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 March 31, 2018

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 April 27, 2018
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	21
Item 4    —	Controls and Procedures	25
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 March 31
	2018			2017
Operating revenues	$	447,232		$	460,072
Operating expenses
Electric fuel and purchased power	253,944			253,685
Operating and maintenance expenses	66,068			76,140
Demand side management expenses	4,158			3,875
Depreciation and amortization	48,416			50,418
Taxes (other than income taxes)	17,590			16,790
Total operating expenses	390,176			400,908
Operating income	57,056			59,164
Other expense, net	(704		)	(718		)
Allowance for funds used during construction — equity	3,417			2,135
Interest charges and financing costs
Interest charges — includes other financing costs of $694, and $581, respectively	20,155			22,738
Allowance for funds used during construction — debt	(1,771		)	(1,339		)
Total interest charges and financing costs	18,384			21,399
Income before income taxes	41,385			39,182
Income taxes	8,286			14,127
Net income	$	33,099		$	25,055

See Notes to Financial Statements

3

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2018		2017
Net income	$	33,099	$	25,055
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $5 and $9, respectively	19		15
Derivative instruments:
Reclassification of losses to net income, net of tax of $3 and $6, respectively	12		9
Other comprehensive income	31		24
Comprehensive income	$	33,130	$	25,079

See Notes to Financial Statements

4

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2018			2017
Operating activities
Net income	$	33,099		$	25,055
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	48,479			50,368
Demand side management program amortization	418			418
Deferred income taxes	753			33,079
Amortization of investment tax credits	(13		)	(33		)
Allowance for equity funds used during construction	(3,417		)	(2,135		)
Net derivative losses	15			15
Changes in operating assets and liabilities:
Accounts receivable	(11,369		)	(1,486		)
Accrued unbilled revenues	12,112			427
Inventories	6,018			7,204
Prepayments and other	1,359			(9,655		)
Accounts payable	(11,977		)	(7,497		)
Net regulatory assets and liabilities	26,974			(2,636		)
Other current liabilities	(4,936		)	(5,444		)
Pension and other employee benefit obligations	(7,880		)	(22,278		)
Change in other noncurrent assets	511			(306		)
Change in other noncurrent liabilities	(218		)	372
Net cash provided by operating activities	89,928			65,468
Investing activities
Utility capital/construction expenditures	(148,911		)	(142,559		)
Allowance for equity funds used during construction	3,417			2,135
Investments in utility money pool arrangement	(46,000		)	—
Repayments from utility money pool arrangement	111,000			—
Net cash used in investing activities	(80,494		)	(140,424		)
Financing activities
Proceeds from short-term borrowings, net	10,000			61,000
Borrowings under utility money pool arrangement	1,000			93,000
Repayments under utility money pool arrangement	(1,000		)	(93,000		)
Capital contributions from parent	360			45,000
Repayment of long-term debt, including reacquisition premiums	—			(18		)
Dividends paid to parent	(26,753		)	(30,870		)
Net cash (used in) provided by financing activities	(16,393		)	75,112
Net change in cash and cash equivalents	(6,959		)	156
Cash and cash equivalents at beginning of period	10,871			844
Cash and cash equivalents at end of period	$	3,912		$	1,000
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(21,194	)	$	(14,021	)
Cash (paid) received for income taxes, net	(4,034		)	9,741
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	36,452		$	38,096

See Notes to Financial Statements

5

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

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

	March 31, 2018			Dec. 31, 2017
Assets
Current assets
Cash and cash equivalents	$	3,912		$	10,871
Accounts receivable, net	88,537			79,581
Accounts receivable from affiliates	3,500			1,297
Investments in utility money pool arrangement	—			65,000
Accrued unbilled revenues	117,692			129,804
Inventories	34,415			40,433
Regulatory assets	32,265			31,538
Derivative instruments	8,502			15,882
Prepaid taxes	15,199			15,025
Prepayments and other	8,808			10,341
Total current assets	312,830			399,772
Property, plant and equipment, net	5,157,550			5,095,609
Other assets
Regulatory assets	355,379			362,943
Derivative instruments	18,164			18,954
Other	7,596			11,266
Total other assets	381,139			393,163
Total assets	$	5,851,519		$	5,888,544
Liabilities and Equity
Current liabilities
Short-term debt	$	10,000		$	—
Accounts payable	168,786			211,756
Accounts payable to affiliates	12,041			22,577
Regulatory liabilities	81,171			68,835
Taxes accrued	40,199			35,243
Accrued interest	20,271			23,275
Dividends payable	33,255			26,753
Derivative instruments	3,565			3,565
Other	21,889			29,641
Total current liabilities	391,177			421,645
Deferred credits and other liabilities
Deferred income taxes	576,692			574,906
Regulatory liabilities	787,943			784,564
Asset retirement obligations	28,899			28,524
Derivative instruments	19,057			19,949
Pension and employee benefit obligations	82,354			90,266
Other	4,936			8,386
Total deferred credits and other liabilities	1,499,881			1,506,595
Commitments and contingencies
Capitalization
Long-term debt	1,830,223			1,829,941
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at March 31, 2018 and Dec. 31, 2017, respectively	—			—
Additional paid in capital	1,590,242			1,590,242
Retained earnings	541,432			541,588
Accumulated other comprehensive loss	(1,436		)	(1,467		)
Total common stockholder’s equity	2,130,238			2,130,363
Total liabilities and equity	$	5,851,519		$	5,888,544

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 March 31, 2018 and Dec. 31, 2017; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2018 and 2017; and its cash flows for the three months endedMarch 31, 2018 and 2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2018 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, 2017 balance sheet information has been derived from the audited 2017 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2017. 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, 2017, filed with the SEC on Feb. 23, 2018. 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, 2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Leases —In February 2016, the Financial Accounting Standards Board (FASB) issued Leases, Topic 842 (Accounting Standards Update (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 and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered into prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated 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 into after Dec. 31, 2018 will generally qualify as leases under the new standard.

Recently Adopted

Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. SPS implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on SPS’ financial statements. For related disclosures, see Note 12.

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 eliminated the available-for-sale classification for marketable equity securities and also replaced 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 recognized in earnings. SPS implemented the guidance on Jan. 1, 2018 and the implementation did not have a material impact on its financial statements.

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. 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 historical ratemaking treatment, and the impacts of adoption will be limited to changes in classification of non-service costs in the statement of income. SPS implemented the new guidance on Jan. 1, 2018, and as a result, $0.7 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the income statement for the three months ended March 31, 2017. Under a practical expedient permitted by the standard, SPS used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	94,741		$	85,929
Less allowance for bad debts	(6,204		)	(6,348		)
	$	88,537		$	79,581

(Thousands of Dollars)	March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	26,483	$	26,218
Fuel	7,932		14,215
	$	34,415	$	40,433

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	6,908,735		$	6,765,371
Construction work in progress	306,920			351,875
Total property, plant and equipment	7,215,655			7,117,246
Less accumulated depreciation	(2,058,105		)	(2,021,637		)
	$	5,157,550		$	5,095,609

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, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

8

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:

	Three Months ended March 31
		2018		2017
Federal statutory rate		21.0	%	35.0	%
State tax, net of federal tax effect		2.4		2.1
Increases (decreases) in tax from:
Regulatory differences - ARAM (a)		(4.1	)	—
Regulatory differences - ARAM deferral (b)		2.9		—
Regulatory differences - other utility plant items		(1.5	)	(1.0	)
Other tax credits, net of federal income tax expense		(0.7	)	(0.5	)
Other, net		—		0.5
Effective income tax rate		20.0	%	36.1	%

^(a)   The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

^(b) As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

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 federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	December 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

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 and in 2015 the IRS forwarded the issue to the Office of Appeals (“Appeals”). In 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. As of March 31, 2018, the case has been forwarded to the Joint Committee on Taxation.

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 March 31, 2018, 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 uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2018, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized 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.

9

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

(Millions of Dollars)	March 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	2.3
Unrecognized tax benefit — Temporary tax positions	2.0		2.0
Total unrecognized tax benefit	$	4.4	$	4.3

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)	March 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(5.9	)	$	(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 audit resumes and state audits resume. As the IRS Appeals progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2018, and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2018 or Dec. 31, 2017.

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, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Tax Reform — Regulatory Proceedings

The specific impacts of the Tax Cuts and Jobs Act (TCJA) on customer rates are subject to regulatory approval. Each of the states in Xcel Energy’s service areas, including Texas and New Mexico, have opened dockets to address the impacts of the TCJA. SPS has made filings and is working with various stakeholders in its jurisdictions to determine the appropriate treatment for the TCJA.

