UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~Sept.~~June 30, ~~2017~~

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 ~~Oct.~~July 27, ~~2017~~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	2023
Item 4 —	Controls and Procedures	2426

PART II — OTHER INFORMATION
Item 1 —	Legal Proceedings	2527
Item 1A —	Risk Factors	2527
Item 6 —	Exhibits	2627

SIGNATURES		2728

Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

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

PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016			2018			2017			2018			2017
Operating revenues	$	551,623		$	554,926		$	1,491,491		$	1,386,210		$	481,338		$	479,796		$	928,570		$	939,868

Operating expenses
Electric fuel and purchased power	294,400			297,587			816,027			757,537			257,642			267,942			511,586			521,627
Operating and maintenance expenses	66,289			71,699			213,348			202,410			66,148			69,421			132,216			145,561
Demand side management expenses	4,236			5,663			11,802			12,279			4,779			3,691			8,937			7,566
Depreciation and amortization	47,548			42,026			144,781			123,250			49,579			46,815			97,995			97,233
Taxes (other than income taxes)	16,743			15,589			50,222			46,417			15,629			16,689			33,219			33,479
Total operating expenses	429,216			432,564			1,236,180			1,141,893			393,777			404,558			783,953			805,466

Operating income	122,407			122,362			255,311			244,317			87,561			75,238			144,617			134,402

Other income, net	285			137			452			563
Other expense, net													(782		)	(613		)	(1,486		)	(1,331		)
Allowance for funds used during construction — equity	2,453			2,632			6,457			7,348			3,201			1,869			6,618			4,004

Interest charges and financing costs
Interest charges — includes other financing costs of $625, $828, $1,781, and $2,461, respectively	21,444			23,343			66,128			67,350
Interest charges — includes other financing costs of $702, $581, $1,396, and $1,156, respectively													20,621			21,946			40,776			44,684
Allowance for funds used during construction — debt	(1,349		)	(1,422		)	(3,816		)	(4,146		)	(1,532		)	(1,128		)	(3,303		)	(2,467		)
Total interest charges and financing costs	20,095			21,921			62,312			63,204			19,089			20,818			37,473			42,217

Income before income taxes	105,050			103,210			199,908			189,024			70,891			55,676			112,276			94,858
Income taxes	37,269			34,864			71,710			65,944			12,440			20,314			20,726			34,441
Net income	$	67,781		$	68,346		$	128,198		$	123,080		$	58,451		$	35,362		$	91,550		$	60,417

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)


	Three Months Ended Sept. 30				Nine Months Ended Sept. 30				Three Months Ended June 30,				Six Months Ended June 30
	2017		2016		2017		2016		2018		2017		2018		2017
Net income	$	67,781	$	68,346	$	128,198	$	123,080	$	58,451	$	35,362	$	91,550	$	60,417

Other comprehensive income

Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost, net of tax of $9, $6, $27 and $19, respectively	16		12		46		35
Amortization of losses included in net periodic benefit cost, net of tax of $5, $9, $10 and $18, respectively									18		15		37		30

Derivative instruments:
Reclassification of losses to net income, net of tax of $6, $25, $18 and $74, respectively	10		44		29		129
Reclassification of losses to net income, net of tax of $4, $6, $7 and $12, respectively									12		10		24		19
Other comprehensive income	26		56		75		164		30		25		61		49
Comprehensive income	$	67,807	$	68,402	$	128,273	$	123,244	$	58,481	$	35,387	$	91,611	$	60,466

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)


	Nine Months Ended Sept. 30						Six Months Ended June 30
	2017			2016			2018			2017
Operating activities
Net income	$	128,198		$	123,080		$	91,550		$	60,417
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	144,664			123,820			98,128			97,126
Demand side management program amortization	1,255			1,255			837			837
Deferred income taxes	101,388			99,882			(2,306		)	48,099
Amortization of investment tax credits	(99		)	(160		)	(26		)	(66		)
Allowance for equity funds used during construction	(6,457		)	(7,348		)	(6,618		)	(4,004		)
Net derivative losses	47			203			31			31
Other	9			122
Other, net							(5		)	10
Changes in operating assets and liabilities:
Accounts receivable	(25,134		)	(22,160		)	(25,351		)	(12,210		)
Accrued unbilled revenues	(13,682		)	(18,307		)	2,329			(16,668		)
Inventories	(2,845		)	(1,491		)	7,915			5,411
Prepayments and other	19,361			24,172			671			7,028
Accounts payable	7,817			19,690			640			16,799
Net regulatory assets and liabilities	24,856			(18,480		)	46,163			(3,477		)
Other current liabilities	19,748			18,989			13,937			(2,896		)
Pension and other employee benefit obligations	(21,638		)	(15,606		)	(7,885		)	(21,946		)
Change in other noncurrent assets	(1,697		)	(537		)	4,397			(373		)
Change in other noncurrent liabilities	(18,690		)	3,916			(458		)	(2,351		)
Net cash provided by operating activities	357,101			331,040			223,949			171,767

Investing activities
Utility capital/construction expenditures	(400,957		)	(371,994		)	(478,352		)	(279,918		)
Proceeds from insurance recoveries	—			987
Allowance for equity funds used during construction	6,457			7,348			6,618			4,004
Investments in utility money pool arrangement	—			(75,000		)	(46,000		)	—
Repayments from utility money pool arrangement	—			75,000			111,000			—
Other	(493		)	(1,174		)
Other, net							—			(493		)
Net cash used in investing activities	(394,993		)	(364,833		)	(406,734		)	(276,407		)

Financing activities
Proceeds from short-term borrowings, net	(50,000		)	(15,000		)	132,000			56,000
Proceeds from issuance of long-term debt, net	442,651			296,152
Borrowings under utility money pool arrangement	323,000			505,000			180,000			572,000
Repayments under utility money pool arrangement	(323,000		)	(505,000		)	(80,000		)	(511,000		)
Capital contributions from parent	45,000			16,225			360			45,000
Repayment of long-term debt, including reacquisition premiums	(271,613		)	—
Repayment of long-term debt							—			(18		)
Dividends paid to parent	(82,599		)	(57,570		)	(60,008		)	(57,585		)
Other, net							(31		)	—
Net cash provided by financing activities	83,439			239,807			172,321			104,397

Net change in cash and cash equivalents	45,547			206,014			(10,464		)	(243		)
Cash and cash equivalents at beginning of period	844			834			10,871			844
Cash and cash equivalents at end of period	$	46,391		$	206,848		$	407		$	601

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(58,581	)	$	(47,787	)	$	(36,680	)	$	(40,450	)
Cash received for income taxes, net	37,899			49,402
Cash (paid) received for income taxes, net							(7,560		)	17,213
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	40,861		$	25,445		$	43,286		$	34,529

