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EX-31.01 - EXHIBIT 31.01 - SOUTHWESTERN PUBLIC SERVICE COspsex3101q32014.htm
EX-31.02 - EXHIBIT 31.02 - SOUTHWESTERN PUBLIC SERVICE COspsex3102q32014.htm
EX-99.01 - EXHIBIT 99.01 - SOUTHWESTERN PUBLIC SERVICE COspsex9901q32014.htm
EXCEL - IDEA: XBRL DOCUMENT - SOUTHWESTERN PUBLIC SERVICE COFinancial_Report.xls
EX-32.01 - EXHIBIT 32.01 - SOUTHWESTERN PUBLIC SERVICE COspsex3201q32014.htm

                              
 
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, 2014
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 Nov. 3, 2014
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     —

Item 2    —

Item 4    —

 
 
 
PART II — OTHER INFORMATION
 
Item 1     —

Item 1A  —

Item 4    —

Item 5    —

Item 6    —

 
 
 

 
 
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).

2


PART 1FINANCIAL INFORMATION
Item 1FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands)
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
 
2014
 
2013
 
2014
 
2013
Operating revenues
$
552,779

 
$
481,407

 
$
1,493,715

 
$
1,317,495

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 
 
 
Electric fuel and purchased power
315,524

 
293,831

 
918,874

 
814,077

Operating and maintenance expenses
66,833

 
66,288

 
205,194

 
198,309

Demand side management program expenses
3,455

 
2,966

 
9,368

 
9,216

Depreciation and amortization
34,207

 
30,315

 
99,790

 
91,575

Taxes (other than income taxes)
13,991

 
13,354

 
40,144

 
38,137

Total operating expenses
434,010

 
406,754

 
1,273,370

 
1,151,314

 
 
 
 
 
 
 
 
Operating income
118,769

 
74,653

 
220,345

 
166,181

 
 
 
 
 
 
 
 
Other income (expense), net
66

 
(115
)
 
(22
)
 
(58
)
Allowance for funds used during construction — equity
3,147

 
2,150

 
9,682

 
6,972

 
 
 
 
 
 
 
 
Interest charges and financing costs
 

 
 

 
 
 
 
Interest charges — includes other financing costs of
$768, $773, $2,229 and $2,248, respectively
20,479

 
22,892

 
59,405

 
58,509

Allowance for funds used during construction — debt
(1,846
)
 
(1,387
)
 
(5,694
)
 
(4,406
)
Total interest charges and financing costs
18,633

 
21,505

 
53,711

 
54,103

 
 
 
 
 
 
 
 
Income before income taxes
103,349

 
55,183

 
176,294

 
118,992

Income taxes
36,412

 
20,146

 
62,587

 
43,165

Net income
$
66,937

 
$
35,037

 
$
113,707

 
$
75,827


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
 
 
2014
 
2013
 
2014
 
2013
Net income
 
$
66,937

 
$
35,037

 
$
113,707

 
$
75,827

Other comprehensive income
 
 

 
 

 
 

 
 

Derivative instruments:
 
 

 
 

 
 

 
 

Reclassification of losses to net income, net of tax of $24 and $72 for each of the three and nine months ended Sept. 30, 2014 and 2013, respectively
 
44

 
44

 
129

 
129

Other comprehensive income
 
44

 
44

 
129

 
129

Comprehensive income
 
$
66,981

 
$
35,081

 
$
113,836

 
$
75,956


See Notes to Financial Statements


4


SOUTHWESTERN PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
Nine Months Ended Sept. 30
 
2014
 
2013
Operating activities
 
 
 

Net income
$
113,707

 
$
75,827

Adjustments to reconcile net income to cash provided by operating activities:
 

 
 

Depreciation and amortization
101,514

 
93,171

Demand side management program amortization
1,255

 
1,255

Deferred income taxes
88,008

 
36,831

Amortization of investment tax credits
(255
)
 
(245
)
Allowance for equity funds used during construction
(9,682
)
 
(6,972
)
Net derivative losses
201

 
201

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(10,982
)
 
(32,999
)
Accrued unbilled revenues
(22,164
)
 
(25,860
)
Inventories
(6,257
)
 
(5,558
)
Prepayments and other
(672
)
 
(7,046
)
Accounts payable
5,777

 
21,281

Net regulatory assets and liabilities
(11,550
)
 
(11,629
)
Other current liabilities
29,426

 
62,149

Pension and other employee benefit obligations
(2,535
)
 
(18,923
)
Change in other noncurrent assets
2,684

 
(1,580
)
Change in other noncurrent liabilities
2,204

 
(2,221
)
Net cash provided by operating activities
280,679

 
177,682

 
 
 
 
Investing activities
 

 
 

Utility capital/construction expenditures
(412,976
)
 
(423,435
)
Allowance for equity funds used during construction
9,682

 
6,972

Investments in utility money pool arrangement
(94,000
)
 
(12,000
)
Repayments from utility money pool arrangement
91,000

 
12,000

Net cash used in investing activities
(406,294
)
 
(416,463
)
 
 
 
 
Financing activities
 

 
 

Repayments of short-term borrowings, net
(84,000
)
 