In January 2018, the Public Utility Commission of Texas (PUCT) issued an order requiring utilities to apply deferred accounting for the impacts of the TCJA. In February 2018, SPS filed with the PUCT supplemental testimony, which indicated that the TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending Texas electric rate case, as discussed below.

In February 2018, SPS filed with the New Mexico Public Regulation Commission (NMPRC) a preliminary quantification of the impacts of the TCJA on its ongoing New Mexico 2017 electric rate case, which indicated that the TCJA would reduce revenue requirements by approximately $11 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending New Mexico electric rate case, as discussed below.

Federal Energy Regulatory Commission (FERC) Formula Rates — The FERC has not yet issued guidance on how or when electric utilities should reflect the impacts of the TCJA in FERC jurisdictional wholesale rates. The FERC issued a Notice of Inquiry (NOI) in March 2018 seeking comments on how to reflect the TCJA impacts in wholesale rates, in particular changes to accumulated deferred income taxes and bonus depreciation. Comments for the NOI are due in May 2018. However, FERC-approved formula rates for wholesale customers are generally adjusted on an annual basis for certain changes in rate base and actual operating expenses, including income taxes. As a result, these revenues would be subject to an automatic reduction for the effect of the TCJA corporate tax rate change through the annual true-up process, absent specific FERC action.

As a portion of the TCJA tax rate change largely offsets a depreciation rate change that was effective Jan. 1, 2018 in its wholesale production rates, SPS has notified FERC that it will continue to charge production rates established in 2017, subject to refund. SPS’ wholesale transmission rates continue to be calculated at the pre-TCJA corporate tax rate, subject to true-up in 2019.

10

Pending Regulatory Proceedings — PUCT

Texas 2017 Electric Rate Case — In 2017, SPS filed a $55 million, or 5.8 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 a historic test year (HTY) ended June 30, 2017, a requested return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

The following table summarizes SPS’ rate increase request:

Revenue Request (Millions of Dollars)
Incremental revenue request	$	69
Transmission Cost Recovery Factor (TCRF) rider conversion to base rates (a)	(14		)
Net revenue increase request	$	55

^(a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or 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 revised procedural schedule are as follows:

• PUCT Staff direct testimony — May 2, 2018;

• PUCT Staff and intervenors’ cross-rebuttal testimony — May 14, 2018;

• SPS’ rebuttal testimony — May 23, 2018; and

• Hearings — June 4 - 14, 2018.

As discussed above, the PUCT has opened a docket on the impact of the TCJA, which may have an impact on this rate case. In February 2018, SPS filed supplemental testimony with the PUCT, which indicated that TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the fourth quarter of 2018.

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42 million. In 2015, the PUCT approved an overall rate decrease of approximately $4 million, net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court (District Court) challenging 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 2017, the District Court denied SPS’ appeal, and SPS appealed the District Court’s decision to the Court of Appeals. A decision is pending.

Pending Regulatory Proceeding — NMPRC

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $43 million. The request is based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent and a rate base of approximately $885 million, including rate base additions through Nov. 30, 2017. This rate case also takes into account the decline in sales of 380 megawatts (MW) in 2017 from certain wholesale customers and seeks to adjust the life of SPS’ Tolk power plant (Unit 1 from 2042 to 2032 and Unit 2 from 2045 to 2032).

In February 2018, SPS filed supplemental information, which indicated that the TCJA would reduce revenue requirements by approximately $11 million. In addition, SPS requested an increase in the equity ratio of 58 percent and an adjustment to regional transmission revenue for the impacts of TCJA.

On April 13, 2018, the NMPRC Staff, the New Mexico Attorney General (NMAG), and several other parties filed testimony. The recommended ROE’s ranged from 9.0 percent to of 9.21 percent, and the recommended equity ratios were 51.0 percent to 53.97 percent.

11

The following table summarizes certain parties’ recommendations from SPS’ request:

Millions of Dollars	NMPRC Staff Testimony			NMAG Testimony
SPS request	$	43		$	43
Reduction to request for the impact of the TCJA	(11		)	(11		)
SPS request, including the impact of the TCJA	32			32
ROE (9.0 percent and 9.21 percent, respectively)	(4		)	(6		)
Capital structure (52.0 percent and 53.97 percent, respectively)	(7		)	(3		)
Accelerated depreciation (Tolk plant)	(3		)	(3		)
Disallow rate case expenses	(2		)	(3		)
Regional transmission revenue (adjustment for the impact of the TCJA)	—			(3		)
Post test year plant (estimated numbers were updated to actual)	(1		)	(2		)
Other, net	(4		)	(5		)
Recommended rate increase	$	11		$	7

Key dates in the procedural schedule are as follows:

• SPS’ rebuttal testimony — May 2, 2018; and

• Hearings — May 15 - 25, 2018.

SPS anticipates a decision and implementation of final rates in the second half of 2018.

Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41 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 2017, the NMPRC dismissed SPS’ rate case. SPS filed a notice of appeal in the New Mexico Supreme Court. A decision is not expected until the second half of 2019.

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 2016, the FERC granted SPP’s request to recover the charges not billed since 2008.  SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. SPS is currently seeking recovery of these SPP charges in its pending Texas and New Mexico base rate cases.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC denied SPS’ complaint. SPS sought rehearing in April 2018, which is pending FERC action.  If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

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, 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.

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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 March 31, 2018 and Dec. 31, 2017, 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

Manufactured Gas Plant (MGP), Landfill or Disposal Sites— SPS is currently involved in investigating and/or remediating an MGP, landfill or other disposal site. SPS has identified one site where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. SPS anticipates that the investigation or remediation activities will continue through at least 2018. SPS has accrued $0.1 million for the site as of March 31, 2018 and Dec. 31, 2017, respectively. There may be insurance recovery and/or recovery from other potentially responsible parties that will offset any costs incurred. SPS anticipates that any amounts spent will be fully recovered from customers.

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 March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	—			13
Maximum amount outstanding	1			100
Weighted average interest rate, computed on a daily basis	1.64		%	1.12		%
Weighted average interest rate at period end	N/A			N/A

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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 March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	400		$	400
Amount outstanding at period end	10			—
Average amount outstanding	4			69
Maximum amount outstanding	28			176
Weighted average interest rate, computed on a daily basis	1.86		%	1.13		%
Weighted average interest rate at period end	2.25			N/A

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. As of March 31, 2018 and Dec. 31, 2017, there were $2 million and $3 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 March 31, 2018, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	12	$	388

^(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 March 31, 2018 and Dec. 31, 2017.

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.

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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 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 March 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included immaterial 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 March 31, 2018 and Dec. 31, 2017:

(Amounts in Thousands) (a)	March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	6,386	4,251

^(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 months ended March 31, 2018 and 2017, respectively.

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During the three months ended March 31, 2018 and 2017, changes in the fair value of FTRs resulted in pre-tax net gains of $0.3 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 $0.5 million and gains of $1.2 million were recognized for the three months ended March 31, 2018 and 2017, respectively, 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 months ended March 31, 2018 and 2017. 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 March 31, 2018, two of SPS’ most significant counterparties for these activities, comprising $13.2 million or 28 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Six of the most significant counterparties, comprising $9.9 million or 21 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 $0.9 million or 2 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. All nine of these significant counterparties are municipal or cooperative electric entities or other utilities.

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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 March 31, 2018:

	March 31, 2018
	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	$	—	$	—	$	6,801	$	6,801	$	(1,458	)	$	5,343
Total current derivative assets	$	—	$	—	$	6,801	$	6,801	$	(1,458	)	5,343
PPAs (a)												3,159
Current derivative instruments												$	8,502
Noncurrent derivative assets
PPAs (a)												$	18,164
Noncurrent derivative instruments												$	18,164
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,458	$	1,458	$	(1,458	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,458	$	1,458	$	(1,458	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	19,057
Noncurrent derivative instruments												$	19,057

^(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 March 31, 2018. At March 31, 2018, 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, 2017:

	Dec. 31, 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	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	$	12,723
Total current derivative assets	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	12,723
PPAs (a)												3,159
Current derivative instruments												$	15,882
Noncurrent derivative assets
PPAs (a)												$	18,954
Noncurrent derivative instruments												$	18,954
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	19,949
Noncurrent derivative instruments												$	19,949

^(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, 2017. At Dec. 31, 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 the changes in Level 3 commodity derivatives for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
(Thousands of Dollars)	2018			2017
Balance at Jan. 1	$	12,723		$	1,955
Purchases	680			3,511
Settlements	(10,439		)	(16,400		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	2,379			12,126
Balance at March 31	$	5,343		$	1,192

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 months ended March 31, 2018 and 2017.

