Southwestern Public Service 10-Q 2016 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended Sept. 30, 2016

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.)
Tyler at Sixth
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, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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)

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. 31, 2016
Common Stock, $1 par value	100 shares

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

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l     —	Financial Statements (Unaudited)	3
Item 2    —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 4    —	Controls and Procedures	24
PART II — OTHER INFORMATION
Item 1     —	Legal Proceedings	24
Item 1A  —	Risk Factors	24
Item 4    —	Mine Safety Disclosures	25
Item 5    —	Other Information	25
Item 6    —	Exhibits	25
SIGNATURES		26
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
	2016			2015			2016			2015
Operating revenues	$	554,926		$	530,752		$	1,386,210		$	1,377,566
Operating expenses
Electric fuel and purchased power	297,587			287,476			757,537			776,301
Operating and maintenance expenses	71,699			72,036			202,410			219,760
Demand side management program expenses	5,663			3,726			12,279			10,155
Depreciation and amortization	42,026			35,422			123,250			107,911
Taxes (other than income taxes)	15,589			15,016			46,417			43,472
Total operating expenses	432,564			413,676			1,141,893			1,157,599
Operating income	122,362			117,076			244,317			219,967
Other income, net	137			103			563			203
Allowance for funds used during construction — equity	2,632			2,085			7,348			5,578
Interest charges and financing costs
Interest charges — includes other financing costs of $828, $789, $2,461 and $2,334, respectively	23,343			21,779			67,350			63,737
Allowance for funds used during construction — debt	(1,422		)	(1,204		)	(4,146		)	(3,402		)
Total interest charges and financing costs	21,921			20,575			63,204			60,335
Income before income taxes	103,210			98,689			189,024			165,413
Income taxes	34,864			36,874			65,944			60,775
Net income	$	68,346		$	61,815		$	123,080		$	104,638

See Notes to Financial Statements

3

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended Sept. 30				Nine Months Ended Sept. 30
	2016		2015		2016		2015
Net income	$	68,346	$	61,815	$	123,080	$	104,638
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost,     net of tax of $6, $0, $19 and $0, respectively	12		—		35		—
Derivative instruments:
Reclassification of losses to net income, net of tax of $25,     $24, $74 and $72, respectively	44		44		129		129
Other comprehensive income	56		44		164		129
Comprehensive income	$	68,402	$	61,859	$	123,244	$	104,767

See Notes to Financial Statements

4

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Nine Months Ended Sept. 30
	2016			2015
Operating activities
Net income	$	123,080		$	104,638
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	123,820			109,629
Demand side management program amortization	1,255			1,255
Deferred income taxes	99,882			35,541
Amortization of investment tax credits	(160		)	(255		)
Allowance for equity funds used during construction	(7,348		)	(5,578		)
Net derivative losses	203			201
Other	122			—
Changes in operating assets and liabilities:
Accounts receivable	(22,160		)	(24,416		)
Accrued unbilled revenues	(18,307		)	18,286
Inventories	(1,491		)	3,351
Prepayments and other	24,172			(14,589		)
Accounts payable	19,690			(6,891		)
Net regulatory assets and liabilities	(18,480		)	43,980
Other current liabilities	18,989			43,949
Pension and other employee benefit obligations	(15,606		)	(9,961		)
Change in other noncurrent assets	(537		)	1,054
Change in other noncurrent liabilities	3,916			1,227
Net cash provided by operating activities	331,040			301,421
Investing activities
Utility capital/construction expenditures	(371,994		)	(428,991		)
Proceeds from insurance recoveries	987			—
Allowance for equity funds used during construction	7,348			5,578
Investments in utility money pool arrangement	(75,000		)	(9,000		)
Repayments from utility money pool arrangement	75,000			9,000
Other	(1,174		)	—
Net cash used in investing activities	(364,833		)	(423,413		)
Financing activities
Repayment of short-term borrowings, net	(15,000		)	(37,000		)
Proceeds from long-term debt	296,152			198,784
Borrowings under utility money pool arrangement	505,000			407,700
Repayments under utility money pool arrangement	(505,000		)	(405,700		)
Capital contributions from parent	16,225			34,535
Dividends paid to parent	(57,570		)	(76,192		)
Net cash provided by financing activities	239,807			122,127
Net change in cash and cash equivalents	206,014			135
Cash and cash equivalents at beginning of period	834			596
Cash and cash equivalents at end of period	$	206,848		$	731
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(47,787	)	$	(58,539	)
Cash received (paid) for income taxes, net	49,402			(41,114		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	25,445		$	29,815