(9,000
)
Proceeds from issuance of long-term debt
148,241

 
94,809

Borrowings under utility money pool arrangement
433,000

 
565,000

Repayments under utility money pool arrangement
(471,000
)
 
(485,000
)
Capital contributions from parent
160,000

 
124,935

Dividends paid to parent
(60,632
)
 
(51,361
)
Net cash provided by financing activities
125,609

 
239,383

 
 
 
 
Net change in cash and cash equivalents
(6
)
 
602

Cash and cash equivalents at beginning of period
1,011

 
482

Cash and cash equivalents at end of period
$
1,005

 
$
1,084

 
 
 
 
Supplemental disclosure of cash flow information:
 

 
 

Cash paid for interest (net of amounts capitalized)
$
(41,604
)
 
$
(41,273
)
Cash received (paid) for income taxes, net
26,539

 
(18,719
)
Supplemental disclosure of non-cash investing transactions:
 

 
 

Property, plant and equipment additions in accounts payable
$
19,538

 
$
25,143


See Notes to Financial Statements

5


SOUTHWESTERN PUBLIC SERVICE COMPANY
BALANCE SHEETS (UNAUDITED)
(amounts in thousands, except share and per share data)
 
Sept. 30, 2014
 
Dec. 31, 2013
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
1,005

 
$
1,011

Accounts receivable, net
90,316

 
70,951

Accounts receivable from affiliates
7,457

 
15,840

Investments in utility money pool arrangement

3,000

 

Accrued unbilled revenues
131,371

 
109,207

Inventories
43,395

 
37,138

Regulatory assets
44,090

 
27,595

Derivative instruments
30,132

 
17,826

Deferred income taxes
53,344

 
85,362

Prepayments and other
20,243

 
19,571

Total current assets
424,353

 
384,501

 
 
 
 
Property, plant and equipment, net
3,616,190

 
3,284,030

 
 
 
 
Other assets
 

 
 

Regulatory assets
274,816

 
290,415

Derivative instruments
35,137

 
41,056

Other
15,831

 
17,068

Total other assets
325,784

 
348,539

Total assets
$
4,366,327

 
$
4,017,070

 
 
 
 
Liabilities and Equity
 

 
 

Current liabilities
 

 
 

Short-term debt
$

 
$
84,000

Borrowings under utility money pool arrangement

 
38,000

Accounts payable
147,580

 
143,879

Accounts payable to affiliates
13,696

 
15,387

Regulatory liabilities
88,364

 
83,759

Taxes accrued
31,558

 
23,584

Accrued interest
27,377

 
16,883

Dividends payable
22,866

 
18,082

Derivative instruments
3,565

 
3,583

Other
81,868

 
75,355

Total current liabilities
416,874

 
502,512

 
 
 
 
Deferred credits and other liabilities
 

 
 

Deferred income taxes
818,465

 
757,778

Regulatory liabilities
100,488

 
81,504

Asset retirement obligations
20,194

 
19,375

Derivative instruments
31,534

 
34,207

Pension and employee benefit obligations
52,552

 
55,087

Other
4,504

 
3,051

Total deferred credits and other liabilities
1,027,737

 
951,002

 
 
 
 
Commitments and contingencies


 


Capitalization
 

 
 

Long-term debt
1,349,604

 
1,199,865

Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at
Sept. 30, 2014 and Dec. 31, 2013, respectively

 

Additional paid in capital
1,165,463

 
1,005,463

Retained earnings
407,681

 
359,389

Accumulated other comprehensive loss
(1,032
)
 
(1,161
)
Total common stockholder’s equity
1,572,112

 
1,363,691

Total liabilities and equity
$
4,366,327

 
$
4,017,070


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, 2014, and Dec. 31, 2013; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2014 and 2013; and its cash flows for the nine months ended Sept. 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2014 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, 2013 balance sheet information has been derived from the audited 2013 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2013. 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, 2013, filed with the SEC on Feb. 24, 2014. 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, 2013, 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 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. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. SPS is currently evaluating the impact of adopting ASU 2014-09 on its financial statements.

3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
Sept. 30, 2014
 
Dec. 31, 2013
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
96,110

 
$
76,426

Less allowance for bad debts
 
(5,794
)
 
(5,475
)
 
 
$
90,316

 
$
70,951

(Thousands of Dollars)
 
Sept. 30, 2014
 
Dec. 31, 2013
Inventories
 
 
 
 
Materials and supplies
 
$
23,770

 
$
21,600

Fuel
 
19,625

 
15,538

 
 
$
43,395

 
$
37,138

(Thousands of Dollars)
 
Sept. 30, 2014
 
Dec. 31, 2013
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
5,200,187

 
$
4,714,398

Construction work in progress
 
264,894

 
388,323

Total property, plant and equipment
 
5,465,081

 
5,102,721

Less accumulated depreciation
 
(1,848,891
)
 
(1,818,691
)
 
 
$
3,616,190

 
$
3,284,030



7


4.
Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of Sept. 30, 2014, the IRS had proposed an adjustment to several federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. SPS is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2014, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. There are currently no state income tax audits in progress.

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

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
Sept. 30, 2014
 
Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions
 
$
0.4

 
$
1.2

Unrecognized tax benefit — Temporary tax positions
 
2.9

 
2.9

Total unrecognized tax benefit
 
$
3.3

 
$
4.1


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, 2014
 
Dec. 31, 2013
NOL and tax credit carryforwards
 
$
(2.4
)
 
$
(2.4
)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.