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

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


	Sept. 30, 2017			Dec. 31, 2016			June 30, 2018			Dec. 31, 2017
Assets
Current assets
Cash and cash equivalents	$	46,391		$	844		$	407		$	10,871
Accounts receivable, net	96,614			74,190			102,379			79,581
Accounts receivable from affiliates	3,737			949			4,764			1,297
Investments in utility money pool arrangement							—			65,000
Accrued unbilled revenues	133,100			119,418			127,475			129,804
Inventories	41,350			38,505			32,518			40,433
Regulatory assets	38,021			38,721			26,093			31,538
Derivative instruments	23,597			5,114			38,549			15,882
Prepaid taxes	3,233			21,779			15,710			15,025
Prepayments and other	7,040			7,855			10,219			10,341
Total current assets	393,083			307,375			358,114			399,772

Property, plant and equipment, net	4,947,114			4,695,819			5,434,187			5,095,609

Other assets
Regulatory assets	343,685			346,683			360,902			362,943
Derivative instruments	19,743			22,113			17,374			18,954
Other	12,193			7,477			3,710			11,266
Total other assets	375,621			376,273			381,986			393,163
Total assets	$	5,715,818		$	5,379,467		$	6,174,287		$	5,888,544

Liabilities and Equity
Current liabilities
Short-term debt	$	—		$	50,000		$	132,000		$	—
Borrowings under utility money pool arrangement							100,000			—
Accounts payable	183,437			176,157			184,825			211,756
Accounts payable to affiliates	11,935			14,414			15,036			22,577
Regulatory liabilities	70,355			41,577			123,303			68,835
Taxes accrued	56,386			39,742			51,965			35,243
Accrued interest	21,430			19,162			23,413			23,275
Dividends payable	26,166			30,870			30,697			26,753
Derivative instruments	3,565			3,565			3,565			3,565
Other	27,723			29,703			26,019			29,641
Total current liabilities	400,997			405,190			690,823			421,645

Deferred credits and other liabilities
Deferred income taxes	1,090,921			989,137			577,492			574,906
Regulatory liabilities	222,956			233,454			781,917			784,564
Asset retirement obligations	29,808			28,663			29,279			28,524
Derivative instruments	20,840			23,513			18,166			19,949
Pension and employee benefit obligations	86,291			107,872			82,326			90,266
Other	8,307			24,084			4,630			8,386
Total deferred credits and other liabilities	1,459,123			1,406,723			1,493,810			1,506,595

Commitments and contingencies
Capitalization
Long-term debt	1,829,965			1,635,858			1,830,508			1,829,941
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively	—			—
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2018 and Dec. 31, 2017, respectively							—			—
Additional paid in capital	1,489,882			1,446,223			1,591,366			1,590,242
Retained earnings	537,066			486,763			569,186			541,588
Accumulated other comprehensive loss	(1,215		)	(1,290		)	(1,406		)	(1,467		)
Total common stockholder’s equity	2,025,733			1,931,696			2,159,146			2,130,363
Total liabilities and equity	$	5,715,818		$	5,379,467		$	6,174,287		$	5,888,544

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of ~~Sept.~~June 30, ~~2017~~2018 and Dec. 31, ~~2016;~~2017; the results of its operations, including the components of net income and comprehensive income, for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~2016;~~2017; and its cash flows for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~2016.~~2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after ~~Sept.~~June 30, ~~2017~~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, ~~2016~~2017 balance sheet information has been derived from the audited ~~2016~~2017 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, ~~2016.~~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, ~~2016,~~2017, filed with the SEC on Feb. ~~24, 2017.~~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, ~~2016,~~2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.


2.	Accounting Pronouncements

Recently Issued

~~Revenue Recognition~~Leases — —I ~~In May 2014,~~n February 2016, the Financial Accounting Standards Board (FASB) issued ~~Revenue from Contracts with Customers,~~Leases, Topic ~~606~~842 (Accounting Standards Update (ASU) ~~No. 2014-09)~~, which provides a new framework for the recognition of revenue. SPS expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. SPS currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

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

~~Leases —~~I~~n February 2016, the FASB issued~~ ~~Leases, Topic 842 (ASU~~ No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. SPS has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the ~~standard. As such, agreements entered prior to~~standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). On Jan. 1, ~~2017 that are currently~~2019 agreements considered leases ~~are expected to be recognized on~~for the ~~balance sheet, including contracts for~~ use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for ~~natural gas-fueled~~fossil-fueled generating ~~facilities.~~facilities are expected to be recognized on the balance sheet.

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 ~~expects that similar agreements entered~~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 to the financial statements.

Classification and Measurement of Financial Instruments — In January 2016, ~~will generally qualify as leases under~~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, ~~but has~~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 ~~yet completed~~have a material impact on its ~~evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.~~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. ~~SPS expects that as~~As a result of the application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the ~~current~~historical ratemaking treatment, and ~~that~~ the impacts of adoption will be limited to changes in classification of non-service costs in the statement of income. ~~This~~SPS implemented the new guidance ~~will be effective~~on Jan. 1, 2018, and as a result, $1.5 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the income statement for ~~interim and annual reporting~~the six months ended June 30, 2017. Under a practical expedient permitted by the standard, SPS used benefit cost amounts disclosed for prior periods ~~beginning after Dec. 15, 2017.~~as the basis for retrospective application.


3.	Selected Balance Sheet Data


(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016			June 30, 2018			Dec. 31, 2017
Accounts receivable, net
Accounts receivable	$	103,704		$	80,569		$	107,990		$	85,929
Less allowance for bad debts	(7,090		)	(6,379		)	(5,611		)	(6,348		)
	$	96,614		$	74,190		$	102,379		$	79,581


(Thousands of Dollars)	Sept. 30, 2017		Dec. 31, 2016		June 30, 2018		Dec. 31, 2017
Inventories
Materials and supplies	$	26,877	$	25,453	$	25,416	$	26,218
Fuel	14,473		13,052		7,102		14,215
	$	41,350	$	38,505	$	32,518	$	40,433


(Thousands of Dollars)	Sept. 30, 2017			Dec. 31, 2016			June 30, 2018			Dec. 31, 2017
Property, plant and equipment, net
Electric plant	$	6,653,228		$	6,362,189		$	7,059,344		$	6,765,371
Construction work in progress	312,445			260,327			447,945			351,875
Total property, plant and equipment	6,965,673			6,622,516			7,507,289			7,117,246
Less accumulated depreciation	(2,018,559		)	(1,926,697		)	(2,073,102		)	(2,021,637		)
	$	4,947,114		$	4,695,819		$	5,434,187		$	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, ~~2016~~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:



	Six Months Ended June 30
	2018		2017
Federal statutory rate	21.0	%	35.0	%
State tax, net of federal tax effect	2.4		2.2
Increases (decreases) in tax from:
Regulatory differences - ARAM ^(a)	(4.2	)	—
Regulatory differences - ARAM ^(b)	1.3		—
Regulatory differences - other utility plant items	(1.4	)	(0.8	)
Tax credits, net of federal income tax expense	(0.7	)	(0.5	)
Other, net	0.1		0.4
Effective income tax rate	18.5	%	36.3	%