See Notes to Financial Statements

5

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

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

	Sept. 30, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	206,848		$	834
Accounts receivable, net	91,299			71,166
Accounts receivable from affiliates	3,198			1,079
Accrued unbilled revenues	122,088			103,781
Inventories	39,037			37,546
Regulatory assets	28,417			31,541
Derivative instruments	4,478			12,952
Deferred income taxes	31,555			35,686
Prepaid taxes	22,021			35,666
Prepayments and other	9,006			20,520
Total current assets	557,947			350,771
Property, plant and equipment, net	4,579,219			4,348,823
Other assets
Regulatory assets	309,389			301,814
Derivative instruments	22,902			25,272
Other	8,862			3,449
Total other assets	341,153			330,535
Total assets	$	5,478,319		$	5,030,129
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	200,000		$	200,000
Short-term debt	—			15,000
Accounts payable	159,272			146,794
Accounts payable to affiliates	17,617			29,135
Regulatory liabilities	66,043			98,305
Taxes accrued	42,418			33,374
Accrued interest	31,129			17,781
Dividends payable	27,498			12,538
Derivative instruments	3,565			3,565
Other	29,807			35,654
Total current liabilities	577,349			592,146
Deferred credits and other liabilities
Deferred income taxes	996,111			896,430
Regulatory liabilities	233,777			229,584
Asset retirement obligations	28,314			27,233
Derivative instruments	24,404			27,078
Pension and employee benefit obligations	77,649			93,346
Other	21,366			17,841
Total deferred credits and other liabilities	1,381,621			1,291,512
Commitments and contingencies
Capitalization
Long-term debt	1,635,687			1,338,522
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Sept. 30, 2016 and Dec. 31, 2015, respectively	—			—
Additional paid in capital	1,396,223			1,371,223
Retained earnings	488,556			438,007
Accumulated other comprehensive loss	(1,117		)	(1,281		)
Total common stockholder’s equity	1,883,662			1,807,949
Total liabilities and equity	$	5,478,319		$	5,030,129

See Notes to Financial Statements

6

SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of Sept. 30, 2016 and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2016 and 2015; and its cash flows for the nine months ended Sept. 30, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2016 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, 2015 balance sheet information has been derived from the audited 2015 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2015. 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, 2015, filed with the SEC on Feb. 22, 2016. 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, 2015, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Revenue Recognition— In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. The guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. SPS is currently evaluating the impact of adopting ASU 2014-09 on its financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, SPS does not expect the implementation of ASU 2015-17 to have a material impact on its financial statements.

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 among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, 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 is currently evaluating the impact of adopting ASU 2016-01 on its financial statements.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. SPS is currently evaluating the impact of adopting ASU 2016-02 on its financial statements.

7

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. SPS does not expect the implementation of ASU 2016-09 to have a material impact on its financial statements.

Recently Adopted

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. SPS implemented the new guidance as required on Jan. 1, 2016, and as a result, $11.8 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the balance sheet as of March 31, 2016, and $12.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the balance sheet as of Dec. 31, 2015.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a net asset value methodology in the fair value hierarchy. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	97,640		$	77,054
Less allowance for bad debts	(6,341		)	(5,888		)
	$	91,299		$	71,166

(Thousands of Dollars)	Sept. 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	25,440	$	24,888
Fuel	13,597		12,658
	$	39,037	$	37,546

(Thousands of Dollars)	Sept. 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	6,191,562		$	5,933,764
Construction work in progress	294,025			236,697
Total property, plant and equipment	6,485,587			6,170,461
Less accumulated depreciation	(1,906,368		)	(1,821,638		)
	$	4,579,219		$	4,348,823

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, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

8

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of Sept. 30, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, the 2013 through 2014 claims, and the anticipated claim for 2015. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in June 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’s proposed adjustment of the carryback claims. SPS is not expected to accrue any income tax expense related to this adjustment. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

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

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

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

(Millions of Dollars)	Sept. 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	3.2	$	2.6
Unrecognized tax benefit — Temporary tax positions	22.7		22.1
Total unrecognized tax benefit	$	25.9	$	24.7

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

(Millions of Dollars)	Sept. 30, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.7	)	$	(5.0	)

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

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2016 or Dec. 31, 2015.