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, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2014 or Dec. 31, 2013.

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, 2013 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.


8


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

Texas 2014 Electric Rate Case — In January 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflected a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the Transmission Cost Recovery Factor (TCRF) to zero when the final base rates become effective. In April 2014, SPS revised its request to a net increase of $48.1 million.

The rate filing was based on a historic test year ending June 2013, a requested return on equity (ROE) of 10.40 percent, an electric rate base of approximately $1.27 billion and an equity ratio of 53.89 percent. The requested rate increase reflected an increase in depreciation expense of approximately $16 million.

In September 2014, SPS, PUCT staff, and intervenors filed a non-unanimous settlement agreement, subject to PUCT approval, which would increase SPS’ rates by $37 million, or 3.5 percent, retroactive to June 1, 2014. Starting Oct. 1, 2014, SPS began collecting the rate increase through interim rates subject to refund. SPS expects to recover the rate increase for the months of June through September through a separate surcharge to be implemented by the first quarter of 2015. Based on the anticipated outcome of the rate case, SPS recognized approximately $13.3 million of revenue in the third quarter of 2014 for the surcharge.

The settlement includes an ROE of 9.7 percent solely for the purpose of calculating the allowance for funds used during construction (AFUDC) and determining baselines in future filings for the TCRF. In October 2014, the administrative law judges (ALJs) approved the stipulation and recommended that SPS file to implement the surcharge following the PUCT's final order. The PUCT is expected to rule on the settlement in 2014.

Although the parties to the settlement agreement have not prepared a calculation of the $37 million increase and do not agree about which specific costs are included, or not, in the agreed settlement revenue requirement, SPS’ reconciliation of its original request to the settlement increase is as follows:
(Millions of Dollars)
 
Settlement Agreement
Base rate increase request, January 2014
 
$
81.5

Revisions for updated information
 
(4.6
)
Revised request, April 2014
 
76.9

Remove proposed increase in depreciation
 
(16.0
)
Remove adjustment allocators for certain wholesale load reduction
 
(12.0
)
Revised amortizations (rate case expenses, pension and other post-employment benefits expense and gain on sale to Lubbock)
 
(9.0
)
Non-specified settlement adjustments
 
(2.9
)
Settlement base rate increase
 
$
37.0


Electric, Purchased Gas and Resource Adjustment Clauses

TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues was $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In May 2014, the ALJ terminated the interim TCRF due to a settlement in principle being reached with intervenors and the PUCT staff in the pending Texas electric rate case. In July 2014, the PUCT approved the settlement agreement between the parties allowing SPS to recover $4 million annually through the TCRF. In September 2014, SPS filed a proposal with the PUCT to refund approximately $3.7 million during November 2014 for interim rates collected in excess of the final rates approved. PUCT approval of the refund is pending. As of Sept. 30, 2014, SPS had recorded an accrual for the proposed refund.

Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

New Mexico 2014 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million effective in 2014. The rate filing was based on a 2014 forecast test year, a requested ROE of 10.65 percent, an electric rate base of $479.8 million and an equity ratio of 53.89 percent.

In September 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. The request reflected a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million.


9


In March 2014, the NMPRC approved an overall increase of approximately $33.1 million. The increase reflects a base rate increase of $12.7 million and rider recovery of $18.1 million for renewable energy costs, both based on an ROE of 9.96 percent and an equity ratio of 53.89 percent. Final rates were effective April 5, 2014. In April 2014, the New Mexico Attorney General (NMAG) filed a request for rehearing. The rehearing request was denied by the NMPRC. In June 2014, the NMAG filed an appeal of the NMPRC’s denial to the New Mexico Supreme Court. A decision is expected by the second quarter of 2016.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that the base ROE included in the SPS production formula rate of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth.

The FERC also issued orders consolidating the Golden Spread ROE complaints and setting them for settlement judge procedures and hearings and indicated the parties should apply the new ROE methodology to the proceedings. The FERC established effective dates for the refunds as April 20, 2012 and July 19, 2013. The complaints remain in settlement judge proceedings. In October 2014, the FERC upheld the determination of the long term growth rate to be used together with a short term growth rate in its new ROE methodology.

Golden Spread, along with certain New Mexico cooperatives and the West Texas Municipal Power Agency, filed a third rate complaint on Oct. 20, 2014, requesting that the base ROE in the SPS production and transmission formula rates be reduced to 8.61 percent and 9.11 percent, respectively. The complainants requested a refund effective date of Oct. 20, 2014, and that the new complaint be consolidated with the two prior complaints. FERC action is pending.

2004 FERC Complaint Case Orders  In August 2013, the FERC issued an order on rehearing related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12CP system.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling.

In October 2013, the FERC issued orders further considering the requests for rehearing. These matters are currently pending the FERC’s action. If unsuccessful in its rehearing request, SPS will have the opportunity to file rate cases with the FERC and its retail jurisdictions seeking to change all customers to a 3CP allocation method.

As of Dec. 31, 2013, SPS had accrued $44.5 million related to the August 2013 Orders and an additional $4.0 million of principal and interest was accrued during the first nine months of 2014. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015.


