673			6,622,516
Less accumulated depreciation	(2,018,559		)	(1,926,697		)
	$	4,947,114		$	4,695,819

4. 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, 2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audits — 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 through 2011 and 2012 through 2013 federal income tax returns, following extensions, expires in June 2018 and October 2018, respectively.

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. SPS did not accrue any income tax benefit related to this adjustment.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Sept. 30, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

8

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2017, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In 2016, Texas began an audit of years 2009 and 2010, and in September 2017, began an audit of 2011. As of Sept. 30, 2017, Texas had not proposed any material adjustments and there were no other state income tax audits in progress.

Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions	$	5.2	$	4.5
Unrecognized tax benefit — Temporary tax positions	5.1		24.2
Total unrecognized tax benefit	$	10.3	$	28.7

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
NOL and tax credit carryforwards	$	(5.8	)	$	(5.9	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audits resume, the Texas audit progresses, and other state audits resume. As the IRS Appeals and Texas audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $7 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period	$	(0.9	)	$	—
Interest expense related to unrecognized tax benefits recorded during the period	—			(0.9		)
Payable for interest related to unrecognized tax benefits at end of period	$	(0.9	)	$	(0.9	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2017 or Dec. 31, 2016.

5. 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, 2016 and in Note 5 to SPS’ Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, 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)

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. In March 2017, the Travis County District Court denied SPS’ appeal.  In April 2017, SPS appealed the District Court’s decision to the Court of Appeals.

9

Texas 2017 Electric Rate Case — In August 2017, SPS filed a $66.4 million, or 7.1 percent, retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on the 12-month period ended June 30, 2017, with the final three months based on estimates, a requested return on equity (ROE) of 10.25 percent, a Texas retail electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

In October 2017, SPS revised its request to $54.6 million, or 5.8 percent, which reflects updated actual results. In addition, approximately $4.4 million of rate case expenses was bifurcated into a separate docket.

The following table summarizes SPS’ revised rate increase request:

Revenue Request (Millions of Dollars)
Incremental revenue request	$	69.2
Transmission Cost Recovery Factor (TCRF) revenue conversion to base rates (a)	(14.6		)
Net revenue increase request	$	54.6

^(a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

Key dates in the procedural schedule are as follows:

• Intervenors’ direct testimony — Feb. 22, 2018;

• PUCT Staff direct testimony — March 1, 2018;

• PUCT Staff and intervenors’ cross-rebuttal testimony — March 22, 2018;

• SPS’ rebuttal testimony — March 23, 2018;

• Hearings — April 10 - 20, 2018; and

• Statutory deadline — Aug. 31, 2018.

The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the third quarter of 2018.

Pending Regulatory Proceeding — New Mexico Public Regulation Commission (NMPRC)

New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing was based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a future test year ending June 30, 2018.

In April 2017, the NMPRC dismissed SPS’ rate case. In May 2017, SPS filed a notice of appeal to the New Mexico Supreme Court. A decision from the New Mexico Supreme Court is not expected until the second or third quarter of 2018.

SPS plans to file another base rate case by November 2017 utilizing a historic test year ending June 2017.

Pending Regulatory Proceeding — Federal Energy Regulatory Commission (FERC)

Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades.  In July 2016, the FERC granted SPP’s request for a waiver to allow SPP to recover the charges not billed since 2008.  In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges, to be paid over a five-year period commencing November 2016. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. On the retail level, in October 2016, SPS filed applications for deferred accounting and future recovery of related costs in New Mexico and Texas.  In December 2016, SPS’ New Mexico application was consolidated with its base rate case, but the NMPRC dismissed that rate case in April 2017. SPS will seek recovery of these SPP charges in its next New Mexico base rate case by November 2017. In March 2017, SPS withdrew its Texas application and is now seeking to recover these SPP charges in its pending rate case filed in August 2017.

10

In October 2017, SPS filed a complaint against SPP regarding the amounts billed on and after November 2016 asserting that SPP has assessed upgrade charges to SPS even where SPS’ transmission service was not dependent upon the upgrade as required by the SPP OATT.  If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings. Also in October 2017, SPP made adjustments to its previous calculations of upgrade charges to SPP customers, and the impact was immaterial to SPS.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10 and 11 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2016, and in Notes 5 and 6 to the financial statements included in SPS’ Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, 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.

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 897 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2017 and Dec. 31, 2016, 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 2041.

Environmental Contingencies

Environmental Requirements

Water and Waste

Federal Clean Water Act (CWA) Waters of the United States Rule —In 2015, the Environmental Protection Agency (EPA) and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in the first quarter of 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

Federal CWA Effluent Limitations Guidelines (ELG) —In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In September 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport water until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

Air

Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, the EPA issued its final rule for existing power plants.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. 

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The CPP was challenged by multiple parties in the D.C. Circuit Court.  In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the Clean Air Act (CAA). The EPA will take public comment on the proposal for 60 days. The EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing electric generating units.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The Best Available Retrofit Technology (BART) requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce Sulfur Dioxide (SO₂), Nitrogen Oxide (NOx) and particulate matter emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR). Texas’ first regional haze plan has undergone federal review as described below.

BART Determinations for Texas: Texas developed a State Implementation Plan (SIP) that found the CAIR equal to BART for electric generating units. As a result, no additional controls beyond CAIR compliance would have been required. In 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that deferred its approval of CSAPR compliance as BART until the EPA considered further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO₂ emission budgets. The EPA then published a proposed rule in January 2017 that could have had the effect of requiring installation of dry scrubbers to reduce SO₂ emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could have been approximately $400 million. In September 2017, the EPA issued a final rule adopting a Texas only SO₂ trading program as a BART Alternative. The program allocated SO₂ allowances to electric generating units in Texas, including all three Harrington units and both Tolk units, consistent with their allocation under CSAPR, resulting in an emissions budget for Texas that is consistent with the EPA’s 2012 rule. SPS expects the allowance allocations to be sufficient for SO₂ emissions from Harrington and Tolk units in 2019 and future years. The anticipated costs of compliance are not expected to have a material impact on the results of operations, financial position or cash flows; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

Reasonable Progress Rule: In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO₂ emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. SPS appealed the EPA’s decision and requested a stay of the final rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the case in abeyance until the EPA completes its reconsideration of the rule. In the final BART rule that affects Tolk and Harrington described above, the EPA noted that it will address the remanded rule in a future action. Such a rule will address whether further SO₂ emission reductions are needed at Tolk to address the “reasonable progress” requirements of the regional haze program. The risk of these controls being imposed along with the risk of investments to provide additional cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units.

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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.

7. 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 Sept. 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	37			28
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	1.10		%	0.67		%
Weighted average interest rate at period end	N/A			N/A

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	400		$	400
Amount outstanding at period end	—			50
Average amount outstanding	36			43
Maximum amount outstanding	106			140
Weighted average interest rate, computed on a daily basis	1.37		%	0.67		%
Weighted average interest rate at period end	N/A			0.95

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. As of Sept. 30, 2017 and Dec. 31, 2016, there were $2 million and $5 million, respectively, of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, 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.

As of Sept. 30, 2017, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	3	$	397

^(a)  This credit facility expires in June 2021.

^(b)  Includes outstanding commercial paper and letters of credit.

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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 as of Sept. 30, 2017 and Dec. 31, 2016.

Long-Term Borrowings

In August 2017, SPS issued $450 million of 3.70 percent first mortgage bonds due Aug. 15, 2047.

Debt Redemption

On Aug. 30, 2017, SPS reacquired $250 million of debt with a coupon rate of 8.75 percent and an original maturity date of Dec. 1, 2018. The redemption resulted in payment of an early redemption premium of $21.6 million which was deferred as a regulatory asset.

8. 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 value (NAV).

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 classification. 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, generally referred to as financial transmission rights (FTRs), purchased from Southwest Power Pool Inc. (SPP). FTRs purchased from a regional transmission organization (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 transmission congestion. 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 the cleared prices for each FTR for the most recent auction.

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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 transparency in the auction process, 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, the limited transparency associated with the 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.

As of Sept. 30, 2017, accumulated other comprehensive losses related to interest rate derivatives included an immaterial amount 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, including derivatives. 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. 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 as of Sept. 30, 2017 and Dec. 31, 2016:

(Amounts in Thousands) (a)	Sept. 30, 2017	Dec. 31, 2016
Megawatt hours of electricity	6,183	2,685

^(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 immaterial for the three and nine months ended Sept. 30, 2017 and $0.1 million and $0.2 million for the three and nine months ended Sept. 30, 2016.

During the three and nine months ended Sept. 30, 2017, changes in the fair value of FTRs resulted in pre-tax net losses of $2.5 million and $0.2 million, respectively, and were recognized as regulatory assets and liabilities. For the three and nine months ended Sept. 30, 2016, changes in the fair value of FTRs resulted in pre-tax net gains of $0.2 million and $2.0 million, respectively, and were 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 losses of $2.2 million and gains of $0.1 million were recognized for the three and nine months ended Sept. 30, 2017, recorded to electric fuel and purchased power. For the three and nine months ended Sept. 30, 2016, FTR settlement losses of $0.4 million and $3.7 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 nine months ended Sept. 30, 2017 and 2016. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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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 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 activities. As of Sept. 30, 2017, two of SPS’ most significant counterparties for these activities, comprising $15.3 million or 33 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the most significant counterparties, comprising $9.2 million or 20 percent of this credit exposure, were not rated by Standard & Poor’s, Moody’s or Fitch Ratings, but based on SPS’ internal analysis, had credit quality consistent with investment grade. The one remaining significant counterparty, comprising $0.2 million or less than 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 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 as of Sept. 30, 2017:

	Sept. 30, 2017
	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	$	—	$	—	$	23,018	$	23,018	$	(2,580	)	$	20,438
Total current derivative assets	$	—	$	—	$	23,018	$	23,018	$	(2,580	)	20,438
PPAs (a)												3,159
Current derivative instruments												$	23,597
Noncurrent derivative assets
PPAs (a)												$	19,743
Noncurrent derivative instruments												$	19,743
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,580	$	2,580	$	(2,580	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,580	$	2,580	$	(2,580	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	20,840
Noncurrent derivative instruments												$	20,840

^(a) 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 Sept. 30, 2017. At Sept. 30, 2017, 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.