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, 2015 and in Note 5 to SPS’ Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

9

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million, which it subsequently revised to $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. The hearing in the appeal is scheduled for February 2017.

Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a historic test year (HTY) ended Sept. 30, 2015, a requested return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In SPS’ required update filing in April 2016, SPS revised its requested rate increase to $68.6 million.

Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be effective retroactive to July 20, 2016.

In August 2016, several intervenors filed direct testimony in response to SPS’ rate request, including: PUCT Staff (Staff), the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), Texas Industrial Energy Consumers (TIEC), and the State of Texas’ agencies.

• The Staff recommended a rate increase of approximately $32.9 million, based on a ROE of 9.30 percent and an equity ratio of 51 percent. The Staff’s proposed rate increase reflects imputed revenues for power factor adjustment charges and weather normalization;

• AXM recommended a rate increase of approximately $25.2 million, based on a ROE of 9.40 percent and an equity ratio of 51 percent; and

• The other intervenors did not present a complete revenue requirement analysis. The majority of the direct testimony focused on specific cost allocation and rate design issues. However, OPUC and TIEC recommended ROEs of 9.20 percent and 9.15 percent, respectively.

In October 2016, SPS and various parties reached an agreement in principle in the Texas rate case. SPS and the parties are documenting the settlement, and expect to file with the PUCT in the fourth quarter of 2016.  Any settlement would require approval of the PUCT, with a decision expected by the end of 2016 or early 2017.

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

New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC seeking an increase in non-fuel base rates of $45.4 million. The proposed increase would be offset by a decrease in base fuel revenue of approximately $21.1 million. The rate filing was based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric rate base of approximately $734 million and an equity ratio of 53.97 percent.

In August 2016, the NMPRC approved a black-box stipulation that resulted in a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments to the fuel and purchased power cost adjustment clause.

SPS plans to file another base rate case in November 2016 utilizing a future test year ending June 2018.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these upgrades. 

10

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008.  The FERC approved the waiver request in July 2016.  SPS and certain other parties requested rehearing of the FERC order.  In September 2016, SPP provided further information regarding additional costs, primarily due to the system-wide claw back of point to point revenues previously distributed to SPS and other entities. Amounts due to SPP are expected to be paid over a five-year period commencing November 2016 under an optional payment plan that was approved by the FERC in September 2016 and elected by SPS in October 2016. Based on SPP’s calculation in October 2016, estimated costs would be approximately $12 million to $14 million, and SPS anticipates these costs would be recoverable through regulatory mechanisms.

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, 2015, and in Note 6 to SPS’ Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position.

Purchased Power Agreements (PPAs)

Under certain PPAs, SPS purchases power from independent power producing entities that own natural gas fueled power plants for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.

SPS had approximately 897 megawatts (MW) and 827 MW of capacity under long-term PPAs as of Sept. 30, 2016 and Dec. 31, 2015, with entities that have been determined to be variable interest entities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2041.

Environmental Contingencies

Environmental Requirements

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) and nitrogen oxide (NOx) from utilities in the eastern half of the United States, including Texas, using an emissions trading program.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone National Ambient Air Quality Standard (NAAQS) and the 1997 and 2006 particulate NAAQS. As the United States Environmental Protection Agency (EPA) revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. In September 2016, the EPA adopted a final rule that reduced the ozone season emission budget for NOx in Texas by approximately 22 percent, which is expected to lead to increased costs to purchase emission allowances. SPS does not anticipate these increased costs to purchase emission allowances will have a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce SO₂, NOx and PM 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, CSAPR.