10


Request for Waiver of Southwest Power Pool, Inc. (SPP) Tariff — In July 2014, SPS filed a request for the FERC to grant SPS a waiver of an SPP tariff regarding the billing of SPP administrative and transmission expansion charges for certain loads that left the SPS system at the end of 2013 through a sale of transmission assets to Sharyland Distribution and Transmission Services, LLC (Sharyland). Under the SPP tariff provisions, SPP assesses these charges based on prior year load. Absent the waiver, SPS would be billed approximately $2.9 million by SPP in 2014 for loads that are no longer served by SPS. SPP has intervened to oppose the waiver request and Sharyland has intervened to support the waiver request. FERC action is pending.

6.
Commitments and Contingencies

Except to the extent noted below and in Note 5, the circumstances set forth in Notes 10 and 11 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2013, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position.

Purchased Power Agreements (PPAs)

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

SPS had approximately 827 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2014 and Dec. 31, 2013 with entities that have been determined to be variable interest entities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. These agreements have expiration dates through 2033.

Indemnification Agreements

In connection with the sale of certain Texas electric transmission assets to Sharyland Distribution and Transmission Services, LLC in 2013, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing liabilities. SPS’ indemnification obligation is capped at $37.1 million, in the aggregate. The indemnification provisions for most representations and warranties expire in December 2014. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. As of Sept. 30, 2014 and Dec. 31, 2013, SPS has recorded a $0.4 million liability related to this indemnity.

Environmental Contingencies

Environmental Requirements

Water and waste
Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In June 2013, the U.S. Environmental Protection Agency (EPA) published a proposed 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. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017, but no later than July 2022. The impact of this rule on SPS is uncertain at this time.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.


11


Air
EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. SPS is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at SPS’ power plants.

GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Dec. 1, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which SPS operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at SPS’ power plants.

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Texas. The CSAPR set more stringent requirements than the proposed Clean Air Transport Rule and requires plants in Texas to reduce their SO2 and annual NOx emissions. The rule also creates an emissions trading program.

In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. In June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested the CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit granted the EPA’s motion in October 2014. In addition, the D.C. Circuit set a briefing schedule and plans to hear arguments on the remaining issues in the case in March 2015.


12


Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4 to meet reserve requirements and provide quick start capability, reduced wholesale load and new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million.

The EPA will begin to administer the CSAPR in 2015, which will replace the CAIR. In 2014, SPS expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1 and in 2014 on Tolk Unit 2. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. At Sept. 30, 2014, the estimated annual CAIR NOx allowance cost for SPS did not have a material impact on the results of operations, financial position or cash flows. SPS has sufficient SO2 allowances to comply with the CAIR through 2015.

Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Texas identified the SPS facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities.

Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. It is not yet known how the U.S. Supreme Court’s April 2014 decision on the CSAPR, or the D.C. Circuit’s decision to lift its stay of the CSAPR, may impact the EPA’s approval of the BART requirements in the SIP.

In May 2014, the EPA issued a request for information under the CAA related to SO2 control equipment at Tolk Units 1 and 2. The EPA stated it is conducting an analysis of the cost and feasibility of SO2 controls on certain sources, including the Tolk facility, as part of its review of the SIP. The EPA has preliminarily identified Tolk as a contributor to haze in the Wichita Mountains Wildlife Refuge in Oklahoma, and is planning further analysis of SO2 control options. The EPA plans to make a proposal in November 2014 that could include SO2 emission controls at Tolk and anticipates issuing a final decision in August 2015. The costs and timing of potential additional SO2 controls at Tolk are dependent on the EPA’s proposal and final decision, neither of which is yet known.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where SPS operates power plants, current monitored air concentrations are below the level of the final annual primary standard. In August 2014, EPA issued its proposed designations, which did not include areas in any states in which SPS operates. The EPA is expected to finalize its designation of non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.

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.


13


Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint  Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute. First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008. Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved Qualifying Facilities (QF) Tariff. Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. The state and federal lawsuits and regulatory proceedings are in various stages of litigation. On Sept. 8, 2014, the Fifth Circuit Court of Appeals (Fifth Circuit) ruled that federal courts do not have jurisdiction to hear Exelon Wind’s challenge to the PUCT’s decision that Exelon Wind is ineligible to establish LEOs for the six wind facilities that were the subject of the PUCT’s order. The Fifth Circuit also ruled that the PUCT’s requirement that only QF’s providing firm energy are eligible to establish LEOs is valid. Exelon Wind filed a motion for rehearing with the Fifth Circuit on Sept. 22, 2014. On Oct. 10, 2014, the Fifth Circuit denied Exelon Wind’s motion for rehearing. SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

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, 2014
 
Twelve Months Ended Dec. 31, 2013
Borrowing limit
 
$
100

 
$
100

Amount outstanding at period end
 

 
38

Average amount outstanding
 
1

 
46

Maximum amount outstanding
 
22

 
100

Weighted average interest rate, computed on a daily basis
 
0.26
%
 
0.15
%
Weighted average interest rate at period end
 
N/A

 
0.25


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, 2014
 
Twelve Months Ended Dec. 31, 2013
Borrowing limit
 
$
300

 
$
300

Amount outstanding at period end
 

 
84

Average amount outstanding
 
43

 
32

Maximum amount outstanding
 
106

 
140

Weighted average interest rate, computed on a daily basis
 
0.26
%
 
0.30
%
Weighted average interest rate at period end
 
N/A

 
0.27


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, 2014 and Dec. 31, 2013, there were $41.0 million and $25.5 million of letters of credit outstanding, respectively, under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.