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Fair Value of Long-Term Debt

As of March 31, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,830,223	$	1,901,350	$	1,829,941	$	2,001,992

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 March 31, 2018 and Dec. 31, 2017, 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 (Expense), Net

Other (expense), net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Other nonoperating income	$	2		$	—
Benefits non-service cost	(636		)	(749		)
Interest (expense) income	(58		)	45
Insurance policy expense	(12		)	(12		)
Other nonoperating expense	—			(2		)
Other (expense), net	$	(704	)	$	(718	)

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,430		$	2,440		$	279		$	219
Interest cost (a)	4,603			4,928			410			415
Expected return on plan assets (a)	(7,082		)	(6,971		)	(615		)	(589		)
Amortization of prior service credit (a)	(35		)	—			(101		)	(100		)
Amortization of net loss (gain) (a)	3,517			3,245			(113		)	(155		)
Net periodic benefit cost (credit)	3,433			3,642			(140		)	(210		)
Credits not recognized due to the effects of regulation	974			148			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,407		$	3,790		$	(140	)	$	(210	)

(a) The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the

income statement or capitalized on the balance sheet as a regulatory asset.

In January 2018, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $8.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2018.

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11. Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2018 and 2017 were as follows:

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(776	)	$	(691	)	$	(1,467	)
Losses reclassified from net accumulated other comprehensive loss	12			19			31
Net current period other comprehensive income	12			19			31
Accumulated other comprehensive loss at March 31	$	(764	)	$	(672	)	$	(1,436	)

	Three Months Ended March 31, 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	9			15			24
Net current period other comprehensive income	9			15			24
Accumulated other comprehensive loss at March 31	$	(669	)	$	(597	)	$	(1,266	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2018 and 2017 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
Losses on cash flow hedges:
Interest rate derivatives	$	15		(a)	$	15		(a)
Total, pre-tax	15				15
Tax benefit	(3		)		(6		)
Total, net of tax	12				9
Defined benefit pension and postretirement losses:
Amortization of net loss	24			(b)	24			(b)
Total, pre-tax	24				24
Tax benefit	(5		)		(9		)
Total, net of tax	19				15
Total amounts reclassified, net of tax	$	31			$	24

^(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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12. Revenues

SPS principally generates revenue from the transmission, distribution and sale of electricity to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. SPS recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such SPS does not recognize a separate financing component of its collections from customers. SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. SPS recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales. SPS has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.

When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.

In the following table, regulated electric revenue is classified by the type of goods/services rendered and market/customer type.

	Three Months Ended
(Thousands of Dollars)	March 31, 2018		March 31, 2017
Major product lines
Revenue from contracts with customers:
Residential	$	80,049	$	79,601
Commercial and industrial (C&I)	195,771		200,957
Other	9,664		9,612
Total retail	285,484		290,170
Wholesale	93,232		91,141
Transmission	55,646		54,178
Other	7,531		1,945
Total revenue from contracts with customers	441,893		437,434
Alternative revenue and other	5,339		22,638
Total revenues	$	447,232	$	460,072

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 including the TCJA’s impact to SPS and its customers, as well as assumptions and other statements identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” 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, 2017 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.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as electric margin. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are adjusted from the most directly comparable measure calculated and presented in accordance with GAAP. SPS’ management uses non-GAAP measures internally for financial planning and analysis, for reporting of results to the Board of Directors, and when communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our operating performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.

Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various recovery mechanisms, and as a result, changes in these expenses are offset in operating revenues. Management believes electric margin provides the most meaningful basis for evaluating our operations because they exclude the revenue impact of fluctuations in these expenses. These margins can be reconciled to operating income, a GAAP measure, by including O&M expenses, DSM expenses, depreciation and amortization, and taxes (other than income taxes).

Results of Operations

SPS’ net income was approximately $33 million for the first quarter of 2018, compared with approximately $25 million for the same period in 2017. The increase in net income was largely due to the timing of operating and maintenance (O&M) expenses, favorable impact of weather and lower interest expense.

22

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:

	Three Months Ended March 31
(Millions of Dollars)	2018			2017
Electric revenues	$	455		$	460
Electric fuel and purchased power	(254		)	(254		)
Electric margin before impact of the TCJA	$	201		$	206
Impact of the TCJA (offset as a reduction in income tax expense)	(8		)	$	—
Electric margin	$	193		$	206

The following tables summarize the components of the changes in electric revenues and electric margin for the three months ended March 31, 2018:

Electric Revenues

(Millions of Dollars)	2018 vs 2017
Trading	$	14
Wholesale transmission revenue	5
Estimated impact of weather	4
Fuel and purchased power cost recovery	(18		)
Firm wholesale	(7		)
Other, net	(3		)
Total decrease in electric revenues before impact of the TCJA	$	(5	)
Impact of TCJA (offset as a reduction in income tax expense)	(8		)
Total decrease in electric revenues	$	(13	)

Electric Margin

(Millions of Dollars)	2018 vs 2017
Estimated impact of weather	$	4
Wholesale transmission revenue, net of costs	3
Firm wholesale	(7		)
Other, net	(5		)
Total decrease in electric margin before impact of the TCJA	$	(5	)
Impact of TCJA (offset as a reduction in income tax expense)	(8		)
Total decrease in electric margin	$	(13	)

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses decreased $10 million, or 13.2 percent, for the first quarter of 2018. The decrease primarily relates to timing of O&M expenses, including planned maintenance and overhauls at various generation facilities.

Income Taxes — Income tax expense decreased $6 million for the first quarter of 2018 compared with the same period in 2017. The decrease was primarily due to the decrease in the federal tax rate due to the TCJA and an increase in plant-related regulatory differences related to ARAM. These were partially offset by the deferral of the effects of ARAM. The ETR was 20.0 percent for the first quarter of 2018, compared with 36.1 percent for the same period in 2017. The lower ETR in 2018 is primarily due to the items referenced above.

23

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, 2017, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

Lubbock Power & Light’s (LP&L’s) Request for Participation in Electric Reliability Council of Texas (ERCOT) —In September 2017, LP&L filed its application with the PUCT and proposed to transition a portion of its load to ERCOT no later than June 2021. As a result of LP&L’s proposal, approximately $18 million in wholesale transmission revenue would be reallocated to remaining SPS transmission customers at the time of the load transition.  In November 2017, SPS and various other parties, including the PUCT Staff, filed direct testimony in response to LP&L’s application. SPS proposed an Interconnection Switching Fee to be determined by the PUCT.

In February 2018, SPS, LP&L, the PUCT Staff and various other parties filed a stipulation that provides SPS’ customers with an Interconnection Switching Fee of approximately $24 million to compensate them for the transfer of LP&L’s load from SPP to ERCOT. Under the settlement, SPS would allocate the Interconnection Switching Fee to its Texas and New Mexico retail and wholesale transmission customers through a bill credit following LP&L’s load transition to ERCOT. The PUCT approved the stipulation in March 2018. LP&L has announced its intention to transfer to ERCOT effective June 1, 2021.

Texas State Right of First Refusal (ROFR) Request for Declaratory Order — In February 2017, SPS and SPP filed a joint petition with the PUCT for a declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility, operating in areas outside of ERCOT, the ROFR to construct new transmission facilities located in the utility’s service area. SPP stated that Texas law does not provide a clear statement regarding the ROFR for incumbent utilities and therefore SPP was abiding by the portion of its OATT, which requires competitive solicitation to construct and operate new transmission facilities within areas of Texas’ SPP footprint.

In October 2017, the PUCT issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities within its service area. In January 2018, SPS and two other parties filed appeals of the PUCT’s order in the Texas State District Court. The appeals have been consolidated and the case is being briefed.

Wind Proposals — In 2017, SPS filed proposals with the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through two wind farms (the Hale wind project in Texas and the Sagamore wind project in New Mexico) for a cost of approximately $1.6 billion.  In addition, the proposal includes a purchased power agreement for 230 MW of wind. 

In March 2018, the NMPRC approved SPS’ request consistent with the terms of SPS’ and the parties’ modified unanimous settlement. The key terms of the settlement are:

• An investment cap of $1,675 per kilowatt, which is equal to 102.5 percent of the estimated construction costs;

• SPS customers would receive a credit to their bills if actual capacity factors fall below 48 percent;

• SPS customers would receive 100 percent of the federal PTC; and

• SPS will sell the output from the two wind farms into the market and keep the revenue and the grossed-up PTCs during the time the rate case is pending before the wind projects go into base rates.  If the market revenue and grossed up PTC value exceeds the estimated revenue requirement, SPS will refund the excess amount to customers as an additional customer protection during the interim period.