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Texas developed a state implementation plan (SIP) that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In December 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the United States Court of Appeals for the District of Columbia Circuit’s (D.C. Circuit) remand of the Texas SO₂ emission budgets. In March 2016, the EPA requested information under the Clean Air Act related to EGUs at SPS’ plants. SPS identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO₂ and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO₂ and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. It is not yet known whether the Texas Commission on Environmental Quality (TCEQ) intends to utilize this option. If Texas does not opt into the CSAPR rule, the EPA is expected to issue a proposed rule in December 2016 that could impact Harrington Units 1 and 2.

In December 2014, the EPA proposed to disapprove portions of the SIP and instead adopt a federal implementation plan (FIP). In January 2016, the EPA adopted a final rule establishing a FIP for the state of Texas, which imposed SO₂ emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. In March 2016, SPS appealed the EPA’s decision and asked for a stay of the final rule while it is being reviewed. In July 2016, the United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay motion and decided that the Fifth Circuit, not the D.C. Circuit, is the appropriate venue for this case. In addition, SPS filed a petition with the EPA requesting reconsideration of the final rule. SPS believes these costs or the costs of alternative cost-effective generation would be recoverable through regulatory mechanisms if required, and therefore does not expect a material impact on results of operations, financial position or cash flows.

Implementation of the NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near SPS’ Tolk and Harrington plants.  The Tolk and Harrington Plants utilize low sulfur coal to reduce SO₂ emissions. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the area near the Harrington plant as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020.

If an area is designated nonattainment in 2020, the states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO₂ controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the designation of nonattainment areas is made, and any required state plans are developed. SPS believes that should SO₂ control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

In light of the continuing development of environmental regulatory requirements, as well as the more favorable long term outlook for alternative resources, SPS is undertaking analysis to determine the most cost-effective means to meet the needs of its customers, given a low natural gas price environment, the need to make additional investments to provide water to the Tolk facility and the potential need to make major investments in air pollution control equipment.

Legal Contingencies

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

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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, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	31			21
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	0.59		%	0.40		%
Weighted average interest rate at period end	N/A			N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Sept. 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	400		$	400
Amount outstanding at period end	—			15
Average amount outstanding	26			100
Maximum amount outstanding	91			246
Weighted average interest rate, computed on a daily basis	0.67		%	0.46		%
Weighted average interest rate at period end	N/A			0.60

Letters of Credit — SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Sept. 30, 2016 and Dec. 31, 2015, there were $5 million and $7 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, SPS must have a 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 credit facility capacity. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At Sept. 30, 2016, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	5	$	395

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

^(b)  Includes outstanding letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at Sept. 30, 2016 and Dec. 31, 2015.

Amended Credit Agreements - In June 2016, SPS entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $400 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:

• The maturity extended from October 2019 to June 2021.

• The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.

• The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

SPS has the right to request an extension of the revolving credit facility termination date for two additional one-year periods, subject to majority bank group approval.

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Long-Term Borrowings

In August 2016, SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046.

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 measurement 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 prices.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by SPS include transmission congestion instruments purchased from the SPP, referred to as financial transmission rights (FTRs). 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 energy congestion, which is caused by transmission load and transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity. Unplanned plant outages, scheduled plant maintenance, changes in the costs of fuels used in generation, weather and changes in demand for electricity can each impact the operating schedules of the power plants and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model fair value measurements for FTRs have been assigned a Level 3. Monthly settlements for non-trading FTRs are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the financial statements of SPS.

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Derivative Instruments Fair Value Measurements

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

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

At Sept. 30, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

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

The following table details the gross notional amounts of commodity FTRs at Sept. 30, 2016 and Dec. 31, 2015:

(Amounts in Thousands) (a)	Sept. 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	3,650	6,192

^(a)  Amounts are not reflective of net positions in the underlying commodities.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for the three months ended Sept. 30, 2016 and 2015, and $0.2 million for the nine months ended Sept. 30, 2016 and 2015.

