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EX-99.01 - EXHIBIT 99.01 - SOUTHWESTERN PUBLIC SERVICE COspsex990110k2017.htm
EX-32.01 - EXHIBIT 32.01 - SOUTHWESTERN PUBLIC SERVICE COspsex320110k2017.htm
EX-31.02 - EXHIBIT 31.02 - SOUTHWESTERN PUBLIC SERVICE COspsex310210k2017.htm
EX-31.01 - EXHIBIT 31.01 - SOUTHWESTERN PUBLIC SERVICE COspsex310110k2017.htm
EX-23.01 - EXHIBIT 23.01 - SOUTHWESTERN PUBLIC SERVICE COspsex230110k2017.htm
EX-12.01 - EXHIBIT 12.01 - SOUTHWESTERN PUBLIC SERVICE COspsex120110k2017.htm
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549

FORM 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number:  001-03789
SOUTHWESTERN PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
New Mexico
 
75-0575400
State or other jurisdiction of incorporation or organization
 
(I.R.S. Employer Identification No.)
790 South Buchanan Street, Amarillo, Texas  79101
(Address of principal executive offices)
Registrant’s telephone number, including area code:  303-571-7511
Securities registered pursuant to Section 12(b) of the Act:  None
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  ¨ Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  ¨ Yes x No
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 Website, 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 if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act
Large accelerated filer ¨
 
Accelerated filer ¨
Non-accelerated filer x
 
Smaller Reporting Company ¨
(Do not check if a smaller reporting company)
 
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  ¨ Yes   x No
As of Feb. 23, 2018, 100 shares of common stock, par value $1 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Item 14 of Form 10-K is set forth under the heading “Independent Registered Public Accounting Firm – Audit and Non-Audit Fees” in Xcel Energy Inc.’s definitive Proxy Statement for the 2018 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about April 3, 2018. Such information set forth under such heading is incorporated herein by this reference hereto.
Southwestern Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).
 



TABLE OF CONTENTS
Index
PART I
 
 
PART II
 
 
PART III
 
 
PART IV
 
 

This Form 10-K is filed by SPS. SPS is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available on various filings with the SEC. This report should be read in its entirety.

2


PART I
Item lBusiness

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
NCE
New Century Energies, Inc.
NSP-Minnesota
Northern States Power Company, a Minnesota corporation
NSP-Wisconsin
Northern States Power Company, a Wisconsin corporation
PSCo
Public Service Company of Colorado
SPS
Southwestern Public Service Company
Utility subsidiaries
NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy
Xcel Energy Inc. and its subsidiaries
 
 
Federal and State Regulatory Agencies
CFTC
Commodity Futures Trading Commission
D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
DOE
United States Department of Energy

EPA
United States Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
IRS
Internal Revenue Service
NERC
North American Electric Reliability Corporation
NMPRC
New Mexico Public Regulation Commission
PHMSA
Pipeline and Hazardous Materials Safety Administration
PUCT
Public Utility Commission of Texas
SEC
Securities and Exchange Commission
 
 
Electric and Resource Adjustment Clauses
DCRF
Distribution cost recovery factor
DSM
Demand side management
EE
Energy efficiency
EECRF
Energy efficiency cost recovery factor
FPPCAC
Fuel and purchased power cost adjustment clause
PCRF
Power cost recovery factor
TCRF
Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)
 
 
Other Terms and Abbreviations
AFUDC
Allowance for funds used during construction
ALJ
Administrative law judge
APBO
Accumulated postretirement benefit obligation
ARO
Asset retirement obligation
ASC
FASB Accounting Standards Codification
ASU
FASB Accounting Standards Update
BART
Best available retrofit technology
CAA
Clean Air Act
CAIR
Clean Air Interstate Rule
C&I
Commercial and Industrial
CO2
Carbon dioxide
CCN
Certificate of convenience and necessity
CPP
Clean Power Plan
CSAPR
Cross-State Air Pollution Rule
CWIP
Construction work in progress
EGU
Electric generating unit

3


ERCOT
Electric Reliability Council of Texas
ETR
Effective tax rate
FASB
Financial Accounting Standards Board
FTR
Financial transmission right
GAAP
Generally accepted accounting principles
GHG
Greenhouse gas
IPP
Independent power producers
IRC
Internal Revenue Code
ITC
Investment tax credit
MISO
Midcontinent Independent System Operator, Inc.
Moody’s
Moody’s Investor Services
NAAQS
National Ambient Air Quality Standard
Native load
Customer demand of retail and wholesale customers whereby a utility has an obligation to serve under statute or long-term contract.
NAV
Net asset value
NOL
Net operating loss
NOx
Nitrogen oxide
NTC
Notifications to construct
O&M
Operating and maintenance
OCI
Other comprehensive income
PJM
PJM Interconnection, LLC
PM
Particulate matter
PPA
Purchased power agreement
PRP
Potentially responsible party
PSIA
Pipeline system integrity adjustment
PTC
Production tax credit
PV
Photovoltaic
QF
Qualifying facilities
R&E
Research and experimentation
REC
Renewable energy credit
ROE
Return on equity
RPS
Renewable portfolio standards
RTO
Regional Transmission Organization
SIP
State implementation plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool, Inc.
Standard & Poor’s
Standard & Poor’s Ratings Services
TCJA
2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act

 
 
Measurements
KV
Kilovolts
KWh
Kilowatt hours
MMBtu
Million British thermal units
MW
Megawatts
MWh
Megawatt hours


4


COMPANY OVERVIEW

SPS was incorporated in 1921 under the laws of New Mexico.  SPS is a utility engaged primarily in the generation, purchase, transmission, distribution, and sale of electricity in portions of Texas and New Mexico.  SPS provides electric utility service to approximately 390,000 retail customers in Texas and New Mexico.  Approximately 71 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2017 and 2016.  Although SPS’ large C&I electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large C&I electric sales include: oil and gas extraction, as well as petroleum refining and related industries.  For small C&I customers, significant electric retail sales include the following industries: oil and gas extraction and grocery establishments.  Generally, SPS’ earnings contribute approximately 10 percent to 15 percent of Xcel Energy’s consolidated net income.