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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 as of Dec. 31, 2016:

	Dec. 31, 2016
	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	$	—	$	—	$	3,254	$	3,254	$	(1,299	)	$	1,955
Total current derivative assets	$	—	$	—	$	3,254	$	3,254	$	(1,299	)	1,955
PPAs (a)												3,159
Current derivative instruments												$	5,114
Noncurrent derivative assets
PPAs (a)												$	22,113
Noncurrent derivative instruments												$	22,113
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,299	$	1,299	$	(1,299	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,299	$	1,299	$	(1,299	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	23,513
Noncurrent derivative instruments												$	23,513

^(a)  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, 2016. At Dec. 31, 2016, 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 nine months ended Sept. 30, 2017 and 2016:

	Three Months Ended Sept. 30
(Thousands of Dollars)	2017			2016
Balance at July 1	$	28,665		$	1,070
Purchases	43			274
Settlements	(9,939		)	(7,822		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	1,669			6,614
Balance at Sept. 30	$	20,438		$	136

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2017			2016
Balance at Jan. 1	$	1,955		$	5,060
Purchases	39,376			5,426
Settlements	(40,437		)	(22,438		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	19,544			12,088
Balance at Sept. 30	$	20,438		$	136

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 nine months ended Sept. 30, 2017 and 2016.

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Fair Value of Long-Term Debt

As of Sept. 30, 2017 and Dec. 31, 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2017				Dec. 31, 2016
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,829,965	$	1,954,618	$	1,635,858	$	1,741,502

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 Sept. 30, 2017 and Dec. 31, 2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

9. Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2017			2016			2017			2016
Interest income	$	296		$	400		$	488		$	579
Other nonoperating income	1			—			—			16
Insurance policy expense	(12		)	(32		)	(36		)	(32		)
Other nonoperating expense	—			(231		)	—			—
Other income, net	$	285		$	137		$	452		$	563

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,439		$	2,440		$	219		$	194
Interest cost	4,928			5,315			415			455
Expected return on plan assets	(6,971		)	(6,901		)	(589		)	(594		)
Amortization of prior service credit	—			—			(100		)	(100		)
Amortization of net loss (gain)	3,245			2,997			(155		)	(146		)
Net periodic benefit cost (credit)	3,641			3,851			(210		)	(191		)
Credits not recognized due to the effects of regulation	553			637			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,194		$	4,488		$	(210	)	$	(191	)

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	Nine Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,319		$	7,320		$	657		$	582
Interest cost	14,783			15,945			1,245			1,365
Expected return on plan assets	(20,913		)	(20,703		)	(1,767		)	(1,782		)
Amortization of prior service credit	—			—			(300		)	(300		)
Amortization of net loss (gain)	9,735			8,991			(465		)	(438		)
Net periodic benefit cost (credit)	10,924			11,553			(630		)	(573		)
Credits not recognized due to the effects of regulation	1,275			1,353			—			—
Net benefit cost (credit) recognized for financial reporting	$	12,199		$	12,906		$	(630	)	$	(573	)

In January 2017, contributions of $150.0 million were made across four of Xcel Energy’s pension plans, of which $23.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2017.

11. Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:

	Three Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(659	)	$	(582	)	$	(1,241	)
Losses reclassified from net accumulated other comprehensive loss	10			16			26
Net current period other comprehensive income	10			16			26
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)

	Three Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(732	)	$	(441	)	$	(1,173	)
Other comprehensive income before reclassifications	—			12			12
Losses reclassified from net accumulated other comprehensive loss	44			—			44
Net current period other comprehensive income	44			12			56
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)

	Nine Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(678	)	$	(612	)	$	(1,290	)
Losses reclassified from net accumulated other comprehensive loss	29			46			75
Net current period other comprehensive income	29			46			75
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)

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	Nine Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(817	)	$	(464	)	$	(1,281	)
Other comprehensive income before reclassifications	—			35			35
Losses reclassified from net accumulated other comprehensive loss	129			—			129
Net current period other comprehensive income	129			35			164
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2017				Three Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	16		(a)	$	69		(a)
Total, pre-tax	16				69
Tax benefit	(6		)		(25		)
Total, net of tax	10				44
Defined benefit pension and postretirement losses:
Amortization of net loss	24			(b)	—			(b)
Total, pre-tax	24				—
Tax benefit	(8		)		—
Total, net of tax	16				—
Total amounts reclassified, net of tax	$	26			$	44

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2017				Nine Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	47		(a)	$	203		(a)
Total, pre-tax	47				203
Tax benefit	(18		)		(74		)
Total, net of tax	29				129
Defined benefit pension and postretirement losses:
Amortization of net loss	72			(b)	—			(b)
Total, pre-tax	72				—
Tax benefit	(26		)		—
Total, net of tax	46				—
Total amounts reclassified, net of tax	$	75			$	129

^(a)  Included in interest charges.

^(b)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 10 for details regarding these benefit plans.

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

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Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on SPS’ financial condition, results of operations, and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and the related notes to the financial statements.  Due to the seasonality of SPS’ electric sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including SPS’ Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2016 and subsequent securities filings, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Results of Operations

SPS’ net income was approximately $128.2 million for 2017 year-to-date, compared with approximately $123.1 million for the same period in 2016. The year-to-date increase in electric margin was attributable to rate increases in Texas and New Mexico, partially offset by the impact of unfavorable weather. This increase was largely offset by higher depreciation expense and timing of O&M expenses.

Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Changes in fuel or purchased power costs can impact earnings as the fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses. The following tables detail the electric revenues and margin:

	Nine Months Ended Sept. 30
(Millions of Dollars)	2017			2016
Electric revenues	$	1,491		$	1,386
Electric fuel and purchased power	(816		)	(758		)
Electric margin	$	675		$	628

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The following tables summarize the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30, 2017:

Electric Revenues

(Millions of Dollars)	2017 vs 2016
Retail rate increases (Texas, New Mexico)	$	53
Fuel and purchased power cost recovery	30
Wholesale transmission revenue	14
Demand revenue	9
Other, net	(1		)
Total increase in electric revenues	$	105

Electric Margin

(Millions of Dollars)	2017 vs 2016
Retail rate increases (Texas, New Mexico)	$	53
Demand revenue	9
Renewable energy credits	5
Wholesale transmission revenue, net of costs	(10		)
Fuel handling	(4		)
Other, net	(6		)
Total increase in electric margin	$	47

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $10.9 million, or 5.4 percent, for 2017 year-to-date. The increase primarily relates to prior year deferrals associated with the Texas 2016 rate case, increases in employee benefits expense, and the timing of planned maintenance and overhauls at various generation facilities, as summarized in the table below:

(Millions of Dollars)	2017 vs 2016
Texas 2016 electric rate case cost deferral	$	8.0
Employee benefits expense	2.0
Electric distribution costs	2.0
Plant generation costs	(2.0		)
Other, net	1.0
Total increase in O&M expenses	$	11.0

Depreciation and Amortization — Depreciation and amortization increased $21.5 million, or 17.5 percent, for 2017 year-to-date. The increase was primarily attributable to transmission and distribution capital investments.

Income Taxes — Income tax expense increased $5.8 million, for 2017 year-to-date. The increase in income tax expense was primarily due to higher pretax earnings and decreased tax benefit for adjustments attributable to the tax return filed in the third quarter. The ETR was 35.9 percent for 2017 year-to-date, compared with 34.9 percent for the same period in 2016. The higher ETR in 2017 was primarily due to the adjustment referenced above.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1 of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2016 and Public Utility Regulation included in Item 2 of SPS’ Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

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Wind Development — Xcel Energy plans to significantly expand its wind capacity by adding 1,230 MW of new wind generation at SPS by the end of 2020. SPS has filed to own and place in rate base 1,000 MW of these wind projects, while 230 MW would be through PPAs. The PUCT and NMPRC are expected to rule on SPS’ wind projects by the end of the first quarter of 2018. Hearings in Texas with the PUCT are scheduled for Nov. 6 through Nov. 17, 2017. Hearings in New Mexico with the NMPRC are scheduled for Nov. 28 through Dec. 1, 2017.

If approved by the PUCT and the NMPRC, these wind projects would qualify for 100 percent of the production tax credit and are expected to provide billions of dollars of savings to SPS’ customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with various commission approved resource plans.

The following table details these wind projects:

Project Name	Capacity (MW)	State	Estimated Year of Completion	Ownership/PPA
Hale	478	TX	2019	SPS
Sagamore	522	NM	2020	SPS
Total Ownership	1,000
Bonita	230	TX	2019	PPA
Total PPA	230
Total Wind Capacity	1,230

TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 Kilovolt (KV) Transmission Line— In March 2016, the PUCT approved SPS’ Certificate of Convenience and Necessity (CCN) for the 27-mile Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. A CCN for the 106-mile TUCO to Yoakum County substation segment was approved by the PUCT in September 2017 and is scheduled to be in service in the second quarter of 2020. A 36-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment was filed in June 2017. Assuming approval of this CCN, the Yoakum County to Hobbs Plant segment is scheduled to be in service in summer of 2019. The estimated project cost for all three segments is approximately $239 million.