During the three and nine months ended Sept. 30, 2016, changes in the fair value of FTRs resulted in pre-tax net gains of $0.2 million and $2.0 million, respectively and were recognized as regulatory assets and liabilities. For the three and nine months ended Sept. 30, 2015, changes in the fair value of FTRs resulted in pre-tax net losses of $0.7 million and $2.7 million, respectively, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses of $0.4 million and $3.7 million were recognized for the three and nine months ended Sept. 30, 2016, recorded to electric fuel and purchased power. For the three and nine months ended Sept. 30, 2015, FTR settlement losses of $0.7 million and $2.3 million, respectively, were recognized and recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2016 and 2015. 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 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. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms , 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.

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SPS’ most significant concentrations of credit risk are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At Sept. 30, 2016, seven of the most significant counterparties, comprising $41.1 million or 46 percent of this credit exposure, were not rated by Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $0.4 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. Seven of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Sept. 30, 2016:

	Sept. 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,598	$	2,598	$	(2,462	)	$	136
Total current derivative assets	$	—	$	—	$	2,598	$	2,598	$	(2,462	)	136
PPAs (a)												4,342
Current derivative instruments												$	4,478
Noncurrent derivative assets
PPAs (a)												$	22,902
Noncurrent derivative instruments												$	22,902
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,462	$	2,462	$	(2,462	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,462	$	2,462	$	(2,462	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	24,404
Noncurrent derivative instruments												$	24,404

^(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b) SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Sept. 30, 2016. At Sept. 30, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	$	5,060
Total current derivative assets	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	5,060
PPAs (a)												7,892
Current derivative instruments												$	12,952
Noncurrent derivative assets
PPAs (a)												$	25,272
Noncurrent derivative instruments												$	25,272
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	$	—
Total current derivative liabilities	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	27,078
Noncurrent derivative instruments												$	27,078

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2016 and 2015:

	Three Months Ended Sept. 30
(Thousands of Dollars)	2016			2015
Balance at July 1	$	1,070		$	11,463
Purchases	274			408
Settlements	(7,822		)	(7,409		)
Net transactions recorded during the period:
Gains recognized as regulatory assets and liabilities	6,614			2,898
Balance at Sept. 30	$	136		$	7,360

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	Nine Months Ended Sept. 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	5,060		$	15,884
Purchases	5,426			22,621
Settlements	(22,438		)	(25,810		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	12,088			(5,335		)
Balance at Sept. 30	$	136		$	7,360

SPS recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and nine months ended Sept. 30, 2016 and 2015.

Fair Value of Long-Term Debt

As of Sept. 30, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	Sept. 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	1,835,687	$	2,065,982	$	1,538,522	$	1,678,673

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Sept. 30, 2016 and Dec. 31, 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

9. Other Income, Net

Other income, net consisted of the following:

	Three Months Ended Sept. 30						Nine Months Ended Sept. 30
(Thousands of Dollars)	2016			2015			2016			2015
Interest income	$	400		$	38		$	579		$	83
Other nonoperating (expense) income	(231		)	(156		)	16			(46		)
Insurance policy (expense) income	(32		)	221			(32		)	166
Other income, net	$	137		$	103		$	563		$	203

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended Sept. 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,440		$	2,752		$	194		$	239
Interest cost	5,315			5,046			455			436
Expected return on plan assets	(6,901		)	(7,153		)	(594		)	(635		)
Amortization of prior service cost (credit)	—			9			(100		)	(101		)
Amortization of net loss (gain)	2,997			3,772			(146		)	(159		)
Net periodic benefit cost (credit)	3,851			4,426			(191		)	(220		)
Credits not recognized due to the effects of regulation	637			740			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,488		$	5,166		$	(191	)	$	(220	)

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	Nine Months Ended Sept. 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	7,320		$	8,255		$	582		$	716
Interest cost	15,945			15,138			1,365			1,309
Expected return on plan assets	(20,703		)	(21,458		)	(1,782		)	(1,905		)
Amortization of prior service cost (credit)	—			29			(300		)	(301		)
Amortization of net loss (gain)	8,991			11,316			(438		)	(479		)
Net periodic benefit cost (credit)	11,553			13,280			(573		)	(660		)
Credits not recognized due to the effects of regulation	1,353			2,139			—			—
Net benefit cost (credit) recognized for financial reporting	$	12,906		$	15,419		$	(573	)	$	(660	)

In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $18.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2016.