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


^(b)	As we receive direction from our regulatory commissions regarding the return of excess deferred taxes (to our customers resulting from the Tax Cuts and Jobs Act

(TCJA)), the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding 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~~statutes of limitations applicable to Xcel Energy’s ~~2009 through 2011 and 2012 through 2013~~ federal income tax returns ~~following extensions, expires in June 2018 and October 2018, respectively.~~expire as follows:



Tax Year(s)		Expiration
2009 - 2011		December 2018
2012 - 2014		October 2019
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 claims ~~that would have resulted~~and in ~~$14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of~~ 2015 the IRS forwarded the issue to the Office of Appeals (Appeals). In ~~the third quarter of~~ 2017 Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. SPS did not accrue any income tax benefit related to this adjustment. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

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~~As of June 30, 2018 the ~~issue will be~~case has been forwarded to ~~Appeals. As of Sept. 30, 2017,~~Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, ~~2017,~~2018, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. ~~In 2016, Texas began an audit of years 2009 and 2010, and in September 2017, began an audit of 2011. As of Sept. 30, 2017, Texas had not proposed any material adjustments and there were~~There are currently no ~~other~~ state income tax audits in progress.

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

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


(Millions of Dollars)	Sept. 30, 2017		Dec. 31, 2016		June 30, 2018		Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions	$	5.2	$	4.5	$	2.5	$	2.3
Unrecognized tax benefit — Temporary tax positions	5.1		24.2		1.6		2.0
Total unrecognized tax benefit	$	10.3	$	28.7	$	4.1	$	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)	Sept. 30, 2017			Dec. 31, 2016			June 30, 2018			Dec. 31, 2017
NOL and tax credit carryforwards	$	(5.8	)	$	(5.9	)	$	(6.6	)	$	(5.9	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and ~~audits resume, the Texas~~ audit ~~progresses,~~resumes and ~~other~~ state audits resume. As the IRS Appeals progresses and ~~Texas~~the IRS audit ~~progress,~~resumes, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $7$3 million.

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

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

at June 30, 2018 and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of ~~Sept.~~June 30, ~~2017~~2018 or Dec. 31, ~~2016.~~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, ~~2016~~2017 and in Note 5 to the financial statements included in to SPS’ Quarterly Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2017 and June 30, 2017,~~2018, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

~~Pending~~Tax Reform — Regulatory Proceedings

The specific impacts of the 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.

Texas — In June 2018, SPS, the Public Utility Commission of Texas (PUCT) Staff and various intervenors reached a settlement in the Texas electric rate case which included the impacts of the TCJA. The settlement reflects no change in customer rates or refunds and SPS’ actual capital structure, which SPS has informed the parties it intends to be a 57 percent equity ratio to offset the negative impacts on its credit metrics and potentially its credit ratings.

New Mexico— In February 2018, SPS 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.

Pending Regulatory Proceedings — PUCT

Texas 2017 Electric Rate Case — In 2017, SPS filed a $54 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 request also reflects the acceleration of depreciation lives for the two generating units at the Tolk Generating Station from 2042 and 2045 to 2032.

In May 2018, SPS filed rebuttal testimony and revised its request to an overall increase in the annual base rate revenue of approximately $32 million, or 5.9 percent, net of the TCJA (approximately $32 million after adjusting for a 58 percent equity ratio)

and other adjustments. This request would be equivalent to approximately $17 million after adjusting for the Transmission Cost Recovery Factor (TCRF) rider.

In June 2018, SPS, the PUCT Staff and various intervenors reached a settlement, which results in no overall change to SPS’ revenues after adjusting for the impact of the TCJA and the lower costs of long-term debt.

The following are key terms:

The ability to use an equity ratio that reflects SPS' actual capital structure, which SPS has informed the parties it intends to be 57 percent to mitigate the impact of TCJA on credit metrics;

A 9.5 percent ROE for the calculation of allowance for funds used during construction (AFUDC);

TCRF rider will remain in effect;

SPS will accelerate depreciation rates for the Tolk Generating Station Units 1 and 2 by 50 percent of the original request; and

SPS agrees that it will file its next base rate case no later than Dec. 31, 2019.

A reconciliation of the settlement is as follows:



(Millions of Dollars)
Original base rate request	$	69
Base rate revenue to be recovered through TCRF	(15		)
Net revenue request	54
Adjustment for TCJA and other items	(37		)
Requested incremental revenue	17
Unspecified settlement adjustments	(13		)
Accelerated depreciation (Tolk plant)	(4		)
SPS' net revenue change	$	—

Under the terms of the settlement, the final rates would not change from the current rates. However, SPS would be permitted to surcharge customers for unrecovered TCRF charges that were not billed during the period of Jan. 23, 2018 through June 10, 2018. A PUCT decision is expected in the third 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 ~~$42.1~~$42 million. In 2015, the PUCT approved an overall rate decrease of approximately ~~$4.0~~$4 million, net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court of(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.~~order. In ~~March~~ 2017, the ~~Travis County~~ District Court denied SPS’ ~~appeal. In April 2017,~~appeal, and SPS appealed the District Court’s decision to the state Court of ~~Appeals.~~

~~Texas 2017 Electric Rate Case~~ —Appeals for the 7th Circuit. In ~~August 2017, SPS filed a $66.4 million, or 7.1 percent, retail electric, non-fuel base rate increase case in Texas with each~~2018, the Court of ~~its Texas municipalities and~~Appeals upheld the ~~PUCT. The request was based~~District Court’s decision on the ~~12-month period ended June 30,~~PUCT’s order, rejecting SPS’ appeal. As part of the settlement of the 2017 ~~with the final three months based on estimates, a requested return on equity (ROE) of 10.25 percent, a~~ Texas ~~retail electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.~~

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

~~The following table summarizes SPS’ revised rate increase request:~~

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


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

~~Key dates in the procedural schedule are as follows:~~

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

~~PUCT Staff direct testimony — March 1, 2018;~~

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

~~SPS’ rebuttal testimony — March 23, 2018;~~

~~Hearings — April 10 - 20, 2018; and~~

~~Statutory deadline — Aug. 31, 2018.~~

~~The final rates are expected~~SPS has agreed to ~~be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the third quarter of 2018.~~end its appeal.

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

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $43 million. The request was based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent, a 35 percent federal income tax rate and a rate base of approximately $885 million, including rate base additions through Nov. 30, 2017.

In May 2018, SPS reduced its request to $27 million, net of the TCJA (approximately $11 million) and other

adjustments, based on a requested ROE of 10.25 percent and an equity ratio of 58.0 percent.

In June 2018, the New Mexico Hearing Examiner issued a recommended decision proposing an increase of $12 million based on a ROE of 9.4 percent and an equity ratio of 53.97 percent. She also denied SPS' requests to shorten depreciation lives related to Tolk Units 1 and 2 and Cunningham Unit 1. The Hearing Examiner rejected intervenor proposals to refund the impacts of the TCJA back to Jan. 1, 2018.