The TUCO Substation to Yoakum County Substation to Hobbs Plant Substation transmission line is part of a larger project which includes a 345 KV transmission line from the Hobbs Plant to the China Draw Substation. The Hobbs Plant to China Draw Substation portion of this project was approved by the NMPRC in November 2016 and has an estimated cost of $163 million.  The total investment for the two transmission lines is approximately $402 million.  The Hobbs Plant to China Draw Substation transmission line is under construction and is anticipated to be in service by June 1, 2018.

Wholesale Customer Participation in Electric Reliability Council of Texas (ERCOT) — In March 2016, the PUCT Staff requested comments on Lubbock Power & Light’s (LP&L’s) proposal to transition a portion of its load (approximately 430 MW on a peak basis) to the ERCOT in June 2019. LP&L’s proposal would result in an approximate seven percent reduction of load in SPS, or a loss of approximately $18 million in wholesale transmission revenue.  The remaining portion of LP&L’s load (approximately 170 MW) would continue to be served by SPS. Should LP&L join ERCOT, costs to SPS’ remaining customers would increase as SPS’ transmission costs would be spread across a smaller base of customers. 

The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. The PUCT asked SPP and ERCOT to perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPP and ERCOT filed the studies on June 30, 2017. In September 2017, LP&L filed its application with the PUCT for a public interest determination and proposed a transition date no later than June 2021. The PUCT issued a preliminary order setting out issues for the parties to address. A hearing on the matter is expected to be held in the first quarter of 2018 and a PUCT decision is expected in the second quarter of 2018.

No final decision regarding LP&L’s departure or its potential timing is expected until completion of the PUCT proceedings.

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Summary of Recent Federal Regulatory Developments

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2016 and Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

Department of Energy (DOE) Grid Resiliency Notice of Proposed Rule (NOPR) — In September 2017, the DOE requested the FERC consider and adopt a Grid Resiliency and Pricing Rule to address threats to the U.S. electrical grid. The proposed DOE rule expands upon an August 2017 DOE grid study on the resiliency of the grid. Under the proposed rule, coal and nuclear generation facilities would qualify for full recovery of their costs, which includes a fair rate of return, if they meet the following criteria:

• Are located within a FERC-approved organized wholesale market operated by an RTO or Independent System Operator;

• Have 90 days of on-site fuel storage;

• Provide essential energy and ancillary reliability services to the grid;

• Are in compliance with all environmental mandates; and

• Are not subject to cost-of-service regulation by any state or local authority.

If implemented as written, the coal generation owned by SPS is not expected to be eligible for wholesale cost recovery from SPP because the generation is subject to state cost-of-service regulation. This rule could impact utilities in SPP subject to cost-of-service regulation if they have to compensate other generation facilities who qualify for full recovery of their costs under the rule. Xcel Energy is evaluating the DOE proposal and plans to engage in the FERC stakeholder process. The FERC has indicated that they plan to take action within 60 days, as requested by the DOE. It is unclear how the FERC will respond to the DOE’s NOPR.

North American Electric Reliability Corporation (NERC) Supply Chain Standards — In September 2017, NERC filed supply chain cyber security reliability standards with the FERC. These standards consider the FERC’s directives to address supply chain cyber security risk management for industrial control system hardware, software, computing and network services associated with electric grid operations. The proposed reliability standards focus on security objectives including software integrity and authenticity, vendor remote access protections, information system planning and vendor risk management. It is uncertain when the FERC will take action to approve or remand the proposed reliability standards. If approved by the FERC, the proposed reliability standards will become effective on the first calendar quarter that is 18 months after the effective date of the approval. SPS is in the process of developing plans in accordance with the requirements of the standards. The additional cost for compliance is anticipated to be recoverable through wholesale and retail rates.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Sept. 30, 2017, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

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Internal Control Over Financial Reporting

In 2016, SPS implemented the general ledger modules of a new enterprise resource planning system to improve certain financial and related transaction processes. SPS initiated deployment of work management systems modules and is continuing to implement additional modules including the conversion of existing work management systems to this same system during 2017. In connection with this ongoing implementation, SPS is updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting systems. SPS does not believe that this implementation will have an adverse effect on its internal control over financial reporting.

No changes in SPS’ internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, SPS’ internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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.

Additional Information

See Note 6 to the financial statements for further discussion of legal claims and environmental proceedings.  See Part I Item 2 and Note 5 to the financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

SPS’ risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2016, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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Item 6 — EXHIBITS

*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

3.01	Amended and Restated Articles of Incorporation of SPS dated Sept. 30, 1997.
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013 (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
4.01*	Supplemental Indenture No. 5 dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee, creating $450 million principal amount of 3.70 percent First Mortgage Bonds, Series No. 5 due 2047 (Exhibit 4.02 to Form 8-K dated Aug. 9, 2017 (file no. 001-03789)).
10.1*+	Fourth Amendment to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.1 to Form 10-Q of Xcel Energy for the quarter ended Sept. 30, 2017 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2017 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Statements of Income, (ii) the Statements of Comprehensive Income (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) Notes to Financial Statements, and (vi) document and entity information.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Southwestern Public Service Company
Oct. 27, 2017	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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EX-3.01

Exhibit 3.01

AMENDED AND RESTATED

ARTICLES OF INCORPORATION

OF

SOUTHWESTERN PUBLIC SERVICE COMPANY

Pursuant to Sections 53-13-4 and -7, New Mexico Statutes Annotated, Southwestern Public Service Company, a New Mexico corporation (the "Corporation"), hereby amends and restates its Articles of Incorporation, as previously amended and restated, as follows:

FIRST: Name. The name of the Corporation is Southwestern Public Service Company.

SECOND: Principal New Mexico Office. The location of the principal office of the Corporation in New Mexico shall be at 111 East Fifth, Roswell, New Mexico.

THIRD: Purpose. The purpose for which the Corporation is organized is to transact any and all lawful business for which corporations may be incorporated under the New Mexico Business Corporation Act (the "NMBCA").

FOURTH: Capital Stock. The total number of authorized shares of the Corporation shall be 10,000,200, divided into 10,000,000 preferred shares having a par value of $1 per share (the "Preferred Stock") and 200 common shares having a par value of $1 per share (the "Common Stock").

The designations, voting powers, preferences, and relative, participating, optional, or other special rights, and qualifications, limitations, or restrictions of the above classes of stock are as follows:

(A)    Preferred Stock

(1)    Issuance in Series. Shares of Preferred Stock may be issued in one or more series when and for such consideration or considerations as the Board of Directors determines. All series will rank equally and be identical in all respects, except as permitted by the following provisions of paragraph 2 of this Article Fourth (A).

(2)    Authority of the Board with Respect to Series. The Board of Directors is authorized, at any time, to provide for the issuance of the shares of Preferred Stock in one or more series with the designations, voting powers, preferences, and relative, participating, optional, or other special rights, and qualifications, limitations, or restrictions thereof as are stated in the resolution or resolutions providing for the issue thereof adopted by the Board of Directors, and as are not stated in these Amended and Restated Articles of Incorporation or any amendment hereto or not otherwise prescribed by law including, but not limited to, determination of any of the following:

(i) The maximum number of shares to constitute the series, which may subsequently be increased or decreased (but not below the number of shares of such series then outstanding) by resolution of the Board of Directors and the distinctive designation thereof;

(ii) Whether the shares of the series shall have any voting powers, in addition to the voting powers provided by law, and, if any, the terms of the voting powers;

(iii) The dividend rate or rates, if any, on the shares of the series or the manner in which such rate or rates shall be determined, the conditions and dates upon which the dividends shall be payable, and the preference or relation which the dividends shall bear to the dividends payable on any other class or classes or on any other series of capital stock, and whether the dividends shall be cumulative or noncumulative;

(iv) Whether the shares of the series shall be subject to redemption by the Corporation, and, if made subject to redemption, the times, prices, and other terms, limitations, restrictions, or conditions of the redemption;

(v) The relative amounts, and the relative rights or preferences, if any, of payment in respect of shares of the series, which the holders of shares of the series shall be entitled to receive upon the liquidation, dissolution, or winding up of the Corporation;

(vi) Whether the shares of the series shall be subject to the operation of a retirement or sinking fund and, if so, the extent to which and the manner in which any retirement or sinking fund shall be applied to the purchase or redemption of the shares of the series for retirement or for other corporate purposes, and the terms and provisions relative to the operation of the retirement or sinking fund;

(vii) Whether the shares of the series shall be convertible into, or exchangeable for, shares of any other class, classes, or series, or other securities, whether or not issued by the Corporation, and if so convertible or exchangeable, the price or prices or the rate or rates of conversion or exchange and the method, if any, of adjusting them;

(viii) The limitations and restrictions, if any, to be effective while any shares of the series are outstanding upon the payment of dividends or the making of other distributions on, and upon the purchase, redemption, or other acquisition by the Corporation of, the Common Stock or any other class or classes of stock of the Corporation ranking junior to the shares of the series either as to dividends or upon liquidation, dissolution, or winding up of the Corporation;

(ix) The conditions or restrictions, if any, upon the creation of indebtedness of the Corporation or upon the issuance of any additional stock (including additional shares of such series or of any other class) ranking on a parity with or prior to the shares of the series as to dividends or distribution of assets upon liquidation, dissolution, or winding up of the Corporation; and

(x) Any other preference, relative, participating, optional, or other special rights, and the qualifications, limitations, or restrictions thereof, not inconsistent with law, this Article Fourth, or any resolution of the Board of Directors pursuant hereto.

(3)    Preemptive Rights. The holders of the Preferred Stock shall have no preemptive rights to subscribe to any issue of shares or other securities of any class of the Corporation.

(B)    Common Stock

(1)    Dividends. Subject to the preferential rights of holders of the Preferred Stock, dividends may be paid or declared and set apart for payment upon the Common Stock out of any funds legally available for the declaration of dividends, but only when and as determined by the Board of Directors.