In February 2018, SPS and the parties filed an unopposed settlement with the PUCT.  The key terms of the settlement are similar to the terms approved by the NMPRC above except that the ratemaking treatment of the market revenues and grossed-up PTCs will be treated in a traditional ratemaking manner and the effective date of the rates in the rate cases placing the wind farms in rates will be 35 days after SPS files the rate cases.

In April 2018, the PUCT requested additional information regarding the settlement. SPS filed a response and the PUCT is scheduled to consider the settlement April 27, 2018.

24

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, 2017. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on

prohibited practices and a compliance function that reviews interaction with the markets under FERC and Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations.

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 March 31, 2018, 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.

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, 2017, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

25

Item 6 — EXHIBITS

*  Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3.01 to Form 10-Q for the quarter ended Sept. 30, 2017 (file no. 001-03789)).
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)).
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 March 31, 2018 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.

26

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
April 27, 2018	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)

27

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: April 27, 2018

/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: April 27, 2018

/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 March 31, 2018, 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: April 27, 2018

/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, 2017, 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	3 Months Ended
	Mar. 31, 2018	Apr. 27, 2018
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	Mar. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

XML

STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Statement [Abstract]
Operating revenues	$ 447,232	$ 460,072
Operating expenses
Electric fuel and purchased power	253,944	253,685
Operating and maintenance expenses	66,068	76,140
Demand side management expenses	4,158	3,875
Depreciation and amortization	48,416	50,418
Taxes (other than income taxes)	17,590	16,790
Total operating expenses	390,176	400,908
Operating income	57,056	59,164
Other expense, net	(704)	(718)
Allowance for funds used during construction — equity	3,417	2,135
Interest charges and financing costs
Interest charges — includes other financing costs of $694, and $581, respectively	20,155	22,738
Allowance for funds used during construction — debt	(1,771)	(1,339)
Total interest charges and financing costs	18,384	21,399
Income before income taxes	41,385	39,182
Income taxes	8,286	14,127
Net income	$ 33,099	$ 25,055

XML

STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Interest charges and financing costs
Other financing costs	$ 694	$ 581

XML

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Comprehensive income:
Net income	$ 33,099	$ 25,055
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $5 and $9, respectively	19	15
Derivative instruments:
Reclassification of losses to net income, net of tax of $3 and $6, respectively	12	9
Other comprehensive income	31	24
Comprehensive income	$ 33,130	$ 25,079

XML

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative instruments:
Reclassification of losses to net income, tax	$ 3	$ 6
Other Comprehensive (Income) Loss, Defined Benefit Plan, Prior Service Cost (Credit), Reclassification Adjustment from AOCI, Tax	$ 5	$ 9

XML

STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities
Net income	$ 33,099	$ 25,055
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	48,479	50,368
Demand side management program amortization	418	418
Deferred income taxes	753	33,079
Amortization of investment tax credits	(13)	(33)
Allowance for equity funds used during construction	(3,417)	(2,135)
Net derivative losses	15	15
Changes in operating assets and liabilities:
Accounts receivable	(11,369)	(1,486)
Accrued unbilled revenues	12,112	427
Inventories	6,018	7,204
Prepayments and other	1,359	(9,655)
Accounts payable	(11,977)	(7,497)
Net regulatory assets and liabilities	26,974	(2,636)
Other current liabilities	(4,936)	(5,444)
Pension and other employee benefit obligations	(7,880)	(22,278)
Change in other noncurrent assets	511	(306)
Change in other noncurrent liabilities	(218)	372
Net cash provided by operating activities	89,928	65,468
Investing activities
Utility capital/construction expenditures	(148,911)	(142,559)
Allowance for equity funds used during construction	3,417	2,135
Investments in utility money pool arrangement	46,000	0
Repayments from utility money pool arrangement	111,000	0
Net cash used in investing activities	(80,494)	(140,424)
Financing activities
Proceeds from short-term borrowings, net	10,000	61,000
Borrowings under utility money pool arrangement	1,000	93,000
Repayments under utility money pool arrangement	(1,000)	(93,000)
Capital contributions from parent	360	45,000
Repayment of long-term debt, including reacquisition premiums	0	(18)
Dividends paid to parent	(26,753)	(30,870)
Net cash (used in) provided by financing activities	(16,393)	75,112
Net change in cash and cash equivalents	(6,959)	156
Cash and cash equivalents at beginning of period	10,871	844
Cash and cash equivalents at end of period	3,912	1,000
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(21,194)	(14,021)
Cash (paid) received for income taxes, net	(4,034)	9,741
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 36,452	$ 38,096

XML

BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 3,912	$ 10,871
Accounts receivable, net	88,537	79,581
Accounts receivable from affiliates	3,500	1,297
Investments Receivable in Utility Money Pool Arrangement	0	65,000
Accrued unbilled revenues	117,692	129,804
Inventories	34,415	40,433
Regulatory assets	32,265	31,538
Derivative instruments	8,502	15,882
Prepaid taxes	15,199	15,025
Prepayments and other	8,808	10,341
Total current assets	312,830	399,772
Property, plant and equipment, net	5,157,550	5,095,609
Other assets
Regulatory assets	355,379	362,943
Derivative instruments	18,164	18,954
Other	7,596	11,266
Total other assets	381,139	393,163
Total assets	5,851,519	5,888,544
Current liabilities
Short-term debt	10,000	0
Accounts payable	168,786	211,756
Accounts payable to affiliates	12,041	22,577
Regulatory liabilities	81,171	68,835
Taxes accrued	40,199	35,243
Accrued interest	20,271	23,275
Dividends payable	33,255	26,753
Derivative instruments	3,565	3,565
Other	21,889	29,641
Total current liabilities	391,177	421,645
Deferred credits and other liabilities
Deferred income taxes	576,692	574,906
Regulatory liabilities	787,943	784,564
Asset retirement obligations	28,899	28,524
Derivative instruments	19,057	19,949
Pension and employee benefit obligations	82,354	90,266
Other	4,936	8,386
Total deferred credits and other liabilities	1,499,881	1,506,595
Commitments and contingencies
Capitalization
Long-term debt	1,830,223	1,829,941
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at March 31, 2018 and Dec. 31, 2017, respectively	0	0
Additional paid in capital	1,590,242	1,590,242
Retained earnings	541,432	541,588
Accumulated other comprehensive loss	(1,436)	(1,467)
Total common stockholder’s equity	2,130,238	2,130,363
Total liabilities and equity	$ 5,851,519	$ 5,888,544

XML

BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	200	200
Common stock, par value (in dollars per share)	$ 1.00	$ 1.00
Common stock, shares outstanding (in shares)	100	100

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Management's Opinion

3 Months Ended

Mar. 31, 2018

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 March 31, 2018 and Dec. 31, 2017; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2018 and 2017; and its cash flows for the three months endedMarch 31, 2018 and 2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2018 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, 2017 balance sheet information has been derived from the audited 2017 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2017. 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, 2017, filed with the SEC on Feb. 23, 2018. 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

3 Months Ended

Mar. 31, 2018

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, 2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Accounting Pronouncements

3 Months Ended

Mar. 31, 2018

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Accounting Pronouncements

Accounting Pronouncements

Recently Issued

Leases —In February 2016, the Financial Accounting Standards Board (FASB) issued Leases, Topic 842 (Accounting Standards Update (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 and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered into prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated 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 into after Dec. 31, 2018 will generally qualify as leases under the new standard.

Recently Adopted

Revenue Recognition— In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. SPS implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on SPS’ financial statements. For related disclosures, see Note 12.

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 eliminated the available-for-sale classification for marketable equity securities and also replaced 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 recognized in earnings. SPS implemented the guidance on Jan. 1, 2018 and the implementation did not have a material impact on its financial statements.

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. 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 historical ratemaking treatment, and the impacts of adoption will be limited to changes in classification of non-service costs in the statement of income. SPS implemented the new guidance on Jan. 1, 2018, and as a result, $0.7 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the income statement for the three months ended March 31, 2017. Under a practical expedient permitted by the standard, SPS used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

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Selected Balance Sheet Data

3 Months Ended

Mar. 31, 2018

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	94,741		$	85,929
Less allowance for bad debts	(6,204		)	(6,348		)
	$	88,537		$	79,581

(Thousands of Dollars)	March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	26,483	$	26,218
Fuel	7,932		14,215
	$	34,415	$	40,433

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	6,908,735		$	6,765,371
Construction work in progress	306,920			351,875
Total property, plant and equipment	7,215,655			7,117,246
Less accumulated depreciation	(2,058,105		)	(2,021,637		)
	$	5,157,550		$	5,095,609

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Income Taxes

3 Months Ended

Mar. 31, 2018

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, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:

	Three Months ended March 31
		2018		2017
Federal statutory rate		21.0	%	35.0	%
State tax, net of federal tax effect		2.4		2.1
Increases (decreases) in tax from:
Regulatory differences - ARAM (a)		(4.1	)	—
Regulatory differences - ARAM deferral (b)		2.9		—
Regulatory differences - other utility plant items		(1.5	)	(1.0	)
Other tax credits, net of federal income tax expense		(0.7	)	(0.5	)
Other, net		—		0.5
Effective income tax rate		20.0	%	36.1	%

^(a)   The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

^(b) As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

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 federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	December 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

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 and in 2015 the IRS forwarded the issue to the Office of Appeals (“Appeals”). In 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. As of March 31, 2018, the case has been forwarded to the Joint Committee on Taxation.