14


Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At Sept. 30, 2014, SPS had the following committed credit facility available (in millions of dollars):
Credit Facility (a)
 
Drawn (b)
 
Available
$
300.0

 
$
41.0

 
$
259.0


(a) 
Credit facility has been amended to expire in October 2019.
(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, 2014 and Dec. 31, 2013.

Amended Credit Agreement — On Oct. 14, 2014, SPS entered into an amended five-year credit agreement with a syndicate of banks. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an increased borrowing limit and an extension of maturity from July 2017 to October 2019. The borrowing limit for SPS has been increased to $400 million from $300 million. The Eurodollar borrowing margin on the line of credit ranges from 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fee, calculated on the unused portion of the line of credit, ranges from 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 termination date for two additional one-year periods, subject to majority bank group approval.

Long-Term Borrowings

In June 2014, SPS issued $150 million of 3.30 percent first mortgage bonds due June 15, 2024.

In connection with SPS’ issuance of $150 million of 3.30 percent first mortgage bonds due June 15, 2024, SPS issued $250 million of collateral 8.75 percent first mortgage bonds due Dec. 1, 2018 to the trustee under its senior unsecured indenture in order to secure its previously issued Series G Senior Notes, 8.75 percent due Dec. 1, 2018, equally and ratably with SPS’ first mortgage bonds as required by the terms of such Series G Senior Notes.

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 values.


15


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 Southwest Power Pool, Inc. (SPP), generally 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 overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

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

Derivative Instruments Fair Value Measurements

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

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

At Sept. 30, 2014, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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

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

The following table details the gross notional amounts of commodity FTRs at Sept. 30, 2014 and Dec. 31, 2013:
(Amounts in Thousands)
 
Sept. 30, 2014
 
Dec. 31, 2013
Megawatt hours of electricity
 
10,880

 
5,989



16


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, 2014 and 2013, and $0.2 million for the nine months ended Sept. 30, 2014 and 2013.

During the three and nine months ended Sept. 30, 2014, changes in the fair value of FTRs resulting in pre-tax net losses of $1.2 million and $3.6 million, respectively, were recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses of $1.2 million and $0.3 million were recognized for the three and nine months ended Sept. 30, 2014, respectively, recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

SPS had no derivative instruments designated as fair value hedges during the three and nine months ended Sept. 30, 2014 and 2013. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — SPS continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At Sept. 30, 2014, two of SPS’ eight most significant counterparties for these activities, comprising $19.7 million or 17 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. The remaining six significant counterparties, comprising $58.1 million or 50 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. All eight of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities.


17


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, 2014:
 
 
Sept. 30, 2014
 
 
Fair Value
 
Fair Value Total
 
Counterparty Netting (b)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Electric commodity
 
$

 
$

 
$
37,826

 
$
37,826

 
$
(15,586
)
 
$
22,240

Total current derivative assets
 
$

 
$

 
$
37,826

 
$
37,826

 
$
(15,586
)
 
22,240

PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
7,892

Current derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
30,132

Noncurrent derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
$
35,137

Noncurrent derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
35,137

Current derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Electric commodity
 
$

 
$

 
$
15,586

 
$
15,586

 
$
(15,586
)
 
$

Total current derivative liabilities
 
$

 
$

 
$
15,586

 
$
15,586

 
$
(15,586
)
 

PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
3,565

Current derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
3,565

Noncurrent derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
$
31,534

Noncurrent derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
31,534


(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, 2014. At Sept. 30, 2014, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.


18


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, 2013:
 
 
Dec. 31, 2013
 
 
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
 
$

 
$

 
$
16,420

 
$
16,420

 
$
(6,487
)
 
$
9,933

Total current derivative assets
 
$

 
$

 
$
16,420

 
$
16,420

 
$
(6,487
)
 
9,933

PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
7,893

Current derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
17,826

Noncurrent derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
$
41,056

Noncurrent derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
41,056

Current derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Electric commodity
 
$

 
$

 
$
6,487

 
$
6,487

 
$
(6,487
)
 
$

Total current derivative liabilities
 
$

 
$

 
$
6,487

 
$
6,487

 
$
(6,487
)
 

PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
3,583

Current derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
3,583

Noncurrent derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
$
34,207

Noncurrent derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
34,207


(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, 2013. At Dec. 31, 2013, 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 tables present the changes in Level 3 commodity derivatives for the three and nine months ended Sept. 30, 2014, and there were no Level 3 commodity derivatives during the three and nine months ended Sept. 30, 2013:
(Thousands of Dollars)
 
Three Months Ended Sept. 30, 2014
Balance at July 1
 
$
33,942

Purchases
 
4,429

Settlements
 
(8,346
)
Net transactions recorded during the period:
 
 
Losses recognized as regulatory assets and liabilities
 
(7,785
)
Balance at Sept. 30
 
$
22,240

(Thousands of Dollars)
 
Nine Months Ended Sept. 30, 2014
Balance at Jan. 1
 
$
9,933

Purchases
 
43,904

Settlements
 
(23,001
)
Net transactions recorded during the period:
 
 
Losses recognized as regulatory assets and liabilities
 
(8,596
)
Balance at Sept. 30
 
$
22,240



19


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, 2014 and 2013.