(2)    Liquidation, Dissolution, or Winding Up. Subject to the preferential rights of holders of the Preferred Stock in the event of any voluntary or involuntary liquidation, dissolution, or winding up of the Corporation, the holders of shares of the Common Stock shall be entitled to receive all of the assets of the Corporation available for distribution to its shareholders ratably in proportion to the number of shares of the Common Stock they hold.

(3)    Voting Rights. Except as may be otherwise required by the NMBCA or these Amended and Restated Articles of Incorporation, each holder of Common Stock has one vote for each share of stock he or she holds of record on the books of the Corporation on all matters voted upon by the shareholders. Cumulative voting for the election of directors shall not be permitted.

(4)    Preemptive Rights. The holders of the Common Stock shall have no preemptive rights to subscribe to any issue of shares or other securities of any class of the Corporation.

FIFTH: Duration. The duration of the Corporation shall be perpetual.

SIXTH: Number of Directors. The number of directors shall be fixed as provided in the Bylaws of the Corporation (the "Bylaws") or, if the Bylaws fail to fix the number, by resolution adopted from time to time by the Board of Directors.

SEVENTH: Limitations of Liability; Indemnification. A director of the Corporation shall not be personally liable to the Corporation or to its shareholders for monetary damages for a breach of fiduciary duty as a director unless (a) he or she has breached or failed to perform the duties of his or her office in accordance with the NMBCA, and (b) the breach or failure to perform constitutes negligence, willful misconduct, or recklessness. If the NMBCA is amended to permit the further elimination or limitation of the personal liability of directors, then the liability of a director of the Corporation shall be eliminated or limited to the fullest extent permitted by the NMBCA, as amended.

To the maximum extent permitted by law, the Corporation shall indemnify any person who is or was a director, officer, agent, fiduciary, or employee of the Corporation against any claim, liability, loss, or expense arising against or incurred by such person as a result of circumstances, events, actions, and omissions occurring in such capacity. The Corporation further shall have the authority to maintain insurance at the Corporation’s expense providing for such indemnification, including insurance with respect to claims, liabilities, losses, and expenses against which the Corporation would not otherwise have the power to indemnify such persons.

Any repeal or modification of this Article Seventh by the shareholders of the Corporation shall not adversely affect any right or protection of a director, officer, agent, fiduciary, or employee of the Corporation in respect of any act or omission occurring prior to the time of the repeal or modification.

EIGHTH: Bylaws. In furtherance and not in limitation of the powers conferred by statute, the Board of Directors is authorized to make and alter the Bylaws, subject to the power of the shareholders to alter and repeal the Bylaws made by the Board of Directors.

* * * * *

The foregoing Amended and Restated Articles of Incorporation include amendments to the Corporation’s previous Articles of Incorporation, as amended. These amendments were duly approved and adopted by the Board of Directors of the Corporation effective August 26, 1997.

The sole shareholder of the Corporation, owning 100 shares of common stock of the Corporation, duly approved the foregoing Amended and Restated Articles of Incorporation (including the amendments reflected therein) by written consent effective August 26, 1997. All such shares were eligible to vote on the amendment as a single class, and all such shares were voted for and none against such amendments. No other shares of capital stock of the Corporation were or are outstanding.

These Amended and Restated Articles of Incorporation correctly set forth the corresponding provisions of the Articles of Incorporation as amended and supersede the original Articles of Incorporation and all prior amendments thereto.

Dated: September 30, 1997.

SOUTHWESTERN PUBLIC SERVICE COMPANY

By         /s/ David M. Wilks        

David M. Wilks, President

By         /s/ Mary Pullum            

Mary Pullum, Secretary

STATE OF TEXAS        )

) ss.

COUNTY OF POTTER    )

David M. Wilks, being first duly sworn, states that he is President of Southwestern Public Service Company, that he has read and signed the foregoing document, and that every statement in the document is true and correct to the best of his information and belief.

/s/ David M. Wilks            

David M. Wilks

SWORN AND SUBSCRIBED TO BEFORE ME BY David M. Wilks, as President of Southwestern Public Service Company, on this 30th day of September 1997.

/s/ Teresa Joan Parker        

Teresa Joan Parker

Notary Public, State of Texas

My commission expires: May 19, 2001

[NOTARIAL SEAL]

[Filed in the office of the State

Corporation Commission of

New Mexico and made effective

on October 1, 1997.]

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Oct. 27, 2017

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting

Date: Oct. 27, 2017

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Southwestern Public Service Company (SPS) on Form 10-Q for the quarter ended Sept. 30, 2017, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of SPS certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of SPS as of the dates and for the periods expressed in the Form 10-Q.

Date: Oct. 27, 2017

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to SPS and will be retained by SPS and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

SPS Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of SPS, Xcel Energy Inc. or any of its other subsidiaries.  These statements are based on management’s beliefs as well as assumptions and information currently available to management.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause SPS’ actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where SPS has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

• Availability of cost or capital such as changes in: interest rates; market perceptions of the utility industry, SPS, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry or additional competition in the markets served by SPS, Xcel Energy Inc. and its other subsidiaries;

• State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric market; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Risks associated with implementation of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in SEC filings, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2016, or in other publicly disseminated written documents.

 SPS undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

1

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 27, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHWESTERN PUBLIC SERVICE CO
Entity Central Index Key	0000092521
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	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

XML

STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement [Abstract]
Operating revenues	$ 551,623	$ 554,926	$ 1,491,491	$ 1,386,210
Operating expenses
Electric fuel and purchased power	294,400	297,587	816,027	757,537
Operating and maintenance expenses	66,289	71,699	213,348	202,410
Demand side management expenses	4,236	5,663	11,802	12,279
Depreciation and amortization	47,548	42,026	144,781	123,250
Taxes (other than income taxes)	16,743	15,589	50,222	46,417
Total operating expenses	429,216	432,564	1,236,180	1,141,893
Operating income	122,407	122,362	255,311	244,317
Other income, net	285	137	452	563
Allowance for funds used during construction — equity	2,453	2,632	6,457	7,348
Interest charges and financing costs
Interest charges — includes other financing costs of $625, $828, $1,781, and $2,461, respectively	21,444	23,343	66,128	67,350
Allowance for funds used during construction — debt	(1,349)	(1,422)	(3,816)	(4,146)
Total interest charges and financing costs	20,095	21,921	62,312	63,204
Income before income taxes	105,050	103,210	199,908	189,024
Income taxes	37,269	34,864	71,710	65,944
Net income	$ 67,781	$ 68,346	$ 128,198	$ 123,080

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STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Interest charges and financing costs
Other financing costs	$ 625	$ 828	$ 1,781	$ 2,461

XML

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Comprehensive income:
Net income	$ 67,781	$ 68,346	$ 128,198	$ 123,080
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $9, $6, $27 and $19, respectively	16	12	46	35
Derivative instruments:
Reclassification of losses to net income, net of tax of $6, $25, $18 and $74, respectively	10	44	29	129
Other comprehensive income	26	56	75	164
Comprehensive income	$ 67,807	$ 68,402	$ 128,273	$ 123,244

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STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative instruments:
Reclassification of losses to net income, tax	$ 6	$ 25	$ 18	$ 74
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, Tax	$ 9	$ 6	$ 27	$ 19

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STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating activities
Net income	$ 128,198	$ 123,080
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	144,664	123,820
Demand side management program amortization	1,255	1,255
Deferred income taxes	101,388	99,882
Amortization of investment tax credits	(99)	(160)
Allowance for equity funds used during construction	(6,457)	(7,348)
Net derivative losses	47	203
Other Operating Activities, Cash Flow Statement	9	122
Changes in operating assets and liabilities:
Accounts receivable	(25,134)	(22,160)
Accrued unbilled revenues	(13,682)	(18,307)
Inventories	(2,845)	(1,491)
Prepayments and other	19,361	24,172
Accounts payable	7,817	19,690
Net regulatory assets and liabilities	24,856	(18,480)
Other current liabilities	19,748	18,989
Pension and other employee benefit obligations	(21,638)	(15,606)
Change in other noncurrent assets	(1,697)	(537)
Change in other noncurrent liabilities	(18,690)	3,916
Net cash provided by operating activities	357,101	331,040
Investing activities
Utility capital/construction expenditures	(400,957)	(371,994)
Proceeds from Insurance Settlement, Investing Activities	0	987
Allowance for equity funds used during construction	6,457	7,348
Investments in utility money pool arrangement	0	75,000
Repayments from utility money pool arrangement	0	75,000
Payments for (Proceeds from) Other Investing Activities	493	1,174
Net cash used in investing activities	(394,993)	(364,833)
Financing activities
Proceeds from short-term borrowings, net	(50,000)	(15,000)
Proceeds from issuance of long-term debt, net	442,651	296,152
Borrowings under utility money pool arrangement	323,000	505,000
Repayments under utility money pool arrangement	(323,000)	(505,000)
Capital contributions from parent	45,000	16,225
Repayment of long-term debt, including reacquisition premiums	(271,613)	0
Dividends paid to parent	(82,599)	(57,570)
Net cash provided by financing activities	83,439	239,807
Net change in cash and cash equivalents	45,547	206,014
Cash and cash equivalents at beginning of period	844	834
Cash and cash equivalents at end of period	46,391	206,848
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(58,581)	(47,787)
Cash received for income taxes, net	37,899	49,402
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 40,861	$ 25,445