11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2016 and 2015 were as follows:

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

	Three Months Ended Sept. 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at July 1	$	(904	)
Losses reclassified from net accumulated other comprehensive loss	44
Net current period other comprehensive income	44
Accumulated other comprehensive loss at Sept. 30	$	(860	)

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

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	Nine Months Ended Sept. 30, 2015
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges
Accumulated other comprehensive loss at Jan. 1	$	(989	)
Losses reclassified from net accumulated other comprehensive loss	129
Net current period other comprehensive loss	129
Accumulated other comprehensive loss at Sept. 30	$	(860	)

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended Sept. 30, 2016				Three Months Ended Sept. 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	69		(a)	$	68		(a)
Total, pre-tax	69				68
Tax benefit	(25		)		(24		)
Total amounts reclassified, net of tax	$	44			$	44

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Nine Months Ended Sept. 30, 2016				Nine Months Ended Sept. 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	203		(a)	$	201		(a)
Total, pre-tax	203				201
Tax benefit	(74		)		(72		)
Total amounts reclassified, net of tax	$	129			$	129

^(a)  Included in interest charges.

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.

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Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including SPS’ Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 and Quarterly Report on Form 10-Q for the quarters ended March 31, 2016 and June 30, 2016), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.

Results of Operations

SPS’ net income was approximately $123.1 million for the nine months ended Sept. 30, 2016, compared with net income of approximately $104.6 million for the same period in 2015. Higher electric margins and lower operating and maintenance (O&M) expenses were partially offset by an increase in depreciation.

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. The design of fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings. The following tables detail the electric revenues and margin:

	Nine Months Ended Sept. 30
(Millions of Dollars)	2016			2015
Electric revenues	$	1,386		$	1,378
Electric fuel and purchased power	(758		)	(776		)
Electric margin	$	628		$	602

The following tables summarize the components of the changes in electric revenues and electric margin for the nine months ended Sept. 30, 2016:

Electric Revenues

(Millions of Dollars)	2016 vs. 2015
Transmission revenue	$	32
Firm wholesale	5
Estimated impact of weather	2
Trading	(18		)
Fuel and purchased power cost recovery	(16		)
Other, net	3
Total increase in electric revenues	$	8

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Electric Margin

(Millions of Dollars)	2016 vs. 2015
Transmission revenue, net of costs	$	11
Fuel handling	6
Firm wholesale	5
Estimated impact of weather	2
Other, net	2
Total increase in electric margin	$	26

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses decreased $17.4 million, or 7.9 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The decrease was mainly due to the timing and scope of plant outages.

Depreciation and Amortization — Depreciation and amortization increased $15.3 million, or 14.2 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was primarily attributable to capital investments.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $2.9 million, or 6.8 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was primarily due to higher property taxes.

Allowance for funds used during construction (AFUDC) —AFUDC increased $2.5 million, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was primarily due to the increase in construction projects.

Interest Charges — Interest charges increased $3.6 million, or 5.7 percent, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase was primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $5.2 million, for the nine months ended Sept. 30, 2016, compared with the same period in 2015. The increase in income tax expense was primarily due to higher pretax earnings in 2016, partially offset by a tax benefit for prior year adjustments in 2016. The ETR was 34.9 percent for the nine months ended Sept. 30, 2016, compared with 36.7 percent for the same period in 2015. The lower ETR in 2016 was primarily due to the adjustments referenced above.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1 of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2015, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 Kilovolt (KV) Transmission Line— In June 2015, SPS filed a certificate of convenience and necessity (CCN) with the PUCT for the 33-mile Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. The PUCT approved this CCN in March 2016. A CCN for the 111-mile TUCO to Yoakum County substation segment was filed in June 2016. Assuming approval of this CCN, this segment is scheduled to be in service in 2019. A 20-mile CCN for the Texas/New Mexico state line to Hobbs Plant segment is planned to be filed in the fourth quarter of 2016 or early 2017. The estimated project cost for all three segments is approximately $242 million.