Fair Value of Long-Term Debt

As of Sept. 30, 2014 and Dec. 31, 2013, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
 
Sept. 30, 2014
 
Dec. 31, 2013
(Thousands of Dollars)
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Long-term debt, including current portion
 
$
1,349,604

 
$
1,524,990

 
$
1,199,865

 
$
1,307,035


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, 2014 and Dec. 31, 2013, 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
(Thousands of Dollars)
2014
 
2013
 
2014
 
2013
Interest income
$
73

 
$
48

 
$
313

 
$
308

Other nonoperating income
1

 
1

 
1

 
6

Insurance policy expense
(8
)
 
(164
)
 
(336
)
 
(372
)
Other income (expense), net
$
66

 
$
(115
)
 
$
(22
)
 
$
(58
)

10.
Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)
 
 
Three Months Ended Sept. 30
 
 
2014
 
2013
 
2014
 
2013
(Thousands of Dollars)
 
Pension Benefits
 
Postretirement Health
Care Benefits
Service cost
 
$
2,296

 
$
2,404

 
$
312

 
$
342

Interest cost
 
5,111

 
4,477

 
643

 
588

Expected return on plan assets
 
(6,545
)
 
(5,993
)
 
(812
)
 
(796
)
Amortization of prior service cost (credit)
 
14

 
218

 
(100
)
 
(121
)
Amortization of net loss (gain)
 
3,332

 
4,287

 
(80
)
 
(2
)
Net periodic benefit cost (credit)
 
4,208

 
5,393

 
(37
)
 
11

Credits recognized due to the effects of regulation
 
707

 
62

 

 

Net benefit cost (credit) recognized for financial reporting
 
$
4,915

 
$
5,455

 
$
(37
)
 
$
11


20


 
 
Nine Months Ended Sept. 30
 
 
2014
 
2013
 
2014
 
2013
(Thousands of Dollars)
 
Pension Benefits
 
Postretirement Health
Care Benefits
Service cost
 
$
6,888

 
$
7,211

 
$
935

 
$
1,026

Interest cost
 
15,333

 
13,431

 
1,929

 
1,764

Expected return on plan assets
 
(19,635
)
 
(17,978
)
 
(2,435
)
 
(2,388
)
Amortization of prior service cost (credit)
 
41

 
653

 
(301
)
 
(363
)
Amortization of net loss (gain)
 
9,995

 
12,861

 
(241
)
 
(5
)
Net periodic benefit cost (credit)
 
12,622

 
16,178

 
(113
)
 
34

Credits recognized (costs not recognized) due to the effects of regulation
 
2,122

 
(1,330
)
 

 

Net benefit cost (credit) recognized for financial reporting
 
$
14,744

 
$
14,848

 
$
(113
)
 
$
34


In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $4.4 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2014.

11.
Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:
 
 
Gains and Losses on
Cash Flow Hedges
 
(Thousands of Dollars)
 
Three Months Ended Sept. 30, 2014
 
Three Months Ended Sept. 30, 2013
 
Accumulated other comprehensive loss at July 1
 
$
(1,076
)
 
$
(1,247
)
 
Losses reclassified from net accumulated other comprehensive loss
 
44

 
44

 
Net current period other comprehensive income
 
44

 
44

 
Accumulated other comprehensive loss at Sept. 30
 
$
(1,032
)
 
$
(1,203
)
 
 
 
Gains and Losses on
Cash Flow Hedges
 
(Thousands of Dollars)
 
Nine Months Ended Sept. 30, 2014
 
Nine Months Ended Sept. 30, 2013
 
Accumulated other comprehensive loss at Jan. 1
 
$
(1,161
)
 
$
(1,332
)
 
Losses reclassified from net accumulated other comprehensive loss
 
129

 
129

 
Net current period other comprehensive income
 
129

 
129

 
Accumulated other comprehensive loss at Sept. 30
 
$
(1,032
)
 
$
(1,203
)
 

Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2014 and 2013 were as follows:
 
 
Amounts Reclassified from
Accumulated Other
Comprehensive Loss
 
(Thousands of Dollars)
 
Three Months Ended Sept. 30, 2014
 
Three Months Ended Sept. 30, 2013
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
68

(a) 
$
68

(a) 
Total, pre-tax
 
68

 
68

 
Tax benefit
 
(24
)
 
(24
)
 
Total amounts reclassified, net of tax
 
$
44

 
$
44

 

21


 
 
Amounts Reclassified from
Accumulated Other
Comprehensive Loss
 
(Thousands of Dollars)
 
Nine Months Ended Sept. 30, 2014
 
Nine Months Ended Sept. 30, 2013
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
201

(a) 
$
201

(a) 
Total, pre-tax
 
201

 
201

 
Tax benefit
 
(72
)
 
(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.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis 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 do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: 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; 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 market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2013, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2014.