The following table summarizes certain parties’ proposed modifications to SPS’ request, SPS’ revised request, and the Hearing Examiner’s recommendation:



(Millions of Dollars)	NMPRC Staff Testimony			NMAG Testimony			SPS Rebuttal Testimony			Hearing Examiner's Recommendation
SPS request	$	43		$	43		$	43		$	43
Reduction to request for the impact of the TCJA	(11		)	(11		)	(11		)	(11		)
SPS request, including the impact of the TCJA	32			32			32			32

ROE	(4		)	(6		)	—			(5		)
Capital structure	(7		)	(3		)	—			(3		)
Depreciation lives (Tolk and Cunningham plants)	(3		)	(3		)	—			(3		)
Disallow rate case expenses	(2		)	(3		)	(1		)	—
Regional transmission revenue and expense (adjustment for the impact of the TCJA):
Impact of the TCJA	—			(3		)	—			(1		)
Aligning costs with transmission plant in rate base	—			—			—			(1		)
Post test year plant (updated to actual)	(1		)	(2		)	(3		)	—
Excess generation adjustment	—			(1		)	—			(1		)
Other, net	(4		)	(4		)	(1		)	(6		)
Recommended rate increase	$	11		$	7		$	27		$	12

ROE	9.0		%	9.21		%	10.25		%	9.4		%
Equity ratio	52.0		%	53.97		%	58.0		%	53.97		%

SPS anticipates a decision and implementation of final rates in the third quarter 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 ~~$41.4~~$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 ~~April~~ 2017, the NMPRC dismissed SPS’ rate case. ~~In May 2017,~~ SPS filed a notice of appeal toin the New Mexico Supreme Court. A decision ~~from the New Mexico Supreme Court~~ is not expected until the second ~~or third quarter~~half of ~~2018.~~

~~SPS plans to file another base rate case by November 2017 utilizing a historic test year ending June 2017.~~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,~~participant funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades. In ~~July~~ 2016, the FERC granted SPP’s request ~~for a waiver to allow SPP~~ to recover the charges not billed since 2008. ~~In November 2016,~~ SPP subsequently billed SPS ~~a net amount, for the period from 2008 through August 2016, of $12.8~~approximately $13 million for these ~~charges, to be paid over a five-year period commencing November 2016.~~charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. OnIn November 2017, the ~~retail level, in October 2016,~~FERC denied an SPS request for rehearing. In January 2018, SPS appealed the FERC request to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). SPS has filed ~~applications for deferred accounting and future recovery of related costs in New Mexico and Texas. In December 2016, SPS’ New Mexico application was consolidated with its base rate case, but~~to recover the ~~NMPRC dismissed that rate case in April 2017. SPS will seek recovery of these~~ SPP charges ~~in its next New Mexico base rate case by November 2017. In March 2017, SPS withdrew its Texas application and~~as part of the appeal. The appeal is ~~now seeking to recover these SPP charges in its pending rate case filed in August 2017.~~currently pending.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed ~~on and after November 2016~~ asserting that SPP has assessed upgrade charges to SPS ~~even where SPS’ transmission service was not dependent upon the upgrade as required by~~in violation of the SPP OATT. In March 2018, the FERC denied SPS’ complaint. SPS sought rehearing in April 2018, and the FERC approved the rehearing request for further consideration on May 7, 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings. ~~Also in October 2017, SPP made adjustments to its previous calculations of upgrade charges to SPP customers, and the impact was immaterial to SPS.~~


6.	Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10 and 11 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, ~~2016,~~2017 and in Notes 5 and 6 to the financial statements included in SPS’ Quarterly Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2017 and June 30, 2017,~~2018, 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~~Megawatts (MW) of capacity under long-term PPAs as of ~~Sept.~~June 30, ~~2017~~2018 and Dec. 31, ~~2016,~~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 various expiration dates through 2041.

Environmental Contingencies

~~Environmental Requirements~~

~~Water~~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 ~~Waste~~

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

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

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

~~Air~~

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

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

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

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

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

~~BART Determinations for Texas:~~ Texas developed a State Implementation Plan (SIP) that found the CAIR equal to BART for electric generating units. As a result, no additional controls beyond CAIR compliance would have been required. In 2014, the EPA proposed to approve the BARTsome portion of the ~~SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016,~~investigation and/or remediation activities. SPS anticipates that the EPA adopted a final rule that deferred its approval of CSAPR compliance as BART until the EPA considered further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO₂~~emission budgets. The EPA then published a proposed rule in January 2017 that could have had the effect of requiring installation of dry scrubbers to reduce SO~~₂ emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could have been approximately $400 million. In September 2017, the EPA issued a final rule adopting a Texas only SO₂ ~~trading program as a BART Alternative. The program allocated SO~~₂ allowances to electric generating units in Texas, including all three Harrington units and both Tolk units, consistent with their allocation under CSAPR, resulting in an emissions budget for Texas that is consistent with the EPA’s 2012 rule.investigation or remediation activities will continue through at least 2018. SPS ~~expects the allowance allocations to be sufficient for SO~~₂ emissions from Harrington and Tolk units in 2019 and future years. The anticipated costs of compliance are not expected to have a material impact on the results of operations, financial position or cash flows; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

~~Reasonable Progress Rule:~~ ~~In January 2016, the EPA adopted a final rule establishing a federal implementation plan~~accrued $0.1 million for the ~~state~~site as of ~~Texas, which imposed SO~~₂ ~~emission limitations~~June 30, 2018 and Dec. 31, 2017, respectively. There may be insurance recovery and/or recovery from other potentially responsible parties that ~~reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment~~will offset any costs ~~associated with dry scrubbers could~~incurred. SPS anticipates that any amounts spent will be approximately $600 million. SPS appealed the EPA’s decision and requested a stay of the final rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the case in abeyance until the EPA completes its reconsideration of the rule. In the final BART rule that affects Tolk and Harrington described above, the EPA noted that it will address the remanded rule in a future action. Such a rule will address whether further SOfully recovered from customers.₂ emission reductions are needed at Tolk to address the “reasonable progress” requirements of the regional haze program. The risk of these controls being imposed along with the risk of investments to provide additional cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units.