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 March 31, 2018, 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 uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of March 31, 2018, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

Unrecognized 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)	March 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	2.3
Unrecognized tax benefit — Temporary tax positions	2.0		2.0
Total unrecognized tax benefit	$	4.4	$	4.3

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)	March 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(5.9	)	$	(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 audit resumes and state audits resume. As the IRS Appeals progresses, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2018, and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2018 or Dec. 31, 2017.

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Rate Matters

3 Months Ended

Mar. 31, 2018

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, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Tax Reform — Regulatory Proceedings

The specific impacts of the Tax Cuts and Jobs Act (TCJA) on customer rates are subject to regulatory approval. Each of the states in Xcel Energy’s service areas, including Texas and New Mexico, have opened dockets to address the impacts of the TCJA. SPS has made filings and is working with various stakeholders in its jurisdictions to determine the appropriate treatment for the TCJA.

In January 2018, the Public Utility Commission of Texas (PUCT) issued an order requiring utilities to apply deferred accounting for the impacts of the TCJA. In February 2018, SPS filed with the PUCT supplemental testimony, which indicated that the TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending Texas electric rate case, as discussed below.

In February 2018, SPS filed with the New Mexico Public Regulation Commission (NMPRC) a preliminary quantification of the impacts of the TCJA on its ongoing New Mexico 2017 electric rate case, which indicated that the TCJA would reduce revenue requirements by approximately $11 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending New Mexico electric rate case, as discussed below.

Federal Energy Regulatory Commission (FERC) Formula Rates — The FERC has not yet issued guidance on how or when electric utilities should reflect the impacts of the TCJA in FERC jurisdictional wholesale rates. The FERC issued a Notice of Inquiry (NOI) in March 2018 seeking comments on how to reflect the TCJA impacts in wholesale rates, in particular changes to accumulated deferred income taxes and bonus depreciation. Comments for the NOI are due in May 2018. However, FERC-approved formula rates for wholesale customers are generally adjusted on an annual basis for certain changes in rate base and actual operating expenses, including income taxes. As a result, these revenues would be subject to an automatic reduction for the effect of the TCJA corporate tax rate change through the annual true-up process, absent specific FERC action.

As a portion of the TCJA tax rate change largely offsets a depreciation rate change that was effective Jan. 1, 2018 in its wholesale production rates, SPS has notified FERC that it will continue to charge production rates established in 2017, subject to refund. SPS’ wholesale transmission rates continue to be calculated at the pre-TCJA corporate tax rate, subject to true-up in 2019.

Pending Regulatory Proceedings — PUCT

Texas 2017 Electric Rate Case — In 2017, SPS filed a $55 million, or 5.8 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 a historic test year (HTY) ended June 30, 2017, a requested return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

The following table summarizes SPS’ rate increase request:

Revenue Request (Millions of Dollars)
Incremental revenue request	$	69
Transmission Cost Recovery Factor (TCRF) rider conversion to base rates (a)	(14		)
Net revenue increase request	$	55

^(a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or 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 revised procedural schedule are as follows:

• PUCT Staff direct testimony — May 2, 2018;

• PUCT Staff and intervenors’ cross-rebuttal testimony — May 14, 2018;

• SPS’ rebuttal testimony — May 23, 2018; and

• Hearings — June 4 - 14, 2018.

As discussed above, the PUCT has opened a docket on the impact of the TCJA, which may have an impact on this rate case. In February 2018, SPS filed supplemental testimony with the PUCT, which indicated that TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the fourth quarter of 2018.

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42 million. In 2015, the PUCT approved an overall rate decrease of approximately $4 million, net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court (District Court) challenging 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 2017, the District Court denied SPS’ appeal, and SPS appealed the District Court’s decision to the Court of Appeals. A decision is pending.

Pending Regulatory Proceeding — NMPRC

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $43 million. The request is based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent and a rate base of approximately $885 million, including rate base additions through Nov. 30, 2017. This rate case also takes into account the decline in sales of 380 megawatts (MW) in 2017 from certain wholesale customers and seeks to adjust the life of SPS’ Tolk power plant (Unit 1 from 2042 to 2032 and Unit 2 from 2045 to 2032).

In February 2018, SPS filed supplemental information, which indicated that the TCJA would reduce revenue requirements by approximately $11 million. In addition, SPS requested an increase in the equity ratio of 58 percent and an adjustment to regional transmission revenue for the impacts of TCJA.

On April 13, 2018, the NMPRC Staff, the New Mexico Attorney General (NMAG), and several other parties filed testimony. The recommended ROE’s ranged from 9.0 percent to of 9.21 percent, and the recommended equity ratios were 51.0 percent to 53.97 percent.

The following table summarizes certain parties’ recommendations from SPS’ request:

Millions of Dollars	NMPRC Staff Testimony			NMAG Testimony
SPS request	$	43		$	43
Reduction to request for the impact of the TCJA	(11		)	(11		)
SPS request, including the impact of the TCJA	32			32
ROE (9.0 percent and 9.21 percent, respectively)	(4		)	(6		)
Capital structure (52.0 percent and 53.97 percent, respectively)	(7		)	(3		)
Accelerated depreciation (Tolk plant)	(3		)	(3		)
Disallow rate case expenses	(2		)	(3		)
Regional transmission revenue (adjustment for the impact of the TCJA)	—			(3		)
Post test year plant (estimated numbers were updated to actual)	(1		)	(2		)
Other, net	(4		)	(5		)
Recommended rate increase	$	11		$	7

Key dates in the procedural schedule are as follows:

• SPS’ rebuttal testimony — May 2, 2018; and

• Hearings — May 15 - 25, 2018.

SPS anticipates a decision and implementation of final rates in the second half of 2018.

Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41 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 2017, the NMPRC dismissed SPS’ rate case. SPS filed a notice of appeal in the New Mexico Supreme Court. A decision is not expected until the second half of 2019.

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 2016, the FERC granted SPP’s request to recover the charges not billed since 2008.  SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. SPS is currently seeking recovery of these SPP charges in its pending Texas and New Mexico base rate cases.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC denied SPS’ complaint. SPS sought rehearing in April 2018, which is pending FERC action.  If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

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, 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 March 31, 2018 and Dec. 31, 2017, 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

Manufactured Gas Plant (MGP), Landfill or Disposal Sites— SPS is currently involved in investigating and/or remediating an MGP, landfill or other disposal site. SPS has identified one site where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. SPS anticipates that the investigation or remediation activities will continue through at least 2018. SPS has accrued $0.1 million for the site as of March 31, 2018 and Dec. 31, 2017, respectively. There may be insurance recovery and/or recovery from other potentially responsible parties that will offset any costs incurred. SPS anticipates that any amounts spent will be fully recovered from customers.

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

3 Months Ended

Mar. 31, 2018

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 March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	—			13
Maximum amount outstanding	1			100
Weighted average interest rate, computed on a daily basis	1.64		%	1.12		%
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 March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	400		$	400
Amount outstanding at period end	10			—
Average amount outstanding	4			69
Maximum amount outstanding	28			176
Weighted average interest rate, computed on a daily basis	1.86		%	1.13		%
Weighted average interest rate at period end	2.25			N/A

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. As of March 31, 2018 and Dec. 31, 2017, there were $2 million and $3 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 March 31, 2018, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	12	$	388

^(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 March 31, 2018 and Dec. 31, 2017.

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Fair Value of Financial Assets and Liabilities

3 Months Ended

Mar. 31, 2018

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.

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 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 March 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included immaterial 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 March 31, 2018 and Dec. 31, 2017:

(Amounts in Thousands) (a)	March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	6,386	4,251

^(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 months ended March 31, 2018 and 2017, respectively.