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BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 46,391	$ 844
Accounts receivable, net	96,614	74,190
Accounts receivable from affiliates	3,737	949
Accrued unbilled revenues	133,100	119,418
Inventories	41,350	38,505
Regulatory assets	38,021	38,721
Derivative instruments	23,597	5,114
Prepaid taxes	3,233	21,779
Prepayments and other	7,040	7,855
Total current assets	393,083	307,375
Property, plant and equipment, net	4,947,114	4,695,819
Other assets
Regulatory assets	343,685	346,683
Derivative instruments	19,743	22,113
Other	12,193	7,477
Total other assets	375,621	376,273
Total assets	5,715,818	5,379,467
Current liabilities
Short-term debt	0	50,000
Accounts payable	183,437	176,157
Accounts payable to affiliates	11,935	14,414
Regulatory liabilities	70,355	41,577
Taxes accrued	56,386	39,742
Accrued interest	21,430	19,162
Dividends payable	26,166	30,870
Derivative instruments	3,565	3,565
Other	27,723	29,703
Total current liabilities	400,997	405,190
Deferred credits and other liabilities
Deferred income taxes	1,090,921	989,137
Regulatory liabilities	222,956	233,454
Asset retirement obligations	29,808	28,663
Derivative instruments	20,840	23,513
Pension and employee benefit obligations	86,291	107,872
Other	8,307	24,084
Total deferred credits and other liabilities	1,459,123	1,406,723
Commitments and contingencies
Capitalization
Long-term debt	1,829,965	1,635,858
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively	0	0
Additional paid in capital	1,489,882	1,446,223
Retained earnings	537,066	486,763
Accumulated other comprehensive loss	(1,215)	(1,290)
Total common stockholder’s equity	2,025,733	1,931,696
Total liabilities and equity	$ 5,715,818	$ 5,379,467

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BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Sep. 30, 2017	Dec. 31, 2016
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

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Management's Opinion

9 Months Ended

Sep. 30, 2017

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 Sept. 30, 2017 and Dec. 31, 2016; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2017 and 2016; and its cash flows for the nine months endedSept. 30, 2017 and 2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2017 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, 2016 balance sheet information has been derived from the audited 2016 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2016. 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, 2016, filed with the SEC on Feb. 24, 2017. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

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, 2016, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Accounting Pronouncements

9 Months Ended

Sep. 30, 2017

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 new framework for the recognition of revenue. SPS expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. SPS currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. SPS expects that the overall impacts of the Jan. 1, 2018 adoption will not be material.

Leases —In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. SPS has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard. As such, agreements entered prior to Jan. 1, 2017 that are currently considered leases are expected to be recognized on the balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. SPS expects that similar agreements entered after Dec. 31, 2016 will generally qualify as leases under the new standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.

Presentation of Net Periodic Benefit Cost —In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. SPS expects that as a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the current ratemaking treatment and that the impacts of adoption will be limited to changes in classification of non-service costs in the statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017.

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Selected Balance Sheet Data

9 Months Ended

Sep. 30, 2017

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$	103,704		$	80,569
Less allowance for bad debts	(7,090		)	(6,379		)
	$	96,614		$	74,190

(Thousands of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Inventories
Materials and supplies	$	26,877	$	25,453
Fuel	14,473		13,052
	$	41,350	$	38,505

(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Property, plant and equipment, net
Electric plant	$	6,653,228		$	6,362,189
Construction work in progress	312,445			260,327
Total property, plant and equipment	6,965,673			6,622,516
Less accumulated depreciation	(2,018,559		)	(1,926,697		)
	$	4,947,114		$	4,695,819

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Income Taxes

9 Months Ended

Sep. 30, 2017

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, 2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audits — 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 through 2011 and 2012 through 2013 federal income tax returns, following extensions, expires in June 2018 and October 2018, respectively.

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. SPS did not accrue any income tax benefit related to this adjustment.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Sept. 30, 2017, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2017, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In 2016, Texas began an audit of years 2009 and 2010, and in September 2017, began an audit of 2011. As of Sept. 30, 2017, Texas had not proposed any material adjustments and there were no other state income tax audits in progress.

Unrecognized Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions	$	5.2	$	4.5
Unrecognized tax benefit — Temporary tax positions	5.1		24.2
Total unrecognized tax benefit	$	10.3	$	28.7

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
NOL and tax credit carryforwards	$	(5.8	)	$	(5.9	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audits resume, the Texas audit progresses, and other state audits resume. As the IRS Appeals and Texas audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $7 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period	$	(0.9	)	$	—
Interest expense related to unrecognized tax benefits recorded during the period	—			(0.9		)
Payable for interest related to unrecognized tax benefits at end of period	$	(0.9	)	$	(0.9	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2017 or Dec. 31, 2016.

XML

Rate Matters

9 Months Ended

Sep. 30, 2017

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, 2016 and in Note 5 to SPS’ Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, 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)

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. In March 2017, the Travis County District Court denied SPS’ appeal.  In April 2017, SPS appealed the District Court’s decision to the Court of Appeals.

Texas 2017 Electric Rate Case — In August 2017, SPS filed a $66.4 million, or 7.1 percent, retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on the 12-month period ended June 30, 2017, with the final three months based on estimates, a requested return on equity (ROE) of 10.25 percent, a Texas retail electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

In October 2017, SPS revised its request to $54.6 million, or 5.8 percent, which reflects updated actual results. In addition, approximately $4.4 million of rate case expenses was bifurcated into a separate docket.

The following table summarizes SPS’ revised rate increase request:

Revenue Request (Millions of Dollars)
Incremental revenue request	$	69.2
Transmission Cost Recovery Factor (TCRF) revenue conversion to base rates (a)	(14.6		)
Net revenue increase request	$	54.6

^(a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

Key dates in the procedural schedule are as follows:

• Intervenors’ direct testimony — Feb. 22, 2018;

• PUCT Staff direct testimony — March 1, 2018;

• PUCT Staff and intervenors’ cross-rebuttal testimony — March 22, 2018;

• SPS’ rebuttal testimony — March 23, 2018;

• Hearings — April 10 - 20, 2018; and

• Statutory deadline — Aug. 31, 2018.

The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the third quarter of 2018.

Pending Regulatory Proceeding — New Mexico Public Regulation Commission (NMPRC)

New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41.4 million, representing a total revenue increase of approximately 10.9 percent. The rate filing was based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a future test year ending June 30, 2018.

In April 2017, the NMPRC dismissed SPS’ rate case. In May 2017, SPS filed a notice of appeal to the New Mexico Supreme Court. A decision from the New Mexico Supreme Court is not expected until the second or third quarter of 2018.

SPS plans to file another base rate case by November 2017 utilizing a historic test year ending June 2017.

Pending Regulatory Proceeding — Federal Energy Regulatory Commission (FERC)

Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades.  In July 2016, the FERC granted SPP’s request for a waiver to allow SPP to recover the charges not billed since 2008.  In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges, to be paid over a five-year period commencing November 2016. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. On the retail level, in October 2016, SPS filed applications for deferred accounting and future recovery of related costs in New Mexico and Texas.  In December 2016, SPS’ New Mexico application was consolidated with its base rate case, but the NMPRC dismissed that rate case in April 2017. SPS will seek recovery of these SPP charges in its next New Mexico base rate case by November 2017. In March 2017, SPS withdrew its Texas application and is now seeking to recover these SPP charges in its pending rate case filed in August 2017.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed on and after November 2016 asserting that SPP has assessed upgrade charges to SPS even where SPS’ transmission service was not dependent upon the upgrade as required by the SPP OATT.  If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings. Also in October 2017, SPP made adjustments to its previous calculations of upgrade charges to SPP customers, and the impact was immaterial to SPS.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10 and 11 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2016, and in Notes 5 and 6 to the financial statements included in SPS’ Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, 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.

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 897 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2017 and Dec. 31, 2016, 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 2041.

Environmental Contingencies

Environmental Requirements

Water and Waste

Federal Clean Water Act (CWA) Waters of the United States Rule —In 2015, the Environmental Protection Agency (EPA) and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in the first quarter of 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

Federal CWA Effluent Limitations Guidelines (ELG) —In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In September 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport water until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.

Air

Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, the EPA issued its final rule for existing power plants.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. 

The CPP was challenged by multiple parties in the D.C. Circuit Court.  In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the Clean Air Act (CAA). The EPA will take public comment on the proposal for 60 days. The EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing electric generating units.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The Best Available Retrofit Technology (BART) requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce Sulfur Dioxide (SO₂), Nitrogen Oxide (NOx) and particulate matter emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR). Texas’ first regional haze plan has undergone federal review as described below.

BART Determinations for Texas: Texas developed a State Implementation Plan (SIP) that found the CAIR equal to BART for electric generating units. As a result, no additional controls beyond CAIR compliance would have been required. In 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that deferred its approval of CSAPR compliance as BART until the EPA considered further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO₂ emission budgets. The EPA then published a proposed rule in January 2017 that could have had the effect of requiring installation of dry scrubbers to reduce SO₂ emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could have been approximately $400 million. In September 2017, the EPA issued a final rule adopting a Texas only SO₂ trading program as a BART Alternative. The program allocated SO₂ allowances to electric generating units in Texas, including all three Harrington units and both Tolk units, consistent with their allocation under CSAPR, resulting in an emissions budget for Texas that is consistent with the EPA’s 2012 rule. SPS expects the allowance allocations to be sufficient for SO₂ emissions from Harrington and Tolk units in 2019 and future years. The anticipated costs of compliance are not expected to have a material impact on the results of operations, financial position or cash flows; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

Reasonable Progress Rule: In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO₂ emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. SPS appealed the EPA’s decision and requested a stay of the final rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the case in abeyance until the EPA completes its reconsideration of the rule. In the final BART rule that affects Tolk and Harrington described above, the EPA noted that it will address the remanded rule in a future action. Such a rule will address whether further SO₂ emission reductions are needed at Tolk to address the “reasonable progress” requirements of the regional haze program. The risk of these controls being imposed along with the risk of investments to provide additional cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units.

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.