Legal Contingencies

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on SPS’ financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

7. Borrowings and Other Financing Instruments


7.	~~Borrowings and Other Financing Instruments~~

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2017			Year Ended Dec. 31, 2016			Three Months Ended June 30, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	100		$	100		$	100		$	100
Amount outstanding at period end	—			—			100			—
Average amount outstanding	37			28			24			13
Maximum amount outstanding	100			100			100			100
Weighted average interest rate, computed on a daily basis	1.10		%	0.67		%	1.84		%	1.12		%
Weighted average interest rate at period end	N/A			N/A			1.85			N/A

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


(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2017			Year Ended Dec. 31, 2016			Three Months Ended June 30, 2018			Year Ended Dec. 31, 2017
Borrowing limit	$	400		$	400		$	400		$	400
Amount outstanding at period end	—			50			132			—
Average amount outstanding	36			43			32			69
Maximum amount outstanding	106			140			140			176
Weighted average interest rate, computed on a daily basis	1.37		%	0.67		%	2.25		%	1.13		%
Weighted average interest rate at period end	N/A			0.95			2.29			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 ~~Sept.~~June 30, ~~2017~~2018 and Dec. 31, ~~2016,~~2017, there were $2 million and $5$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 ~~Sept.~~June 30, ~~2017,~~2018, SPS had the following committed credit facility available (in millions of dollars):


Credit Facility ^(a)	Credit Facility ^(a)	Drawn ^(b)		Available		Credit Facility ^(a)	Drawn ^(b)		Available
$	400	$	3	$	397	400	$	134	$	266


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


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

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding as of ~~Sept.~~June 30, ~~2017~~2018 and Dec. 31, ~~2016.~~

~~Long-Term Borrowings~~

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

~~Debt Redemption~~

On Aug. 30, 2017, SPS reacquired $250 million of debt with a coupon rate of 8.75 percent and an original maturity date of Dec. 1, 2018. The redemption resulted in payment of an early redemption premium of $21.6 million which was deferred as a regulatory asset.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 (NAV).~~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 ~~Southwest Power Pool Inc. (SPP).~~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~~is insignificant to the financial statements of SPS.

Derivative Instruments Fair Value Measurements

SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.

As of ~~Sept.~~June 30, ~~2017,~~2018, accumulated other comprehensive losses related to interest rate derivatives included an immaterial ~~amount of~~ net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments, including derivatives. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations. This could include the purchase or sale of energy or energy-related products and FTRs.

The following table details the gross notional amounts of commodity FTRs as of ~~Sept.~~June 30, ~~2017~~2018 and Dec. 31, ~~2016:~~2017:


(Amounts in Thousands) ^(a)	Sept. 30, 2017	Dec. 31, 2016	June 30, 2018	Dec. 31, 2017
Megawatt hours of electricity	6,183	2,685	12,941	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 each of the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~$0.1 million and $0.2 million for the three and nine months ended Sept. 30, 2016.~~2017.

During the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017,~~2018, changes in the fair value of FTRs resulted in pre-tax net ~~losses~~gains of ~~$2.5~~$13.0 million and ~~$0.2~~$13.4 million, respectively, and were recognized as regulatory assets and liabilities. For the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2016,~~2017, changes in the fair value of FTRs resulted in pre-tax net gains of $0.2 million and ~~$2.0~~$2.3 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~~gains of ~~$2.2~~$3.9 million and ~~gains of $0.1~~$3.4 million were recognized for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017,~~2018, respectively, and were recorded to electric fuel and purchased power. For the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2016,~~2017, FTR settlement ~~losses~~gains of ~~$0.4~~$1.2 million and ~~$3.7~~$2.4 million, respectively, were recognized and recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~2016.~~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 ~~Sept.~~June 30, ~~2017, two~~2018, six of SPS’ most significant counterparties, ~~for these activities,~~ comprising ~~$15.3~~$25.7 million or ~~33 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Five of the most significant counterparties, comprising $9.2 million or 20~~50 percent of this credit exposure, were not rated by Standard & Poor’s, Moody’s or Fitch Ratings, but based on SPS’ internal analysis, had credit quality consistent with investment grade. The one remaining significant counterparty, comprising $0.2 million or less than 1 percent of this credit exposure, had credit quality less than investment grade, based on ~~SPS’~~ratings from internal analysis. All ~~eight~~seven of these significant counterparties are municipal or cooperative electric entities or other utilities.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis as of ~~Sept.~~June 30, ~~2017:~~2018:


	Sept. 30, 2017														June 30, 2018
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value							Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total				Level 1		Level 2		Level 3				Total			Counterparty Netting ^(b)
Current derivative assets							Fair Value Total
Other derivative instruments:										Counterparty Netting ^(b)												Fair Value Total
Electric commodity	$	—	$	—	$	23,018	$	23,018		$	(2,580	)	$	20,438	$	—	$	—	$	35,897		$	35,897	$	(508	)	$	35,389
Total current derivative assets	$	—	$	—	$	23,018	$	23,018		$	(2,580	)	20,438		$	—	$	—	$	35,897		$	35,897	$	(508	)	35,389
PPAs ^(a)													3,159														3,160
Current derivative instruments													$	23,597													$	38,549
Noncurrent derivative assets
PPAs ^(a)													$	19,743													$	17,374
Noncurrent derivative instruments													$	19,743													$	17,374
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,580	$	2,580		$	(2,580	)	$	—	$	—	$	—	$	508		$	508	$	(508	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,580	$	2,580		$	(2,580	)	—		$	—	$	—	$	508		$	508	$	(508	)	—
PPAs ^(a)													3,565														3,565
Current derivative instruments													$	3,565													$	3,565
Noncurrent derivative liabilities
PPAs ^(a)													$	20,840													$	18,166
Noncurrent derivative instruments													$	20,840													$	18,166


^(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~~is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at ~~Sept.~~June 30, ~~2017.~~2018. At ~~Sept.~~June 30, ~~2017,~~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, ~~2016:~~2017:


	Dec. 31, 2016														Dec. 31, 2017
	Fair Value						Fair Value Total			Counterparty Netting ^(b)					Fair Value							Fair Value Total		Counterparty Netting ^(b)
(Thousands of Dollars)	Level 1		Level 2		Level 3				Total				Level 1		Level 2		Level 3				Total			Counterparty Netting ^(b)
Current derivative assets							Fair Value Total
Other derivative instruments:										Counterparty Netting ^(b)												Fair Value Total
Electric commodity	$	—	$	—	$	3,254	$	3,254		$	(1,299	)	$	1,955	$	—	$	—	$	14,717		$	14,717	$	(1,994	)	$	12,723
Total current derivative assets	$	—	$	—	$	3,254	$	3,254		$	(1,299	)	1,955		$	—	$	—	$	14,717		$	14,717	$	(1,994	)	12,723
PPAs ^(a)													3,159														3,159
Current derivative instruments													$	5,114													$	15,882
Noncurrent derivative assets
PPAs ^(a)													$	22,113													$	18,954
Noncurrent derivative instruments													$	22,113													$	18,954
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,299	$	1,299		$	(1,299	)	$	—	$	—	$	—	$	1,994		$	1,994	$	(1,994	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,299	$	1,299		$	(1,299	)	—		$	—	$	—	$	1,994		$	1,994	$	(1,994	)	—
PPAs ^(a)													3,565														3,565
Current derivative instruments													$	3,565													$	3,565
Noncurrent derivative liabilities
PPAs ^(a)													$	23,513													$	19,949
Noncurrent derivative instruments													$	23,513													$	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~~is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)

SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, ~~2016.~~2017. At Dec. 31, ~~2016,~~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 and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~2016:~~2017:



	Three Months Ended Sept. 30						Three Months Ended June 30,
(Thousands of Dollars)	2017			2016			2018			2017
Balance at July 1	$	28,665		$	1,070
Balance at April 1							$	5,343		$	1,192
Purchases	43			274			18,668			35,822
Settlements	(9,939		)	(7,822		)	(14,798		)	(14,098		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	1,669			6,614			26,176			5,749
Balance at Sept. 30	$	20,438		$	136
Balance at June 30							$	35,389		$	28,665



	Nine Months Ended Sept. 30						Six Months Ended June 30
(Thousands of Dollars)	2017			2016			2018			2017
Balance at Jan. 1	$	1,955		$	5,060		$	12,723		$	1,955
Purchases	39,376			5,426			19,348			39,333
Settlements	(40,437		)	(22,438		)	(25,237		)	(30,498		)
Net transactions recorded during the period:
Net gains recognized as regulatory assets and liabilities	19,544			12,088			28,555			17,875
Balance at Sept. 30	$	20,438		$	136
Balance at June 30							$	35,389		$	28,665

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~2016.~~2017.

Fair Value of Long-Term Debt

As of ~~Sept.~~June 30, ~~2017~~2018 and Dec. 31, ~~2016,~~2017, other financial instruments for which the carrying amount did not equal fair value were as follows:


	Sept. 30, 2017				Dec. 31, 2016				June 30, 2018				Dec. 31, 2017
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,829,965	$	1,954,618	$	1,635,858	$	1,741,502	$	1,830,508	$	1,858,497	$	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 ~~Sept.~~June 30, ~~2017~~2018 and Dec. 31, ~~2016,~~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 ~~Income,~~Expense, Net

Other ~~income,~~expense, net consisted of the following:


	Three Months Ended Sept. 30						Nine Months Ended Sept. 30						Three Months Ended June 30						Six Months Ended June 30
(Thousands of Dollars)	2017			2016			2017			2016			2018			2017			2018			2017
Interest income	$	296		$	400		$	488		$	579		$	356		$	147		$	298		$	192
Other nonoperating income	1			—			—			16			1			1			3			—
Other nonoperating expense													—			—			—			(1		)
Insurance policy expense	(12		)	(32		)	(36		)	(32		)	(12		)	(12		)	(24		)	(24		)
Other nonoperating expense	—			(231		)	—			—
Other income, net	$	285		$	137		$	452		$	563
Benefits non-service cost													(1,127		)	(749		)	(1,763		)	(1,498		)
Other expense, net													$	(782	)	$	(613	)	$	(1,486	)	$	(1,331	)


10.	Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)


	Three Months Ended Sept. 30												Three Months Ended June 30
	2017			2016			2017			2016			2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,439		$	2,440		$	219		$	194		$	2,430		$	2,440		$	280		$	219
Interest cost(a)	4,928			5,315			415			455			4,602			4,927			411			415
Expected return on plan assets(a)	(6,971		)	(6,901		)	(589		)	(594		)	(7,082		)	(6,971		)	(616		)	(589		)
Amortization of prior service credit(a)	—			—			(100		)	(100		)	(34		)	—			(100		)	(100		)
Amortization of net loss (gain)(a)	3,245			2,997			(155		)	(146		)	3,517			3,245			(113		)	(155		)
Net periodic benefit cost (credit)	3,641			3,851			(210		)	(191		)	3,433			3,641			(138		)	(210		)
Credits not recognized due to the effects of regulation	553			637			—			—			761			574			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,194		$	4,488		$	(210	)	$	(191	)	$	4,194		$	4,215		$	(138	)	$	(210	)



	Nine Months Ended Sept. 30												Six Months Ended June 30
	2017			2016			2017			2016			2018			2017			2018			2017
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits						Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,319		$	7,320		$	657		$	582		$	4,860		$	4,880		$	559		$	438
Interest cost	14,783			15,945			1,245			1,365
Expected return on plan assets	(20,913		)	(20,703		)	(1,767		)	(1,782		)
Amortization of prior service credit	—			—			(300		)	(300		)
Amortization of net loss (gain)	9,735			8,991			(465		)	(438		)
Interest cost ^(a)													9,205			9,855			821			830
Expected return on plan assets ^(a)													(14,164		)	(13,942		)	(1,231		)	(1,178		)
Amortization of prior service credit ^(a)													(69		)	—			(201		)	(200		)
Amortization of net loss (gain) ^(a)													7,034			6,490			(226		)	(310		)
Net periodic benefit cost (credit)	10,924			11,553			(630		)	(573		)	6,866			7,283			(278		)	(420		)
Credits not recognized due to the effects of regulation	1,275			1,353			—			—			1,735			722			—			—
Net benefit cost (credit) recognized for financial reporting	$	12,199		$	12,906		$	(630	)	$	(573	)	$	8,601		$	8,005		$	(278	)	$	(420	)

^(a)The components of net periodic cost other than the service cost component are included in the line item “other expense, net” in the income statement or capitalized on the balance sheet as a regulatory asset.

In January ~~2017,~~2018, contributions of ~~$150.0~~$150 million were made across four of Xcel Energy’s pension plans, of which ~~$23.0~~$8.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during ~~2017.~~2018.


11.	Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive loss, net of tax, for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~2016~~2017 were as follows:


	Three Months Ended Sept. 30, 2017									Three Months Ended June 30, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(659	)	$	(582	)	$	(1,241	)
Accumulated other comprehensive loss at April 1										$	(764	)	$	(672	)	$	(1,436	)
Losses reclassified from net accumulated other comprehensive loss	10			16			26			12			18			30
Net current period other comprehensive income	10			16			26			12			18			30
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)
Accumulated other comprehensive loss at June 30										$	(752	)	$	(654	)	$	(1,406	)


	Three Months Ended Sept. 30, 2016									Three Months Ended June 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at July 1	$	(732	)	$	(441	)	$	(1,173	)
Other comprehensive income before reclassifications	—			12			12
Accumulated other comprehensive loss at April 1										$	(669	)	$	(597	)	$	(1,266	)
Losses reclassified from net accumulated other comprehensive loss	44			—			44			10			15			25
Net current period other comprehensive income	44			12			56			10			15			25
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)
Accumulated other comprehensive loss at June 30										$	(659	)	$	(582	)	$	(1,241	)


	Nine Months Ended Sept. 30, 2017									Six Months Ended June 30, 2018
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(678	)	$	(612	)	$	(1,290	)	$	(776	)	$	(691	)	$	(1,467	)
Losses reclassified from net accumulated other comprehensive loss	29			46			75			24			37			61
Net current period other comprehensive income	29			46			75			24			37			61
Accumulated other comprehensive loss at Sept. 30	$	(649	)	$	(566	)	$	(1,215	)
Accumulated other comprehensive loss at June 30										$	(752	)	$	(654	)	$	(1,406	)