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 based on 2015 revenue requirements. 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. 

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The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. As part of the first process, the PUCT asked SPP and ERCOT to perform reliability and economic studies to better understand the implications of LP&L’s proposal. SPS intends to participate in the PUCT’s processes to protect its customers’ interests.

In May 2016, SPS submitted a filing to the FERC seeking approval to impose an Interconnection Switching Fee (exit fee) associated with LP&L’s proposal.  In September 2016, FERC dismissed SPS’ petition without prejudice to refile, finding the petition premature since LP&L has not made a final decision to move to ERCOT and the terms of the transition, if any, have not been determined.

Summary of Recent Federal Regulatory Developments

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas.  In April 2016, the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations.  These changes include requirements around use of automatic or remote-controlled shut-off valves; testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations. 

SPS continues to analyze the proposed rule changes as they relate to costs, current operations and financial results.  PHMSA has indicated that they intend for the rules to go into effect in late 2017 or early 2018. 

While SPS cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

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, 2015 and Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — The FERC has adopted a new two-step ROE methodology for electric utilities. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC issued an order in the first litigated Midcontinent Independent System Operator, Inc. (MISO) ROE complaint in September 2016 and is not expected to issue an order in the remaining litigated MISO ROE complaint proceeding until 2017.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, SPS filed changes to its transmission formula rates to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings were intended to ensure that SPS is in compliance with IRS rules and may continue to use accelerated tax depreciation.

Golden Spread protested the proposed changes to the SPS transmission formula rate. In April 2016, FERC accepted the SPS formula rate changes, subject to a compliance filing. SPS submitted the compliance filing in May 2016. In August 2016, FERC approved the SPS compliance filing.

SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) — SPP and MISO were involved in a long-running dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagreed over MISO’s authority to transmit power between the traditional MISO region in the Midwest and the Entergy system. Several cases were filed with the FERC by MISO and SPP between 2011 and 2014.

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In January 2016, the FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provides a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period (February 2014 to January 2016) and $16 million annually prospectively starting Feb. 1, 2016, subject to a true-up. In January 2016, SPP filed a proposal regarding distribution of the MISO revenues to SPP members, including SPS. In March 2016, the FERC issued an order rejecting one component of the SPP filing, accepting the remainder of the SPP tariff proposal subject to refund. In August 2016, MISO and other parties filed a settlement regarding the April 2014 MISO tariff change filing to recover SPP JOA charges in MISO rates. The settlement is pending FERC approval. The JOA revenue allocated to SPS under the filed SPP proposal was not expected to be material.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Sept. 30, 2016, 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

Effective January 2016, SPS implemented the general ledger modules of a new enterprise resource planning (ERP) system to improve certain financial and related transaction processes. During 2016 and 2017, SPS will continue implementing additional modules and expects to begin conversion of existing work management systems to this new ERP system. In connection with this ongoing implementation, SPS has updated and will continue updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures. SPS does not expect the implementation of the additional modules to materially affect its internal control over financial reporting.

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Additional Information

See Note 6 to the financial statements for further discussion of legal claims and environmental proceedings.  See 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, 2015, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

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Item 4—MINE SAFETY DISCLOSURES

None.

Item 5—OTHER INFORMATION

None.

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 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
4.01*	Supplemental Indenture dated as of Aug. 1, 2016 between SPS and U.S. Bank National Association, as Trustee, creating $300,000,000 principal amount of 3.40 percent First Mortgage Bonds, Series No. 4 due 2046. (Exhibit 4.02 to Form 8-K of SPS dated Aug. 12, 2016 (file no. 001-03789)).
10.01*+	Third Amendment dated Sept. 30, 2016 to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (Exhibit 10.01 to Form 10-Q of Xcel Energy dated Oct. 28, 2016 (file no. 001-03034)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2016 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Statements of Income, (ii) the Statements of Comprehensive Income (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) Notes to Financial Statements, and (vi) document and entity information.

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SIGNATURES

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

		Southwestern Public Service Company
Oct. 31, 2016	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

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