During the three months ended March 31, 2018 and 2017, changes in the fair value of FTRs resulted in pre-tax net gains of $0.3 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 $0.5 million and gains of $1.2 million were recognized for the three months ended March 31, 2018 and 2017, respectively, 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 months ended March 31, 2018 and 2017. 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 March 31, 2018, two of SPS’ most significant counterparties for these activities, comprising $13.2 million or 28 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Six of the most significant counterparties, comprising $9.9 million or 21 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 $0.9 million or 2 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. All nine 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 March 31, 2018:

	March 31, 2018
	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	$	—	$	—	$	6,801	$	6,801	$	(1,458	)	$	5,343
Total current derivative assets	$	—	$	—	$	6,801	$	6,801	$	(1,458	)	5,343
PPAs (a)												3,159
Current derivative instruments												$	8,502
Noncurrent derivative assets
PPAs (a)												$	18,164
Noncurrent derivative instruments												$	18,164
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,458	$	1,458	$	(1,458	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,458	$	1,458	$	(1,458	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	19,057
Noncurrent derivative instruments												$	19,057

^(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 March 31, 2018. At March 31, 2018, 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, 2017:

	Dec. 31, 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	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	$	12,723
Total current derivative assets	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	12,723
PPAs (a)												3,159
Current derivative instruments												$	15,882
Noncurrent derivative assets
PPAs (a)												$	18,954
Noncurrent derivative instruments												$	18,954
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	19,949
Noncurrent derivative instruments												$	19,949

^(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, 2017. At Dec. 31, 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 the changes in Level 3 commodity derivatives for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
(Thousands of Dollars)	2018			2017
Balance at Jan. 1	$	12,723		$	1,955
Purchases	680			3,511
Settlements	(10,439		)	(16,400		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	2,379			12,126
Balance at March 31	$	5,343		$	1,192

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 months ended March 31, 2018 and 2017.

Fair Value of Long-Term Debt

As of March 31, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,830,223	$	1,901,350	$	1,829,941	$	2,001,992

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 March 31, 2018 and Dec. 31, 2017, 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

3 Months Ended

Mar. 31, 2018

Other Income and Expenses [Abstract]

Other Income, Net

Other (Expense), Net

Other (expense), net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Other nonoperating income	$	2		$	—
Benefits non-service cost	(636		)	(749		)
Interest (expense) income	(58		)	45
Insurance policy expense	(12		)	(12		)
Other nonoperating expense	—			(2		)
Other (expense), net	$	(704	)	$	(718	)

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Benefit Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 2018

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 March 31
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,430		$	2,440		$	279		$	219
Interest cost (a)	4,603			4,928			410			415
Expected return on plan assets (a)	(7,082		)	(6,971		)	(615		)	(589		)
Amortization of prior service credit (a)	(35		)	—			(101		)	(100		)
Amortization of net loss (gain) (a)	3,517			3,245			(113		)	(155		)
Net periodic benefit cost (credit)	3,433			3,642			(140		)	(210		)
Credits not recognized due to the effects of regulation	974			148			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,407		$	3,790		$	(140	)	$	(210	)

(a) The components of net periodic cost other than the service cost component are included in the line item “other income, net” in the

income statement or capitalized on the balance sheet as a regulatory asset.

In January 2018, contributions of $150 million were made across four of Xcel Energy’s pension plans, of which $8.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2018.

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Other Comprehensive Income

3 Months Ended

Mar. 31, 2018

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2018 and 2017 were as follows:

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(776	)	$	(691	)	$	(1,467	)
Losses reclassified from net accumulated other comprehensive loss	12			19			31
Net current period other comprehensive income	12			19			31
Accumulated other comprehensive loss at March 31	$	(764	)	$	(672	)	$	(1,436	)

	Three Months Ended March 31, 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	9			15			24
Net current period other comprehensive income	9			15			24
Accumulated other comprehensive loss at March 31	$	(669	)	$	(597	)	$	(1,266	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2018 and 2017 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
Losses on cash flow hedges:
Interest rate derivatives	$	15		(a)	$	15		(a)
Total, pre-tax	15				15
Tax benefit	(3		)		(6		)
Total, net of tax	12				9
Defined benefit pension and postretirement losses:
Amortization of net loss	24			(b)	24			(b)
Total, pre-tax	24				24
Tax benefit	(5		)		(9		)
Total, net of tax	19				15
Total amounts reclassified, net of tax	$	31			$	24

^(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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Revenues

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

Revenues

SPS principally generates revenue from the transmission, distribution and sale of electricity to wholesale and retail customers. Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. SPS recognizes revenue in an amount that corresponds directly to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recognized. Contract terms are generally short-term in nature, and as such SPS does not recognize a separate financing component of its collections from customers. SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. SPS recognizes sales to both native load and other end use customers on a gross basis in electric revenues and cost of sales. Revenues and charges for short term wholesale sales of excess energy transacted through RTOs are recorded on a gross basis. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales. SPS has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.

When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met (including collection within 24 months), revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenue is recorded on a gross basis and is disclosed separate from revenue from contracts with customers in the period earned.

In the following table, regulated electric revenue is classified by the type of goods/services rendered and market/customer type.

	Three Months Ended
(Thousands of Dollars)	March 31, 2018		March 31, 2017
Major product lines
Revenue from contracts with customers:
Residential	$	80,049	$	79,601
Commercial and industrial (C&I)	195,771		200,957
Other	9,664		9,612
Total retail	285,484		290,170
Wholesale	93,232		91,141
Transmission	55,646		54,178
Other	7,531		1,945
Total revenue from contracts with customers	441,893		437,434
Alternative revenue and other	5,339		22,638
Total revenues	$	447,232	$	460,072

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Selected Balance Sheet Data (Tables)

3 Months Ended

Mar. 31, 2018

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	94,741		$	85,929
Less allowance for bad debts	(6,204		)	(6,348		)
	$	88,537		$	79,581

Inventories

(Thousands of Dollars)	March 31, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	26,483	$	26,218
Fuel	7,932		14,215
	$	34,415	$	40,433

Property, Plant and Equipment, Net

(Thousands of Dollars)	March 31, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	6,908,735		$	6,765,371
Construction work in progress	306,920			351,875
Total property, plant and equipment	7,215,655			7,117,246
Less accumulated depreciation	(2,058,105		)	(2,021,637		)
	$	5,157,550		$	5,095,609

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:

	Three Months ended March 31
		2018		2017
Federal statutory rate		21.0	%	35.0	%
State tax, net of federal tax effect		2.4		2.1
Increases (decreases) in tax from:
Regulatory differences - ARAM (a)		(4.1	)	—
Regulatory differences - ARAM deferral (b)		2.9		—
Regulatory differences - other utility plant items		(1.5	)	(1.0	)
Other tax credits, net of federal income tax expense		(0.7	)	(0.5	)
Other, net		—		0.5
Effective income tax rate		20.0	%	36.1	%

^(a)   The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

^(b) As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block]

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 federal income tax returns expire as follows:

Tax Year(s)	Expiration
2009 - 2011	December 2018
2012 - 2013	October 2018
2014	September 2018
2015	September 2019
2016	September 2020

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	March 31, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	2.4	$	2.3
Unrecognized tax benefit — Temporary tax positions	2.0		2.0
Total unrecognized tax benefit	$	4.4	$	4.3

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)	March 31, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(5.9	)	$	(5.9	)

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Rate Matters Rate Matters (Tables)

3 Months Ended

Mar. 31, 2018

Public Utilities, General Disclosure [Abstract]

Texas 2017 Rate Case [Table Text Block]

The following table summarizes SPS’ rate increase request:

Revenue Request (Millions of Dollars)
Incremental revenue request	$	69
Transmission Cost Recovery Factor (TCRF) rider conversion to base rates (a)	(14		)
Net revenue increase request	$	55

^(a) The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or 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.