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Borrowings and Other Financing Instruments

9 Months Ended

Sep. 30, 2017

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 Sept. 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	37			28
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	1.10		%	0.67		%
Weighted average interest rate at period end	N/A			N/A

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility and the money pool. Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	400		$	400
Amount outstanding at period end	—			50
Average amount outstanding	36			43
Maximum amount outstanding	106			140
Weighted average interest rate, computed on a daily basis	1.37		%	0.67		%
Weighted average interest rate at period end	N/A			0.95

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. As of Sept. 30, 2017 and Dec. 31, 2016, there were $2 million and $5 million, respectively, of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, 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.

As of Sept. 30, 2017, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	3	$	397

^(a)  This credit facility expires in June 2021.

^(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 as of Sept. 30, 2017 and Dec. 31, 2016.

Long-Term Borrowings

In August 2017, SPS issued $450 million of 3.70 percent first mortgage bonds due Aug. 15, 2047.

Debt Redemption

On Aug. 30, 2017, SPS reacquired $250 million of debt with a coupon rate of 8.75 percent and an original maturity date of Dec. 1, 2018. The redemption resulted in payment of an early redemption premium of $21.6 million which was deferred as a regulatory asset.

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Fair Value of Financial Assets and Liabilities

9 Months Ended

Sep. 30, 2017

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 value (NAV).

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 classification. 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, generally referred to as financial transmission rights (FTRs), purchased from Southwest Power Pool Inc. (SPP). FTRs purchased from a regional transmission organization (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 transmission congestion. 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 the cleared prices for each FTR for the most recent auction.

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 transparency in the auction process, 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, the limited transparency associated with the 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.

As of Sept. 30, 2017, accumulated other comprehensive losses related to interest rate derivatives included an immaterial amount 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, including derivatives. 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. 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 as of Sept. 30, 2017 and Dec. 31, 2016:

(Amounts in Thousands) (a)	Sept. 30, 2017	Dec. 31, 2016
Megawatt hours of electricity	6,183	2,685

^(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 immaterial for the three and nine months ended Sept. 30, 2017 and $0.1 million and $0.2 million for the three and nine months ended Sept. 30, 2016.

During the three and nine months ended Sept. 30, 2017, changes in the fair value of FTRs resulted in pre-tax net losses of $2.5 million and $0.2 million, respectively, and were recognized as regulatory assets and liabilities. For the three and nine months ended Sept. 30, 2016, changes in the fair value of FTRs resulted in pre-tax net gains of $0.2 million and $2.0 million, respectively, and were 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 losses of $2.2 million and gains of $0.1 million were recognized for the three and nine months ended Sept. 30, 2017, recorded to electric fuel and purchased power. For the three and nine months ended Sept. 30, 2016, FTR settlement losses of $0.4 million and $3.7 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 nine months ended Sept. 30, 2017 and 2016. 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 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 activities. As of Sept. 30, 2017, two of SPS’ most significant counterparties for these activities, comprising $15.3 million or 33 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the most significant counterparties, comprising $9.2 million or 20 percent of this credit exposure, were not rated by Standard & Poor’s, Moody’s or Fitch Ratings, but based on SPS’ internal analysis, had credit quality consistent with investment grade. The one remaining significant counterparty, comprising $0.2 million or less than 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 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 as of Sept. 30, 2017:

	Sept. 30, 2017
	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	$	—	$	—	$	23,018	$	23,018	$	(2,580	)	$	20,438
Total current derivative assets	$	—	$	—	$	23,018	$	23,018	$	(2,580	)	20,438
PPAs (a)												3,159
Current derivative instruments												$	23,597
Noncurrent derivative assets
PPAs (a)												$	19,743
Noncurrent derivative instruments												$	19,743
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,580	$	2,580	$	(2,580	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,580	$	2,580	$	(2,580	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	20,840
Noncurrent derivative instruments												$	20,840

^(a) 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 Sept. 30, 2017. At Sept. 30, 2017, 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 as of Dec. 31, 2016:

	Dec. 31, 2016
	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	$	—	$	—	$	3,254	$	3,254	$	(1,299	)	$	1,955
Total current derivative assets	$	—	$	—	$	3,254	$	3,254	$	(1,299	)	1,955
PPAs (a)												3,159
Current derivative instruments												$	5,114
Noncurrent derivative assets
PPAs (a)												$	22,113
Noncurrent derivative instruments												$	22,113
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,299	$	1,299	$	(1,299	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,299	$	1,299	$	(1,299	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	23,513
Noncurrent derivative instruments												$	23,513

^(a)  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, 2016. At Dec. 31, 2016, 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 nine months ended Sept. 30, 2017 and 2016:

	Three Months Ended Sept. 30
(Thousands of Dollars)	2017			2016
Balance at July 1	$	28,665		$	1,070
Purchases	43			274
Settlements	(9,939		)	(7,822		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	1,669			6,614
Balance at Sept. 30	$	20,438		$	136

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2017			2016
Balance at Jan. 1	$	1,955		$	5,060
Purchases	39,376			5,426
Settlements	(40,437		)	(22,438		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	19,544			12,088
Balance at Sept. 30	$	20,438		$	136

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 nine months ended Sept. 30, 2017 and 2016.

Fair Value of Long-Term Debt

As of Sept. 30, 2017 and Dec. 31, 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2017				Dec. 31, 2016
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,829,965	$	1,954,618	$	1,635,858	$	1,741,502

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 Sept. 30, 2017 and Dec. 31, 2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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Other Income, Net

9 Months Ended

Sep. 30, 2017

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2017			2016			2017			2016
Interest income	$	296		$	400		$	488		$	579
Other nonoperating income	1			—			—			16
Insurance policy expense	(12		)	(32		)	(36		)	(32		)
Other nonoperating expense	—			(231		)	—			—
Other income, net	$	285		$	137		$	452		$	563

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Benefit Plans and Other Postretirement Benefits

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,439		$	2,440		$	219		$	194
Interest cost	4,928			5,315			415			455
Expected return on plan assets	(6,971		)	(6,901		)	(589		)	(594		)
Amortization of prior service credit	—			—			(100		)	(100		)
Amortization of net loss (gain)	3,245			2,997			(155		)	(146		)
Net periodic benefit cost (credit)	3,641			3,851			(210		)	(191		)
Credits not recognized due to the effects of regulation	553			637			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,194		$	4,488		$	(210	)	$	(191	)

	Nine Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,319		$	7,320		$	657		$	582
Interest cost	14,783			15,945			1,245			1,365
Expected return on plan assets	(20,913		)	(20,703		)	(1,767		)	(1,782		)
Amortization of prior service credit	—			—			(300		)	(300		)
Amortization of net loss (gain)	9,735			8,991			(465		)	(438		)
Net periodic benefit cost (credit)	10,924			11,553			(630		)	(573		)
Credits not recognized due to the effects of regulation	1,275			1,353			—			—
Net benefit cost (credit) recognized for financial reporting	$	12,199		$	12,906		$	(630	)	$	(573	)

In January 2017, contributions of $150.0 million were made across four of Xcel Energy’s pension plans, of which $23.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2017.

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2017

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:

	Three Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(659	)	$	(582	)	$	(1,241	)
Losses reclassified from net accumulated other comprehensive loss	10			16			26
Net current period other comprehensive income	10			16			26
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)

	Three Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(732	)	$	(441	)	$	(1,173	)
Other comprehensive income before reclassifications	—			12			12
Losses reclassified from net accumulated other comprehensive loss	44			—			44
Net current period other comprehensive income	44			12			56
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)

	Nine Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(678	)	$	(612	)	$	(1,290	)
Losses reclassified from net accumulated other comprehensive loss	29			46			75
Net current period other comprehensive income	29			46			75
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)

	Nine Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(817	)	$	(464	)	$	(1,281	)
Other comprehensive income before reclassifications	—			35			35
Losses reclassified from net accumulated other comprehensive loss	129			—			129
Net current period other comprehensive income	129			35			164
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2017				Three Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	16		(a)	$	69		(a)
Total, pre-tax	16				69
Tax benefit	(6		)		(25		)
Total, net of tax	10				44
Defined benefit pension and postretirement losses:
Amortization of net loss	24			(b)	—			(b)
Total, pre-tax	24				—
Tax benefit	(8		)		—
Total, net of tax	16				—
Total amounts reclassified, net of tax	$	26			$	44

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2017				Nine Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	47		(a)	$	203		(a)
Total, pre-tax	47				203
Tax benefit	(18		)		(74		)
Total, net of tax	29				129
Defined benefit pension and postretirement losses:
Amortization of net loss	72			(b)	—			(b)
Total, pre-tax	72				—
Tax benefit	(26		)		—
Total, net of tax	46				—
Total amounts reclassified, net of tax	$	75			$	129

^(a)  Included in interest charges.

^(b)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 10 for details regarding these benefit plans.