	Nine Months Ended Sept. 30, 2016									Six Months Ended June 30, 2017
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total			Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(817	)	$	(464	)	$	(1,281	)	$	(678	)	$	(612	)	$	(1,290	)
Other comprehensive income before reclassifications	—			35			35
Losses reclassified from net accumulated other comprehensive loss	129			—			129			19			30			49
Net current period other comprehensive income	129			35			164			19			30			49
Accumulated other comprehensive loss at Sept. 30	$	(688	)	$	(429	)	$	(1,117	)
Accumulated other comprehensive loss at June 30										$	(659	)	$	(582	)	$	(1,241	)

Reclassifications from accumulated other comprehensive loss for the three and ~~nine~~six months ended ~~Sept.~~June 30, ~~2017~~2018 and ~~2016~~2017 were as follows:

Amounts Reclassified from
Accumulated Other
Comprehensive Loss
(Thousands of Dollars) Three Months Ended Sept. 30, 2017 Three Months Ended Sept. 30, 2016
Losses on cash flow hedges:

Interest rate derivatives $ 16
^(a)
$ 69
^(a)
Total, pre-tax 16
69

Tax benefit (6 ) (25 )
Total, net of tax 10
44

Defined benefit pension and postretirement losses:
Amortization of net loss 24
^(b)
—
^(b)
Total, pre-tax 24
—

Tax benefit (8 ) —

Total, net of tax 16
—

Total amounts reclassified, net of tax $ 26
$ 44


	Amounts Reclassified from Accumulated Other Comprehensive Loss								Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2017				Nine Months Ended Sept. 30, 2016				Three Months Ended June 30, 2018				Three Months Ended June 30, 2017
Losses on cash flow hedges:
Interest rate derivatives	$	47		^(a)	$	203		^(a)	$	16		^(a)	$	16		^(a)
Total, pre-tax	47				203				16				16
Tax benefit	(18		)		(74		)		(4		)		(6		)
Total, net of tax	29				129				12				10
Defined benefit pension and postretirement losses:
Amortization of net loss	72			^(b)	—			^(b)	23			^(b)	24			^(b)
Total, pre-tax	72				—				23				24
Tax benefit	(26		)		—				(5		)		(9		)
Total, net of tax	46				—				18				15
Total amounts reclassified, net of tax	$	75			$	129			$	30			$	25

^(a)



	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2018				Six Months Ended June 30, 2017
Losses on cash flow hedges:
Interest rate derivatives	$	31		^(a)	$	31		^(a)
Total, pre-tax	31				31
Tax benefit	(7		)		(12		)
Total, net of tax	24				19
Defined benefit pension and postretirement losses:
Amortization of net loss	47			^(b)	48			^(b)
Total, pre-tax	47				48
Tax benefit	(10		)		(18		)
Total, net of tax	37				30
Total amounts reclassified, net of tax	$	61			$	49

^(a)Included in interest charges.

~~Included in interest charges.~~


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

12. Revenues

SPS principally generates revenue from the generation, 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 also 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 tables, regulated electric revenue is classified by the type of goods/services rendered and market/customer type.



	Three Months Ended
(Thousands of Dollars)	June 30, 2018		June 30, 2017
Major product lines
Revenue from contracts with customers:
Residential	$	85,107	$	84,188
Commercial and industrial (C&I)	200,760		215,805
Other	11,363		12,242
Total retail	297,230		312,235
Wholesale	115,629		101,893
Transmission	58,970		56,394
Other	2,858		2,065
Total revenue from contracts with customers	474,687		472,587
Alternative revenue and other	6,651		7,209
Total revenues	$	481,338	$	479,796



	Six Months Ended
(Thousands of Dollars)	June 30, 2018		June 30, 2017
Major product lines
Revenue from contracts with customers:
Residential	$	165,156	$	163,789
C&I	396,531		416,762
Other	21,027		21,854
Total retail	582,714		602,405
Wholesale	208,861		193,034
Transmission	114,616		110,572
Other	10,389		4,010
Total revenue from contracts with customers	916,580		910,021
Alternative revenue and other	11,990		29,847
Total revenues	$	928,570	$	939,868

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).

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements ~~are intended~~including the TCJA’s impact to beSPS 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”~~“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, ~~2016~~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;~~market; 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 operating and maintenance (O&M) expenses, demand side management (DSM) expenses, depreciation and amortization, and taxes (other than income taxes).

Results of Operations

SPS’ net income was approximately ~~$128.2~~$92 million for ~~2017~~2018 year-to-date, compared with approximately ~~$123.1~~$60 million for the same period in ~~2016~~.2017. The year-to-date increase ~~in electric margin was attributable to rate increases in Texas and New Mexico, partially offset by the impact of unfavorable weather. This increase~~ was largely ~~offset by higher depreciation expense and~~due to timing of O&M ~~expenses.~~

expenses, the favorable impact of weather, sales growth and lower interest expense.

Electric Revenues and Margin

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


	Nine Months Ended Sept. 30						Six Months Ended June 30
(Millions of Dollars)	2017			2016			2018			2017
Electric revenues	$	1,491		$	1,386
Electric revenues before impact of the TCJA							$	950		$	940
Electric fuel and purchased power	(816		)	(758		)	(516		)	(522		)
Electric margin before impact of the TCJA							$	434		$	418
Impact of the TCJA (offset as a reduction in income tax expense)							(17		)	—
Electric margin	$	675		$	628		$	417		$	418

The following tables summarize the components of the changes in electric revenues and electric margin for the ~~nine~~six months ended ~~Sept.~~June 30, ~~2017:~~2018:

Electric Revenues


(Millions of Dollars)	2017 vs 2016			2018 vs 2017
Retail rate increases (Texas, New Mexico)	$	53
Fuel and purchased power cost recovery	30			$	(53	)
Firm wholesale				(12		)
Trading				36
Wholesale transmission revenue	14			17
Demand revenue	9
Estimated impact of weather				11
Other, net	(1		)	11
Total increase in electric revenues	$	105
Total increase in electric revenues before impact of the TCJA				$	10
Impact of TCJA (offset as a reduction in income tax expense)				(21		)
Total decrease in electric revenues				$	(11	)

Electric Margin

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



(Millions of Dollars)	2018 vs 2017
Firm wholesale	$	(12	)
Estimated impact of weather	11
Wholesale transmission revenue, net of costs	7
Other, net	10
Total increase in electric margin before impact of the TCJA	$	16
Impact of TCJA (offset as a reduction in income tax expense)	(17		)
Total decrease in electric margin	$	(1	)

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses ~~increased $10.9~~decreased $13 million, or ~~5.4~~9.2 percent, for ~~2017~~2018 year-to-date. The ~~increase~~decrease primarily relates to ~~prior year deferrals associated with the Texas 2016 rate case, increases in employee benefits expense, and the~~ timing of O&M expenses, including planned maintenance and overhauls at various generation ~~facilities, as summarized in the table below:~~

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

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

Income Taxes — Income tax expense ~~increased $5.8~~decreased $14 million for ~~2017 year-to-date.~~the first six months of 2018 compared with the same period in 2017. The decrease was primarily driven by a lower federal tax rate due to the TCJA and an increase in ~~income tax expense was primarily due~~plant-related regulatory differences related to ~~higher pretax earnings and decreased tax benefit for adjustments attributable to the tax return filed in the third quarter.~~ARAM (net of deferrals). The ETR was ~~35.9~~18.5 percent for ~~2017 year-to-date,~~the first six months of 2018, compared with ~~34.9~~36.3 percent for the same period in ~~2016.~~2017. The ~~higher~~lower ETR in ~~2017 was~~2018 is primarily due to the ~~adjustment~~items referenced above. See Note 4 to the financial statements.