New Mexico 2017 Electric Rate Case [Table Text Block]

The following table summarizes certain parties’ recommendations from SPS’ request:

Millions of Dollars	NMPRC Staff Testimony			NMAG Testimony
SPS request	$	43		$	43
Reduction to request for the impact of the TCJA	(11		)	(11		)
SPS request, including the impact of the TCJA	32			32
ROE (9.0 percent and 9.21 percent, respectively)	(4		)	(6		)
Capital structure (52.0 percent and 53.97 percent, respectively)	(7		)	(3		)
Accelerated depreciation (Tolk plant)	(3		)	(3		)
Disallow rate case expenses	(2		)	(3		)
Regional transmission revenue (adjustment for the impact of the TCJA)	—			(3		)
Post test year plant (estimated numbers were updated to actual)	(1		)	(2		)
Other, net	(4		)	(5		)
Recommended rate increase	$	11		$	7

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Borrowings and Other Financing Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

As of March 31, 2018, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	12	$	388

^(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 March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	—			13
Maximum amount outstanding	1			100
Weighted average interest rate, computed on a daily basis	1.64		%	1.12		%
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 March 31, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	400		$	400
Amount outstanding at period end	10			—
Average amount outstanding	4			69
Maximum amount outstanding	28			176
Weighted average interest rate, computed on a daily basis	1.86		%	1.13		%
Weighted average interest rate at period end	2.25			N/A

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Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity FTRs

The following table details the gross notional amounts of commodity FTRs as of March 31, 2018 and Dec. 31, 2017:

(Amounts in Thousands) (a)	March 31, 2018	Dec. 31, 2017
Megawatt hours of electricity	6,386	4,251

^(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 March 31, 2018:

	March 31, 2018
	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	$	—	$	—	$	6,801	$	6,801	$	(1,458	)	$	5,343
Total current derivative assets	$	—	$	—	$	6,801	$	6,801	$	(1,458	)	5,343
PPAs (a)												3,159
Current derivative instruments												$	8,502
Noncurrent derivative assets
PPAs (a)												$	18,164
Noncurrent derivative instruments												$	18,164
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,458	$	1,458	$	(1,458	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,458	$	1,458	$	(1,458	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	19,057
Noncurrent derivative instruments												$	19,057

^(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 March 31, 2018. At March 31, 2018, 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, 2017:

	Dec. 31, 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	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	$	12,723
Total current derivative assets	$	—	$	—	$	14,717	$	14,717	$	(1,994	)	12,723
PPAs (a)												3,159
Current derivative instruments												$	15,882
Noncurrent derivative assets
PPAs (a)												$	18,954
Noncurrent derivative instruments												$	18,954
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,994	$	1,994	$	(1,994	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	19,949
Noncurrent derivative instruments												$	19,949

^(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, 2017. At Dec. 31, 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.

Changes in Level 3 Commodity Derivatives

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2018 and 2017:

	Three Months Ended March 31,
(Thousands of Dollars)	2018			2017
Balance at Jan. 1	$	12,723		$	1,955
Purchases	680			3,511
Settlements	(10,439		)	(16,400		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	2,379			12,126
Balance at March 31	$	5,343		$	1,192

Carrying Amount and Fair Value of Long-term Debt

As of March 31, 2018 and Dec. 31, 2017, other financial instruments for which the carrying amount did not equal fair value were as follows:

	March 31, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,830,223	$	1,901,350	$	1,829,941	$	2,001,992

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Other Income, Net (Tables)

3 Months Ended

Mar. 31, 2018

Other Income and Expenses [Abstract]

Other Income, Net

Other (expense), net consisted of the following:

	Three Months Ended March 31
(Thousands of Dollars)	2018			2017
Other nonoperating income	$	2		$	—
Benefits non-service cost	(636		)	(749		)
Interest (expense) income	(58		)	45
Insurance policy expense	(12		)	(12		)
Other nonoperating expense	—			(2		)
Other (expense), net	$	(704	)	$	(718	)

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Benefit Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,430		$	2,440		$	279		$	219
Interest cost (a)	4,603			4,928			410			415
Expected return on plan assets (a)	(7,082		)	(6,971		)	(615		)	(589		)
Amortization of prior service credit (a)	(35		)	—			(101		)	(100		)
Amortization of net loss (gain) (a)	3,517			3,245			(113		)	(155		)
Net periodic benefit cost (credit)	3,433			3,642			(140		)	(210		)
Credits not recognized due to the effects of regulation	974			148			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,407		$	3,790		$	(140	)	$	(210	)

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2018

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 months ended March 31, 2018 and 2017 were as follows:

	Three Months Ended March 31, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(776	)	$	(691	)	$	(1,467	)
Losses reclassified from net accumulated other comprehensive loss	12			19			31
Net current period other comprehensive income	12			19			31
Accumulated other comprehensive loss at March 31	$	(764	)	$	(672	)	$	(1,436	)

	Three Months Ended March 31, 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	9			15			24
Net current period other comprehensive income	9			15			24
Accumulated other comprehensive loss at March 31	$	(669	)	$	(597	)	$	(1,266	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2018 and 2017 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017
Losses on cash flow hedges:
Interest rate derivatives	$	15		(a)	$	15		(a)
Total, pre-tax	15				15
Tax benefit	(3		)		(6		)
Total, net of tax	12				9
Defined benefit pension and postretirement losses:
Amortization of net loss	24			(b)	24			(b)
Total, pre-tax	24				24
Tax benefit	(5		)		(9		)
Total, net of tax	19				15
Total amounts reclassified, net of tax	$	31			$	24

^(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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Revenues (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

	Three Months Ended
(Thousands of Dollars)	March 31, 2018		March 31, 2017
Major product lines
Revenue from contracts with customers:
Residential	$	80,049	$	79,601
Commercial and industrial (C&I)	195,771		200,957
Other	9,664		9,612
Total retail	285,484		290,170
Wholesale	93,232		91,141
Transmission	55,646		54,178
Other	7,531		1,945
Total revenue from contracts with customers	441,893		437,434
Alternative revenue and other	5,339		22,638
Total revenues	$	447,232	$	460,072

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Accounting Pronouncements (Details) - Accounting Standards Update 2017-07 $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Operating and Maintenance Expense
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net benefit cost (credit) recognized for financial reporting	$ (0.7)
Other Income
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net benefit cost (credit) recognized for financial reporting	$ 0.7

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$ 94,741	$ 85,929
Less allowance for bad debts	(6,204)	(6,348)
Accounts receivable, net	$ 88,537	$ 79,581

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Public Utilities, Inventory [Line Items]
Inventories	$ 34,415	$ 40,433
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	26,483	26,218
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 7,932	$ 14,215

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 7,215,655	$ 7,117,246
Less accumulated depreciation	(2,058,105)	(2,021,637)
Property, plant and equipment, net	5,157,550	5,095,609
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	6,908,735	6,765,371
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 306,920	$ 351,875

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Income Taxes (Details) - USD ($)		3 Months Ended		9 Months Ended	12 Months Ended
		Mar. 31, 2018	Mar. 31, 2017	Sep. 30, 2015	Dec. 31, 2012	Dec. 31, 2017
Tax Audits [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		2.40%	2.10%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	[1]	(4.10%)	0.00%
Effective Income Tax Rate Reconciliation, Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Percent	[2]	2.90%	0.00%
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent		(1.50%)	(1.00%)
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items		(0.70%)	(0.50%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent		0.00%	0.50%
Effective Income Tax Rate Reconciliation, Percent		20.00%	36.10%
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions		$ 2,400,000				$ 2,300,000
Unrecognized tax benefit - Temporary tax positions		2,000,000				2,000,000
Total unrecognized tax benefit		4,400,000				4,300,000
NOL and tax credit carryforwards		(5,900,000)				(5,900,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible		2,000,000
Amounts accrued for penalties related to unrecognized tax benefits		$ 0				$ 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
State Jurisdiction (Texas)
Tax Audits [Abstract]
Earliest year subject to examination		2009

[1] The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.

[2] As we receive further clarity or direction from our commissions regarding the flow back to customers of excess deferred taxes resulting from the TCJA, the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a correlating reduction to revenue.