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Selected Balance Sheet Data (Tables)

9 Months Ended

Sep. 30, 2017

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$	103,704		$	80,569
Less allowance for bad debts	(7,090		)	(6,379		)
	$	96,614		$	74,190

Inventories

(Thousands of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Inventories
Materials and supplies	$	26,877	$	25,453
Fuel	14,473		13,052
	$	41,350	$	38,505

Property, Plant and Equipment, Net

(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Property, plant and equipment, net
Electric plant	$	6,653,228		$	6,362,189
Construction work in progress	312,445			260,327
Total property, plant and equipment	6,965,673			6,622,516
Less accumulated depreciation	(2,018,559		)	(1,926,697		)
	$	4,947,114		$	4,695,819

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2017

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Sept. 30, 2017		Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions	$	5.2	$	4.5
Unrecognized tax benefit — Temporary tax positions	5.1		24.2
Total unrecognized tax benefit	$	10.3	$	28.7

Tax Benefits Associated with NOL and Tax Credit Carryforwards

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:

(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
NOL and tax credit carryforwards	$	(5.8	)	$	(5.9	)

Interest Payable related to Unrecognized Tax Benefits [Table Text Block]

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)	Sept. 30, 2017			Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period	$	(0.9	)	$	—
Interest expense related to unrecognized tax benefits recorded during the period	—			(0.9		)
Payable for interest related to unrecognized tax benefits at end of period	$	(0.9	)	$	(0.9	)

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Rate Matters Rate Matters (Tables)

9 Months Ended

Sep. 30, 2017

Public Utilities, General Disclosure [Abstract]

Texas 2017 Rate Case [Table Text Block]

The following table summarizes SPS’ revised rate increase request:

Revenue Request (Millions of Dollars)
Incremental revenue request	$	69.2
Transmission Cost Recovery Factor (TCRF) revenue conversion to base rates (a)	(14.6		)
Net revenue increase request	$	54.6

^(a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

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Borrowings and Other Financing Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

As of Sept. 30, 2017, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	3	$	397

^(a)  This credit facility expires in June 2021.

^(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 Sept. 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	37			28
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	1.10		%	0.67		%
Weighted average interest rate at period end	N/A			N/A

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2017			Year Ended Dec. 31, 2016
Borrowing limit	$	400		$	400
Amount outstanding at period end	—			50
Average amount outstanding	36			43
Maximum amount outstanding	106			140
Weighted average interest rate, computed on a daily basis	1.37		%	0.67		%
Weighted average interest rate at period end	N/A			0.95

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Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity FTRs

The following table details the gross notional amounts of commodity FTRs as of Sept. 30, 2017 and Dec. 31, 2016:

(Amounts in Thousands) (a)	Sept. 30, 2017	Dec. 31, 2016
Megawatt hours of electricity	6,183	2,685

^(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 as of Sept. 30, 2017:

	Sept. 30, 2017
	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	$	—	$	—	$	23,018	$	23,018	$	(2,580	)	$	20,438
Total current derivative assets	$	—	$	—	$	23,018	$	23,018	$	(2,580	)	20,438
PPAs (a)												3,159
Current derivative instruments												$	23,597
Noncurrent derivative assets
PPAs (a)												$	19,743
Noncurrent derivative instruments												$	19,743
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,580	$	2,580	$	(2,580	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,580	$	2,580	$	(2,580	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	20,840
Noncurrent derivative instruments												$	20,840

^(a) 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 Sept. 30, 2017. At Sept. 30, 2017, 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 as of Dec. 31, 2016:

	Dec. 31, 2016
	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	$	—	$	—	$	3,254	$	3,254	$	(1,299	)	$	1,955
Total current derivative assets	$	—	$	—	$	3,254	$	3,254	$	(1,299	)	1,955
PPAs (a)												3,159
Current derivative instruments												$	5,114
Noncurrent derivative assets
PPAs (a)												$	22,113
Noncurrent derivative instruments												$	22,113
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,299	$	1,299	$	(1,299	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,299	$	1,299	$	(1,299	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	23,513
Noncurrent derivative instruments												$	23,513

^(a)  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, 2016. At Dec. 31, 2016, 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 nine months ended Sept. 30, 2017 and 2016:

	Three Months Ended Sept. 30
(Thousands of Dollars)	2017			2016
Balance at July 1	$	28,665		$	1,070
Purchases	43			274
Settlements	(9,939		)	(7,822		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	1,669			6,614
Balance at Sept. 30	$	20,438		$	136

	Nine Months Ended Sept. 30
(Thousands of Dollars)	2017			2016
Balance at Jan. 1	$	1,955		$	5,060
Purchases	39,376			5,426
Settlements	(40,437		)	(22,438		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	19,544			12,088
Balance at Sept. 30	$	20,438		$	136

Carrying Amount and Fair Value of Long-term Debt

As of Sept. 30, 2017 and Dec. 31, 2016, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2017				Dec. 31, 2016
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,829,965	$	1,954,618	$	1,635,858	$	1,741,502

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Other Income, Net (Tables)

9 Months Ended

Sep. 30, 2017

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2017			2016			2017			2016
Interest income	$	296		$	400		$	488		$	579
Other nonoperating income	1			—			—			16
Insurance policy expense	(12		)	(32		)	(36		)	(32		)
Other nonoperating expense	—			(231		)	—			—
Other income, net	$	285		$	137		$	452		$	563

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Benefit Plans and Other Postretirement Benefits (Tables)

9 Months Ended

Sep. 30, 2017

Retirement Benefits [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,439		$	2,440		$	219		$	194
Interest cost	4,928			5,315			415			455
Expected return on plan assets	(6,971		)	(6,901		)	(589		)	(594		)
Amortization of prior service credit	—			—			(100		)	(100		)
Amortization of net loss (gain)	3,245			2,997			(155		)	(146		)
Net periodic benefit cost (credit)	3,641			3,851			(210		)	(191		)
Credits not recognized due to the effects of regulation	553			637			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,194		$	4,488		$	(210	)	$	(191	)

	Nine Months Ended Sept. 30
	2017			2016			2017			2016
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,319		$	7,320		$	657		$	582
Interest cost	14,783			15,945			1,245			1,365
Expected return on plan assets	(20,913		)	(20,703		)	(1,767		)	(1,782		)
Amortization of prior service credit	—			—			(300		)	(300		)
Amortization of net loss (gain)	9,735			8,991			(465		)	(438		)
Net periodic benefit cost (credit)	10,924			11,553			(630		)	(573		)
Credits not recognized due to the effects of regulation	1,275			1,353			—			—
Net benefit cost (credit) recognized for financial reporting	$	12,199		$	12,906		$	(630	)	$	(573	)

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2017

Stockholders' Equity Note [Abstract]

Changes in Accumulated Other Comprehensive Loss, Net of Tax

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:

	Three Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(659	)	$	(582	)	$	(1,241	)
Losses reclassified from net accumulated other comprehensive loss	10			16			26
Net current period other comprehensive income	10			16			26
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)

	Three Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(732	)	$	(441	)	$	(1,173	)
Other comprehensive income before reclassifications	—			12			12
Losses reclassified from net accumulated other comprehensive loss	44			—			44
Net current period other comprehensive income	44			12			56
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)

	Nine Months Ended Sept. 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(678	)	$	(612	)	$	(1,290	)
Losses reclassified from net accumulated other comprehensive loss	29			46			75
Net current period other comprehensive income	29			46			75
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)

	Nine Months Ended Sept. 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(817	)	$	(464	)	$	(1,281	)
Other comprehensive income before reclassifications	—			35			35
Losses reclassified from net accumulated other comprehensive loss	129			—			129
Net current period other comprehensive income	129			35			164
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2017 and 2016 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2017				Three Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	16		(a)	$	69		(a)
Total, pre-tax	16				69
Tax benefit	(6		)		(25		)
Total, net of tax	10				44
Defined benefit pension and postretirement losses:
Amortization of net loss	24			(b)	—			(b)
Total, pre-tax	24				—
Tax benefit	(8		)		—
Total, net of tax	16				—
Total amounts reclassified, net of tax	$	26			$	44

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2017				Nine Months Ended Sept. 30, 2016
Losses on cash flow hedges:
Interest rate derivatives	$	47		(a)	$	203		(a)
Total, pre-tax	47				203
Tax benefit	(18		)		(74		)
Total, net of tax	29				129
Defined benefit pension and postretirement losses:
Amortization of net loss	72			(b)	—			(b)
Total, pre-tax	72				—
Tax benefit	(26		)		—
Total, net of tax	46				—
Total amounts reclassified, net of tax	$	75			$	129

^(a)  Included in interest charges.

^(b)  Included in the computation of net periodic pension and postretirement benefit costs. See Note 10 for details regarding these benefit plans.

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Accounts receivable, net
Accounts receivable	$ 103,704	$ 80,569
Less allowance for bad debts	(7,090)	(6,379)
Accounts receivable, net	$ 96,614	$ 74,190

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Inventories	$ 41,350	$ 38,505
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	26,877	25,453
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 14,473	$ 13,052

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,965,673	$ 6,622,516
Less accumulated depreciation	(2,018,559)	(1,926,697)
Property, plant and equipment, net	4,947,114	4,695,819
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	6,653,228	6,362,189
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 312,445	$ 260,327

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Income Taxes (Details) - USD ($)	9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2015	Dec. 31, 2016	Dec. 31, 2012	Dec. 31, 2015
Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	$ (900,000)		$ (900,000)		$ 0
Interest Expense related to unrecognized tax benefits	0		(900,000)
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions	5,200,000		4,500,000
Unrecognized tax benefit - Temporary tax positions	5,100,000		24,200,000
Total unrecognized tax benefit	10,300,000		28,700,000
NOL and tax credit carryforwards	(5,800,000)		(5,900,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	7,000,000
Amounts accrued for penalties related to unrecognized tax benefits	0		$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination		2012 and 2013		2010 and 2011
Year of carryback claim under examination				2009
Potential Tax Adjustments	$ 14,000,000
Earliest year subject to examination	2009
State Jurisdiction (Texas)
Tax Audits [Abstract]
Year(s) under examination			2009 and 2010
Earliest year subject to examination	2009