Interest Charges — Interest charges decreased $1 million, or 6.0 percent for the second quarter of 2018, and decreased $4 million, or 8.7 percent, year-to-date. The decrease was related to refinancing at lower interest rates, partially offset by higher debt levels to fund capital investments.

Public Utility Regulation

Except to the extent noted below and in Note 5 in the notes to the financial statements, the circumstances set forth in Public Utility Regulation included in Item 1 of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, ~~2016~~2017 and in Public Utility Regulation included in Item 2 of SPS’ Quarterly Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2017 and June 30, 2017,~~2018, appropriately represent, in all material respects, the current status of public utility regulation and are incorporated herein by reference.

~~Wind Development~~Texas State Right of First Refusal (ROFR) Request for Declaratory Order — ~~Xcel Energy plans to significantly expand its wind capacity by adding 1,230 MW of new wind generation at~~In February 2017, SPS ~~by the end of 2020. SPS has~~and SPP filed to own and place in rate base 1,000 MW of these wind projects, while 230 MW would be through PPAs. The PUCT and NMPRC are expected to rule on SPS’ wind projects by the end of the first quarter of 2018. Hearings in Texasa joint petition with the PUCT ~~are scheduled~~ for ~~Nov. 6 through Nov. 17, 2017. Hearings~~a declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility, operating in ~~New Mexico with~~areas outside of Electric Reliability Council of Texas, the ~~NMPRC are scheduled~~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 ~~Nov. 28 through Dec. 1, 2017.~~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.

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

~~The following table details these wind projects:~~

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

Bonita 230
TX 2019 PPA
Total PPA 230

Total Wind Capacity 1,230

case is being briefed.

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

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

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

~~The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a proceeding to determine whether~~Wind Proposals — In 2017, SPS filed proposals with the ~~proposed transfer is in the public interest~~NMPRC and ~~to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If~~ the PUCT ~~determines~~to build, own and operate 1,000 MW of new wind generation through two wind farms (the Hale wind project in Texas and the ~~transfer is~~Sagamore wind project in New Mexico) for a cost of approximately $1.6 billion. In addition, the ~~public interest,~~proposal includes a purchased power agreement for 230 MW of wind. SPS’ wind proposal was approved by both the ~~second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. The PUCT asked SPP~~NMPRC and ERCOT to perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPP and ERCOT filed the studies on June 30, 2017. In September 2017, LP&L filed its application with the PUCT for a public interest determination and proposed a transition date no later than June 2021. The PUCT issued a preliminary order setting out issues for the parties to address. A hearing on the matter is expected to be held in the first quarter of 2018 and a PUCT decision is expected in the second quarter ofduring 2018.

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

Summary of Recent Federal Regulatory Developments

FERC

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, ~~2016~~2017 and Quarterly Report on Form 10-Q for the quarterly ~~periods~~period ended March 31, ~~2017 and June 30, 2017.~~2018. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

~~Department~~Xcel Energy, which includes SPS, attempts to mitigate the risk of ~~Energy (DOE) Grid Resiliency Notice of Proposed Rule (NOPR)~~ ~~— In September 2017,~~regulatory penalties through formal training on

prohibited practices and a compliance function that reviews interaction with the ~~DOE requested the~~markets under FERC ~~consider~~ and ~~adopt a Grid Resiliency and Pricing Rule~~Commodity Futures Trading Commission jurisdictions. Public campaigns are conducted to ~~address threats to the U.S. electrical grid. The proposed DOE rule expands upon an August 2017 DOE grid study on the resiliency~~raise awareness of the ~~grid. Under~~public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the ~~proposed rule, coal and nuclear generation facilities would qualify for full recovery of their costs, which includes a fair rate of return, if they meet the following criteria:~~

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

~~Have 90 days of on-site fuel storage;~~

~~Provide essential energy and ancillary reliability services~~other measures will be sufficient to ~~the grid;~~

~~Are in compliance with all environmental mandates; and~~

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

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

~~North American Electric Reliability Corporation (NERC) Supply Chain Standards~~ — In September 2017, NERC filed supply chain cyber security reliability standards with the FERC. These standards consider the FERC’s directives to address supply chain cyber security risk management for industrial control system hardware, software, computing and network services associated with electric grid operations. The proposed reliability standards focus on security objectives including software integrity and authenticity, vendor remote access protections, information system planning and vendor risk management. It is uncertain when the FERC will take action to approve or remand the proposed reliability standards. If approved by the FERC, the proposed reliability standards will become effective on the first calendar quarter that is 18 months after the effective date of the approval. SPS is in the process of developing plans in accordance with the requirements of the standards. The additional cost for compliance is anticipated to be recoverable through wholesale and retail rates.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 ~~Sept.~~June 30, ~~2017~~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

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

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

Additional Information

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

Item 1A — RISK FACTORS

SPS’ risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, ~~2016,~~2017, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 6 — EXHIBITS



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



3.01*	Amended and Restated Articles of Incorporation ~~of SPS~~ dated Sept. 30, ~~1997.~~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)).
~~4.01~~10.01*	~~Supplemental Indenture No. 5~~Seventh Amendment dated as of Aug. 1, 2017 between SPS and U.S. Bank National Association, as Trustee, creating $450 million principal amount of 3.70 percent First Mortgage Bonds, Series No. 5 due 2047 (Exhibit 4.02 to Form 8-K dated Aug. 9, 2017 (file no. 001-03789)).
~~10.1~~*+	~~Fourth Amendment~~May 7, 2018 to the Xcel Energy ~~Inc. Nonqualified Deferred Compensation Plan (2009 Restatement)~~Senior Executive Severance and Change-in-Control Policy (Exhibit ~~10.1~~10.01 to Form 10-Q of Xcel Energy for the quarter ended ~~Sept.~~June 30, ~~2017~~2018 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended ~~Sept.~~June 30, ~~2017~~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.

SIGNATURES

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



		Southwestern Public Service Company

~~Oct.~~July 27, ~~2017~~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)

2728



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



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



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

Bonita	230	TX	2019	PPA
Total PPA	230
Total Wind Capacity	1,230