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Rate Matters (Details) $ in Millions			1 Months Ended			3 Months Ended	12 Months Ended
		Apr. 13, 2018 USD ($)	Feb. 28, 2018 USD ($)	Oct. 31, 2017 USD ($) MW	Nov. 30, 2016 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
PUCT Proceeding - Texas 2017 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 55.0
Public Utilities, Requested Rate Increase (Decrease), Percentage							5.80%
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%
Public Utilities, Revised Requested Rate Increase							$ 55.0
Public Utilities, Revised Incremental revenue request							69.0
PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount										$ 42.0
NMPRC Proceeding - New Mexico 2016 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 41.0
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 | NMPRC Staff [Member] | New Mexico 2017 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Tax Cuts and Jobs Act of 2017, Estimated Electric Rate Reduction		$ (11.0)
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 43.0
Public Utilities, Recommended ROE, Percentage		9.00%
Public Utilities, Recommended Equity Capital Structure, Percentage		52.00%
Public Utilities, Requested Rate Increase (Decrease) Including TCJA Impact, Amount		$ 32.0
Public Utilities, Increase (Decrease) of Recommended ROE		(4.0)
Public Utilities, Increase (Decrease) of Recommended Capital Structure and Cost of Debt		(7.0)
Public Utilities, Increase (Decrease) from Recommended Accelerated Depreciation for Tolk Plant		(3.0)
Public Utilities, Increase (Decrease) Rate Case Expense Disallowance		(2.0)
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment		0.0
Public Utilities, Increase (Decrease) from Post Test Year Plant Adjustment		(1.0)
Public Utilities, Increase (Decrease) Other, net		(4.0)
Public Utilities, Total Recommended Rate Increase (Decrease)		11.0
Subsequent Event | New Mexico Attorney General (NMAG) [Member] | New Mexico 2017 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Tax Cuts and Jobs Act of 2017, Estimated Electric Rate Reduction		(11.0)
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 43.0
Public Utilities, Recommended ROE, Percentage		9.21%
Public Utilities, Recommended Equity Capital Structure, Percentage		53.97%
Public Utilities, Requested Rate Increase (Decrease) Including TCJA Impact, Amount		$ 32.0
Public Utilities, Increase (Decrease) of Recommended ROE		(6.0)
Public Utilities, Increase (Decrease) of Recommended Capital Structure and Cost of Debt		(3.0)
Public Utilities, Increase (Decrease) from Recommended Accelerated Depreciation for Tolk Plant		(3.0)
Public Utilities, Increase (Decrease) Rate Case Expense Disallowance		(3.0)
Public Utilities, Increase (Decrease) from Regional Transmission Revenue TCJA Adjustment		(3.0)
Public Utilities, Increase (Decrease) from Post Test Year Plant Adjustment		(2.0)
Public Utilities, Increase (Decrease) Other, net		(5.0)
Public Utilities, Total Recommended Rate Increase (Decrease)		$ 7.0
Transmission Cost Recovery Factory (TCRF) Rider | PUCT Proceeding - Texas 2017 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Rider Conversion to Base Rates	[1]						$ 14.0
SPS | New Mexico 2017 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Tax Cuts and Jobs Act of 2017, Estimated Electric Rate Reduction			$ 11.0
Public Utilities, Revised Requested Equity Capital Structure, Percentage			58.00%
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 43.0
Public Utilities, Requested Return on Equity, Percentage				10.25%
Public Utilities, Requested Rate Base, Amount				$ 885.0
Public Utilities, Decline in MW Sales from Wholesale Customers | MW				380
Public Utilities, Requested Equity Capital Structure, Percentage				53.97%
SPS | Public Utility Commission of Texas (PUCT) | PUCT Proceeding - Texas 2017 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Tax Cuts and Jobs Act of 2017, Estimated Electric Rate Reduction			$ 32.0
Public Utilities, Revised Requested Equity Capital Structure, Percentage			58.00%
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								$ 13.0
Public Utilities, Monthly Billed Charges For Transmission Service Upgrades						$ 0.5
Minimum [Member] | Subsequent Event | New Mexico 2017 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Recommended ROE, Percentage		9.00%
Public Utilities, Recommended Equity Capital Structure, Percentage		51.00%
Maximum [Member] | Subsequent Event | New Mexico 2017 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Recommended ROE, Percentage		9.21%
Public Utilities, Recommended Equity Capital Structure, Percentage		53.97%

[1] The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or 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	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	897	897
Purchase Power Agreement Expiration (year)	2041

XML

Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) - Other MGP, Landfill, or Disposal Sites [Domain] $ in Millions	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Site Contingency [Line Items]
Number of identified MGP sites under current investigation and/or remediation	1
Accrual for Environmental Loss Contingencies	$ 0.1	$ 0.0

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Amount outstanding at period end	$ 10,000,000	$ 0
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	0	13,000,000
Maximum amount outstanding	$ 1,000,000	$ 100,000,000
Weighted average interest rate, computed on a daily basis (percentage)	1.64%	1.12%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000,000	$ 400,000,000
Amount outstanding at period end	10,000,000	0
Average amount outstanding	4,000,000	69,000,000
Maximum amount outstanding	$ 28,000,000	$ 176,000,000
Weighted average interest rate, computed on a daily basis (percentage)	1.86%	1.13%
Weighted average interest rate at period end (percentage)	2.25%

XML

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 10,000	$ 0
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 2,000	$ 3,000
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 ($)		3 Months Ended
		Mar. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Credit Facility	[1]	$ 400,000,000
Drawn	[2]	12,000,000
Available		$ 388,000,000
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.

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Mar. 31, 2018 USD ($) MWh	Dec. 31, 2017 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		9
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		6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 9.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		21.00%
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		$ 13.2
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		28.00%
Credit Concentration Risk | External Credit Rating, Non 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		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 0.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		2.00%
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1]	6,386	4,251

[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
	Mar. 31, 2018	Mar. 31, 2017
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0
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	300,000	2,000,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ 500,000	$ (1,200,000)

XML

Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) - USD ($)	Mar. 31, 2018		Dec. 31, 2017
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	8,502,000		15,882,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	18,164,000		18,954,000
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	19,057,000		19,949,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,343,000		12,723,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,458,000)	[1]	(1,994,000)	[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	5,343,000		12,723,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,458,000)	[1]	(1,994,000)	[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	(1,458,000)	[1]	(1,994,000)	[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	(1,458,000)	[1]	(1,994,000)	[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	6,801,000		14,717,000
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	6,801,000		14,717,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,458,000		1,994,000
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	1,458,000		1,994,000
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	18,164,000	[3]	18,954,000	[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	19,057,000	[3]	19,949,000	[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	6,801,000		14,717,000
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	6,801,000		14,717,000
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	1,458,000		1,994,000
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	$ 1,458,000		$ 1,994,000

[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 March 31, 2018. At March 31, 2018, 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, 2017. At Dec. 31, 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.

[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
	Mar. 31, 2018	Mar. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 12,723,000	$ 1,955,000
Purchases	680,000	3,511,000
Settlements	(10,439,000)	(16,400,000)
Net gains recognized as regulatory assets and liabilities	2,379,000	12,126,000
Balance at end of period	5,343,000	1,192,000
Transfers into Level 3	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers out of Level 3	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,830,223	$ 1,829,941
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,901,350	$ 2,001,992

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Other Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Other Income and Expenses [Abstract]
Other Nonoperating Income	$ 2	$ 0
Other Nonoperating Expense	0	(2)
Defined Benefit Plan, Non-service Costs	(636)	(749)
Interest Income (Expense), Nonoperating, Net	(58)	45
Insurance policy expense	(12)	(12)
Other (expense), net	$ (704)	$ (718)

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Jan. 31, 2018 USD ($) Plan	Mar. 31, 2018 USD ($)	Mar. 31, 2017 USD ($)
Pension Plan [Member]
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,430	$ 2,440
Interest cost		4,603	4,928
Expected return on plan assets		(7,082)	(6,971)
Amortization of prior service cost (credit)		(35)	0
Amortization of net loss (gain)		3,517	3,245
Net periodic benefit cost (credit)		3,433	3,642
Defined Benefit Plan Credits Not Recognized Due To Effects of Regulation		974	148
Net benefit cost (credit) recognized for financial reporting		4,407	3,790
Total contributions to the pension plans during the period	$ 8,000
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		279	219
Interest cost		410	415
Expected return on plan assets		(615)	(589)
Amortization of prior service cost (credit)		(101)	(100)
Amortization of net loss (gain)		(113)	(155)
Net periodic benefit cost (credit)		(140)	(210)
Defined Benefit Plan Credits Not Recognized Due To Effects of Regulation		0	0
Net benefit cost (credit) recognized for financial reporting		$ (140)	$ (210)

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ 2,130,363
Losses reclassified from net accumulated other comprehensive loss	31	$ 24
Accumulated other comprehensive loss at end of period	2,130,238
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	(776)	(678)
Losses reclassified from net accumulated other comprehensive loss	12	9
Net current period other comprehensive income	12	9
Accumulated other comprehensive loss at end of period	(764)	(669)
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(691)	(612)
Losses reclassified from net accumulated other comprehensive loss	19	15
Net current period other comprehensive income	19	15
Accumulated other comprehensive loss at end of period	(672)	(597)
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(1,467)	(1,290)
Losses reclassified from net accumulated other comprehensive loss	31	24
Net current period other comprehensive income	31	24
Accumulated other comprehensive loss at end of period	$ (1,436)	$ (1,266)

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Other Comprehensive Income (Reclassifications from AOCI) (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		$ (41,385)	$ (39,182)
Tax benefit		8,286	14,127
Total amounts reclassified, net of tax		31	24
Gains and Losses on Cash Flow Hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		12	9
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		15	15
Tax benefit		(3)	(6)
Total, net of tax		12	9
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]	15	15
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	24
Defined Benefit Pension and Postretirement Items
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total amounts reclassified, net of tax		19	15
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	24
Tax benefit		(5)	(9)
Total amounts reclassified, net of tax		$ 19	$ 15

[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.

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Revenues (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 441,893	$ 437,434
Alternative revenue and other	5,339	22,638
Total operating revenues	$ 447,232	460,072
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 285,484	290,170
Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	80,049	79,601
Retail | Commercial and industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	195,771	200,957
Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	9,664	9,612
Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	93,232	91,141
Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	55,646	54,178
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 7,531	$ 1,945