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Rate Matters (Details) - USD ($) $ in Millions		1 Months Ended			9 Months Ended	12 Months Ended
		Oct. 31, 2017	Aug. 31, 2017	Nov. 30, 2016	Sep. 30, 2017	Dec. 31, 2015	Dec. 31, 2014
PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 42.1
PUCT Proceeding - Texas 2017 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 66.4
Public Utilities, Requested Rate Increase (Decrease), Percentage			7.10%
Public Utilities, Number of Months in Test Year			12 months
Public Utilities, Number of Months in Test Year which are Estimated			3 months
Public Utilities, Requested Return on Equity, Percentage			10.25%
Public Utilities, Requested Rate Base, Amount			$ 1,900.0
Public Utilities, Requested Equity Capital Structure, Percentage			53.97%
NMPRC Proceeding - New Mexico 2016 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 41.4
Public Utilities, Requested Rate Increase (Decrease), Percentage				10.90%
Public Utilities, Requested Return on Equity, Percentage				10.10%
Public Utilities, Requested Rate Base, Amount				$ 832.0
Public Utilities, Requested Equity Capital Structure, Percentage				53.97%
Public Utility Commission of Texas (PUCT) | PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Decrease, Net of Rate Case Expenses						$ 4.0
Subsequent Event | PUCT Proceeding - Texas 2017 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised Requested Rate Increase		$ 54.6
Public Utilities, Revised Requested Rate Increase, Percentage		5.80%
Public Utilities, Rate Case Expenses Addressed in Separate Proceeding		$ 4.4
Public Utilities, Revised Incremental revenue request		69.2
Transmission Cost Recovery Factory (TCRF) Rider | Subsequent Event | PUCT Proceeding - Texas 2017 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Rider Conversion to Base Rates	[1]	$ 14.6
SPS | Southwest Power Pool (SPP) | SPP Open Access Transmission Tariff Upgrade Costs
Public Utilities, General Disclosures [Line Items]
Public Utilities, Billed Charges For Transmission Service Upgrades				$ 12.8
Public Utilities, Length of Payment Period Requested, In Years					5 years
Public Utilities, Monthly Billed Charges For Transmission Service Upgrades					$ 0.5

[1] (a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

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Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	897	897
Purchase Power Agreement Expiration (year)	2041

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Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Clean Power Plan [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Length of Public Comment Period	60 days
Regional Haze Rules
Environmental Requirements [Abstract]
Number of units receiving allocated allowances under program	3
Harrington Units 1 and 2 [Member] | Capital Addition Purchase Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation	$ 400
Tolk Units 1 and 2 [Member] | Capital Addition Purchase Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation	$ 600

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 50,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000,000	100,000,000
Amount outstanding at period end	0	0
Average amount outstanding	37,000,000	28,000,000
Maximum amount outstanding	$ 100,000,000	$ 100,000,000
Weighted average interest rate, computed on a daily basis (percentage)	1.10%	0.67%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000,000	$ 400,000,000
Amount outstanding at period end	0	50,000,000
Average amount outstanding	36,000,000	43,000,000
Maximum amount outstanding	$ 106,000,000	$ 140,000,000
Weighted average interest rate, computed on a daily basis (percentage)	1.37%	0.67%
Weighted average interest rate at period end (percentage)		0.95%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 50,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 2,000	$ 5,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

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Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility - USD ($)		9 Months Ended
		Sep. 30, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Credit Facility	[1]	$ 400,000,000
Drawn	[2]	3,000,000
Available		$ 397,000,000
Maturity Date		Jun. 30, 2021
Direct advances on the credit facility outstanding		$ 0	$ 0

[1] This credit facility expires in June 2021.

[2] Includes outstanding commercial paper and letters of credit.

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - SPS - USD ($)		1 Months Ended
	Aug. 30, 2017	Aug. 31, 2017
Series Due Dec. 1, 2018 | Bonds
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.75%
Debt Instrument, Maturity Date	Dec. 01, 2018
Debt Repayment, Amount	$ 250,000,000
Redemption Premium	$ 21,600,000
Bonds | Series Due August 15, 2047
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 450,000,000
Debt Instrument, Interest Rate, Stated Percentage		3.70%
Debt Instrument, Maturity Date		Aug. 15, 2047

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Sep. 30, 2017 USD ($) MWh	Dec. 31, 2016 MWh
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		8
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure		5
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 9.2
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		20.00%
Credit Concentration Risk | Internal Noninvestment 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		1
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		$ 0.2
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		1.00%
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		2
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 15.3
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		33.00%
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1]	6,183	2,685

[1] (a) Amounts are not reflective of net positions in the underlying commodities.

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net		(100,000)		(200,000)
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 gains (losses) recognized during the period in regulatory (assets) and liabilities	(2,500,000)	200,000	(200,000)	2,000,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ 2,200,000	$ 400,000	$ (100,000)	$ 3,700,000

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Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) - USD ($)	Sep. 30, 2017		Dec. 31, 2016
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	23,597,000		5,114,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	19,743,000		22,113,000
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	20,840,000		23,513,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	20,438,000		1,955,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(2,580,000)	[1]	(1,299,000)	[2]
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	20,438,000		1,955,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(2,580,000)	[1]	(1,299,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(2,580,000)	[1]	(1,299,000)	[2]
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
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(2,580,000)	[1]	(1,299,000)	[2]
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	23,018,000		3,254,000
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	23,018,000		3,254,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,580,000		1,299,000
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	2,580,000		1,299,000
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,159,000	[3]	3,159,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	19,743,000	[3]	22,113,000	[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	20,840,000	[3]	23,513,000	[4]
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	23,018,000		3,254,000
Estimate of Fair Value Measurement [Member] | 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	23,018,000		3,254,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,580,000		1,299,000
Estimate of Fair Value Measurement [Member] | 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	$ 2,580,000		$ 1,299,000

[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 Sept. 30, 2017. At Sept. 30, 2017, 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, 2016. At Dec. 31, 2016, 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] 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] 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.

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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		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 28,665,000	$ 1,070,000	$ 1,955,000	$ 5,060,000
Purchases	43,000	274,000	39,376,000	5,426,000
Settlements	(9,939,000)	(7,822,000)	(40,437,000)	(22,438,000)
Net gains recognized as regulatory assets and liabilities	1,669,000	6,614,000	19,544,000	12,088,000
Balance at end of period	20,438,000	136,000	20,438,000	136,000
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,829,965	$ 1,635,858
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,954,618	$ 1,741,502

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Other Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Other Income and Expenses [Abstract]
Interest income	$ 296	$ 400	$ 488	$ 579
Other Nonoperating Income	1	0	0	16
Insurance policy expense	(12)	(32)	(36)	(32)
Other nonoperating expense	0	(231)	0	0
Other income, net	$ 285	$ 137	$ 452	$ 563

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2017 USD ($) Plan	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)
Pension Plan [Member]
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,439	$ 2,440	$ 7,319	$ 7,320
Interest cost		4,928	5,315	14,783	15,945
Expected return on plan assets		(6,971)	(6,901)	(20,913)	(20,703)
Amortization of prior service cost (credit)		0	0	0	0
Amortization of net loss (gain)		3,245	2,997	9,735	8,991
Net periodic benefit cost (credit)		3,641	3,851	10,924	11,553
Defined Benefit Plan Credits Not Recognized Due To Effects of Regulation		553	637	1,275	1,353
Net benefit cost (credit) recognized for financial reporting		4,194	4,488	12,199	12,906
Total contributions to the pension plans during the period	$ 23,000
Pension Plan [Member] | Xcel Energy Inc.
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Total contributions to the pension plans during the period	$ 150,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4
Other Postretirement Benefits Plan [Member]
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		219	194	657	582
Interest cost		415	455	1,245	1,365
Expected return on plan assets		(589)	(594)	(1,767)	(1,782)
Amortization of prior service cost (credit)		(100)	(100)	(300)	(300)
Amortization of net loss (gain)		(155)	(146)	(465)	(438)
Net periodic benefit cost (credit)		(210)	(191)	(630)	(573)
Defined Benefit Plan Credits Not Recognized Due To Effects of Regulation		0	0	0	0
Net benefit cost (credit) recognized for financial reporting		$ (210)	$ (191)	$ (630)	$ (573)

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period			$ 1,931,696
Losses reclassified from net accumulated other comprehensive loss	$ 26	$ 44	75	$ 129
Accumulated other comprehensive loss at end of period	2,025,733		2,025,733
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	(659)	(732)	(678)	(817)
Other comprehensive income (loss) before reclassifications		0		0
Losses reclassified from net accumulated other comprehensive loss	10	44	29	129
Net current period other comprehensive income	10	44	29	129
Accumulated other comprehensive loss at end of period	(649)	(688)	(649)	(688)
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(582)	(441)	(612)	(464)
Other comprehensive income (loss) before reclassifications		12		35
Losses reclassified from net accumulated other comprehensive loss	16	0	46	0
Net current period other comprehensive income	16	12	46	35
Accumulated other comprehensive loss at end of period	(566)	(429)	(566)	(429)
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(1,241)	(1,173)	(1,290)	(1,281)
Other comprehensive income (loss) before reclassifications		12		35
Losses reclassified from net accumulated other comprehensive loss	26	44	75	129
Net current period other comprehensive income	26	56	75	164
Accumulated other comprehensive loss at end of period	$ (1,215)	$ (1,117)	$ (1,215)	$ (1,117)

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Other Comprehensive Income (Reclassifications from AOCI) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		$ (105,050)	$ (103,210)	$ (199,908)	$ (189,024)
Tax benefit		37,269	34,864	71,710	65,944
Total amounts reclassified, net of tax		26	44	75	129
Gains and Losses on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		10	44	29	129
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		16	69	47	203
Tax benefit		(6)	(25)	(18)	(74)
Total, net of tax		10	44	29	129
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]	16	69	47	203
Amortization of net loss | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax	[2]	24	0	72	0
Defined Benefit Pension and Postretirement Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		16	0	46	0
Defined Benefit Pension and Postretirement Items | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		24	0	72	0
Tax benefit		(8)	0	(26)	0
Total amounts reclassified, net of tax		$ 16	$ 0	$ 46	$ 0

[1] Included in interest charges.

[2] Included in the computation of net periodic pension and postretirement benefit costs. See Note 10 for details regarding these benefit plans.