Results of Operations

SPS’ net income was approximately $113.7 million for the nine months ended Sept. 30, 2014, compared with net income of approximately $75.8 million for the same period in 2013. The increase was primarily due to the positive impact of higher electric rates in Texas and New Mexico and weather-normalized sales growth (which is adjusted against a 30-year average of actual weather conditions), partially offset by increased depreciation, operating and maintenance (O&M) expenses and interest charges.


22


Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. 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)
 
2014
 
2013
Electric revenues
 
$
1,494

 
$
1,317

Electric fuel and purchased power
 
(919
)
 
(814
)
Electric margin
 
$
575

 
$
503


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

Electric Revenues
(Millions of Dollars)
 
2014 vs. 2013
Retail rate increases (a)
 
$
43

Fuel and purchased power cost recovery
 
39

Trading
 
36

Transmission revenue
 
17

Non-fuel riders
 
11

Demand revenue
 
4

Sales mix
 
3

Firm wholesale
 
2

Estimated impact of weather
 
(3
)
Other, net
 
(1
)
Total increase in electric revenues
 
$
151

2004 FERC complaint case order (b)
 
26

Total increase in GAAP electric revenues
 
$
177


Electric Margin
(Millions of Dollars)
 
2014 vs. 2013
Retail rate increases (a)
 
$
43

Non-fuel riders
 
11

Transmission revenue, net of costs
 
7

Demand revenue
 
4

Sales mix

 
3

Firm wholesale
 
2

Purchased capacity costs

 
(11
)
Texas wind renewable energy credits
 
(9
)
Estimated impact of weather

 
(3
)
Other, net
 
(1
)
Total increase in electric margin
 
$
46

2004 FERC complaint case order (b)
 
26

Total increase in GAAP electric revenues
 
$
72


(a) 
Retail rates were implemented in New Mexico and Texas.
(b) 
As a result of two orders issued by FERC in August 2013, a pretax charge of approximately $35 million ($31 million in electric revenues, of which $5 million relates to 2013 and $26 million relates to periods prior to 2013, and $4 million in interest charges) was recorded in 2013.


23


Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $6.9 million, or 3.5 percent, for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The following table summarizes the changes in O&M expenses:
(Millions of Dollars)
 
2014 vs. 2013
Plant generation costs
 
$
3

Transmission cost increases
 
1

Employee benefits
 
1

Other, net
 
2

Total increase in O&M expenses
 
$
7


Depreciation and Amortization — Depreciation and amortization increased $8.2 million, or 9.0 percent, for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The increase is primarily due to normal system expansion and a change in amortization as a result of regulatory outcomes.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $2.0 million, or 5.3 percent, for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The increase is primarily due to an increase in property and general taxes.

AFUDC AFUDC increased $4.0 million for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The increase is primarily due to the expansion of transmission facilities.

Interest Charges — Interest charges increased $0.9 million, or 1.5 percent, for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The increase is primarily due to higher long-term debt levels, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $19.4 million for the nine months ended Sept. 30, 2014 compared with the same period in 2013. The increase in income tax expense is primarily due to higher pretax earnings in 2014. The ETR was 35.5 percent for the nine months ended Sept. 30, 2014, compared with 36.6 percent for the same period in 2013.

Public Utility Regulation

SPP Integrated Market (IM) — In 2012 and 2013, the FERC approved proposed revisions to the SPP tariff to allow SPP to operate a day ahead and real time energy and ancillary services market. The SPP IM began operations on March 1, 2014. SPS submitted filings to the FERC to modify its wholesale power sales contracts to allow recovery of SPP IM charges and revenues through the SPP wholesale fuel clause adjustment (FCA). The FERC approved the FCA tariff filings in April 2014. SPS also requested approval to make sales to the SPP IM at market-based rates, which the FERC approved in February 2014. SPS has also filed changes to its QF tariffs in Texas and New Mexico to revise the pricing applied to QF purchases to be consistent with the new market. In February 2014, SPS was granted interim approval of the revised QF tariff in Texas to coincide with the start of the IM. The New Mexico revised QF tariff was approved in March 2014.

Transmission Notifications to Construct (NTCs) — In April 2014, the SPP Board of Directors approved the High Priority Incremental Load Study Report, a reliability assessment that evaluated the anticipated transmission needs of certain parts of the SPP resulting from expected load growth in the area. As a result of this study, SPS has received NTCs and conditional NTCs for 44 new transmission projects to be placed into service by 2020. SPS is in the process of evaluating these projects and their costs internally before submitting certificates of convenience and necessity (CCNs) to the PUCT and the NMPRC. These projects are intended to provide regional reliability benefits as well as the ability to serve the increase in load in Southeastern New Mexico.

TUCO substation to Woodward, Okla. 345 kilovolt (KV) transmission line
The TUCO to Woodward District extra high voltage interchange is a 345 KV transmission line. SPS constructed the line to just inside the Oklahoma state line, and Oklahoma Gas and Electric Company (OGE) built from there to Woodward, Okla. SPS’ investment in the TUCO to Woodward line and substation is approximately $205 million and is expected to be recovered from SPP members, including SPS, in accordance with the SPP open access transmission tariff (OATT) and the ratemaking process. The line was placed into service in September 2014.


24


Hitchland substation to Woodward, Okla. 345 KV transmission line
The Hitchland substation to Woodward, Okla. line is a 345 KV double circuit transmission line and associated substation facilities in the Oklahoma and Texas Panhandle. SPS built the first 30 miles and OGE completed the line from there to Woodward, Okla. SPS’ investment for the Hitchland to Woodward line and substation is approximately $59 million and is expected to be recovered from SPP members in accordance with the SPP OATT and the ratemaking process. The line was placed into service in May 2014.

Potash Junction substation to Roadrunner substation 345 KV transmission line
In April 2014, SPS filed a CCN with the NMPRC for a new 345 KV transmission line from the Potash Junction substation to the Roadrunner substation, both near Carlsbad, N.M. The proposed line would run 40 miles and cost an estimated $54 million. Approval for the CCN is pending. A hearing has been scheduled for November 2014.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation (NERC) 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, 2013. 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 — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In October 2014, the FERC upheld the determination of the long term growth rate to be used in its new ROE methodology. Several parties sought rehearing of the June 2014 order and therefore the new FERC policy may be subject to additional changes.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued a final ruling, Order 1000, adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities to develop tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal Right of First Refusal (ROFR) to build certain types of transmission projects in its service area. Various parties filed appeals of Order 1000 with the D.C. Circuit. In August 2014, the court denied all appeals and upheld Order 1000 in its entirety. The court indicated, however, that challenges to removal of federal ROFR provisions from individual contracts or tariffs could be considered in individual compliance filings.

The removal of a federal ROFR would eliminate rights that SPS currently has under the SPP tariffs to build certain transmission projects within its footprint. In Order 1000, FERC instead required that the opportunity to build such projects would extend to competitive transmission developers. SPP made its initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation. Subsequently, the FERC ruled on the initial regional compliance filings, directing further compliance changes. The SPP regional compliance filings remain pending further action by the FERC.

Initial filings to address interregional planning and cost allocation requirements with other regions were also made by SPP and are pending initial action by the FERC.

SPS believes that Texas statutes protect the ROFR of incumbent utilities operating outside of the ERCOT region to construct and own transmission interconnected to their systems, though this view is disputed by some parties. The State of New Mexico does not have legislation establishing ROFR rights for incumbent utilities.

Regional planning and cost allocation
The FERC issued its initial order on SPP’s Order 1000 regional compliance filing in July 2013. The FERC identified several areas that required a further compliance filing by SPP to address regional compliance issues. Among other things, the FERC rejected SPP’s proposal to retain a ROFR for new transmission projects with operational voltages between 100 KV and 300 KV. Requests for rehearing of the FERC’s July 2013 order were filed in August 2013 and are pending the FERC’s action. The SPP regional compliance filing was filed in November 2013 and is currently pending FERC action. The SPP regional compliance tariffs went into effect March 1, 2014, subject to the outcome of the additional FERC proceedings.

Interregional planning and cost allocation
The SPP interregional compliance filing was submitted in July 2013 and is pending initial FERC action.


25


NERC Critical Infrastructure Protection (CIP) Requirements — The FERC has approved version 5 of NERC’s CIP standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. SPS is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In July 2014, the FERC issued a notice of proposed rulemaking generally proposing to adopt NERC’s proposed CIP standard related to physical security for bulk electric system facilities. However, the FERC proposed a modification to the standard that would allow certain governmental authorities, including FERC, to revise an entity’s list of critical facilities. SPS expects prompt action by FERC to finalize the rule with a likely effective date in 2015. SPS is currently in the process of evaluating and identifying the critical facilities impacted to better determine the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

SPP and Midcontinent Independent Transmission System Operator, Inc. (MISO) Complaints Regarding RTO Joint Operating Agreement (JOA) SPP and MISO have a longstanding dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagree over MISO’s authority to transmit power over SPP transmission facilities between the traditional MISO region in the Midwest and the Entergy system. Several cases have been filed with the FERC by MISO and SPP. In March 2014, FERC issued an order setting all of the cases for settlement judge proceedings, or hearings if settlement fails. If SPP is successful in charging MISO for use of the SPP system, the NSP System would experience higher costs from MISO, which could be material, but SPS would collect revenues from SPP. The outcome of the JOA disputes, and the potential impact on Xcel Energy, are uncertain at this time. In June 2014, the FERC accepted a proposed tariff change by MISO to recover transmission charges imposed by SPP retroactive to Jan. 29, 2014, and set the issues for settlement judge and hearing procedures which are still underway.

Item 4CONTROLS 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 the 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, 2014, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is 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 discussion of proceedings involving utility rates and other regulatory matters.


26


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, 2013, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4 MINE SAFETY DISCLOSURES

None.

Item 5 OTHER INFORMATION

None.

Item 6 — EXHIBITS
Indicates incorporation by reference
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)).

10.01*
Amended and Restated Credit Agreement, dated as of Oct. 14, 2014 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.04 to Form 8-K, dated Oct. 14, 2014 (file no. 001-03789)).
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.
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.
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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, 2014 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.


27


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
 
 
 
Nov. 3, 2014
By:
/s/ JEFFREY S. SAVAGE
 
 
Jeffrey S. Savage
 
 
Vice President and Controller
 
 
 
 
 
/s/ TERESA S. MADDEN
 
 
Teresa S. Madden
 
 
Senior Vice President, Chief Financial Officer and Director

28