The wholesale customers served by SPS comprised approximately 29 percent of its total KWh sold in 2017.  

ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. The municipalities’ rate setting decisions are subject to review by the PUCT, which has ultimate authority to set the rates SPS charges in the municipalities. The NMPRC also has jurisdiction over the issuance of securities. SPS is regulated by the FERC for its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. As approved by the FERC, SPS is a transmission-owning member of the SPP RTO and operates within the SPP RTO and SPP IM wholesale market. SPS is authorized to make wholesale electric sales at market-based prices.

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms SPS has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

DCRF — Recovers distribution costs in Texas that are not included in base rates.
EECRF — Recovers costs associated with providing energy efficiency programs in Texas.
EE rider — Recovers costs associated with providing energy efficiency programs in New Mexico.
FPPCAC — Adjusts monthly to recover the actual fuel and purchased power costs.
PCRF — Allows recovery of certain purchased power costs in Texas that are not included in base rates.
RPS — Recovers deferred costs associated with renewable energy programs in New Mexico.
TCRF — Recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas that are not included in base rates.

Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric tariff. SO2 and NOx allowance revenues and costs are also recovered through the fixed fuel and purchased energy recovery factor. The regulations allow retail fuel factors to change up to three times per year.

The fixed fuel and purchased energy recovery factor provides for the over- or under-recovery of fuel and purchased energy expenses. Regulations also require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed four percent of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.

PUCT regulations require periodic examination of SPS’ fuel and purchased energy costs, the efficient use of fuel and purchased energy, fuel acquisition and management policies and purchased energy commitments. SPS is required to file an application for the PUCT to retrospectively review fuel and purchased energy costs at least every three years. In June 2016, SPS filed its fuel reconciliation application which reconciled fuel and purchased power costs for 2013 through 2015. In March 2017, the PUCT approved the application.

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased economic energy cost adjustment clause accepted for filing by the FERC.


5


Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2018, assuming normal weather conditions, is as follows:
 
System Peak Demand (in MW)
 
2017
 
2016
 
2015
 
2018 Forecast
SPS
4,374

 
4,836

 
4,678

 
4,483


The peak demand for the SPS system typically occurs in the summer. The 2017 system peak demand for SPS occurred on July 26, 2017. The decline in peak load from 2016 to 2017 is in part due to cooler weather in 2017. Additionally, the partial requirement contract with Golden Spread ended May 2017, contributing to the lower actual peak demand for SPS. The 2018 forecast assumes normal peak day weather.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases, DSM and new generation options to meet its system capacity requirements. In addition, SPS has evaluated water supply issues at its Tolk facility, concluding that additional resource investment will be required to operate the plant through its existing life. The Ogallala aquifer in this region of the country has depleted more rapidly than expected and SPS installed a horizontal water well that could help to delay the need for a more substantial investment solution. As a result of this issue and to a lesser extent, future environmental rules facing the plant, SPS is seeking a decrease to the remaining life of the facility in its current Texas and New Mexico rate case proceedings (see Note 10).

Purchased Power SPS has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts typically require a periodic capacity charge and an energy charge for energy actually purchased. SPS also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations or to obtain energy at a lower cost.

Purchased Transmission Services SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers.

TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV Transmission Line In 2014, SPP evaluated anticipated transmission needs for certain parts of the SPP region which is commonly known as the High Priority Incremental Load Study. As a result, SPS received 44 transmission projects, with an original estimated cost of $557 million. The most significant of these projects are the TUCO Substation to the Yoakum County Substation to the Hobbs Plant Substation and the Hobbs Plant Substation to the China Draw Substation transmission line projects.

In 2016 and 2017, SPS received CCNs for the three segments of the TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 KV transmission line, which are expected to be in service in the second quarter of 2020. This 345 KV transmission line is part of a larger project which includes an additional 345 KV transmission line from the Hobbs Plant Substation to the China Draw Substation, which was approved by the NMPRC in 2016 and is anticipated to be in service by June 2018. The estimated total investment for these transmission lines is approximately $402 million. 

Wind Proposals — In March 2017, SPS filed proposals with the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind generation through two wind farms for a cost of approximately $1.6 billion. In addition, the proposal includes a PPA for 230 MW of wind.

In December 2017, SPS and parties filed a unanimous stipulation with the NMPRC. The stipulation is subject to approval by the NMPRC. The key terms of the stipulation are listed below:

An investment cap of $1,675 per KW, which is equal to 102.5 percent of the estimated construction costs;
SPS customers would receive a credit to their bills if actual capacity factors fall below 48 percent;
SPS customers would receive 100 percent of the federal PTC; and
SPS can file a HTY rate case and include projected capital additions for the wind farms five months beyond the end of the test year. Interim rates would also be made effective 30 days after filing which will allow SPS to closely match the start of cost recovery for that wind farm with the in service date.


6


On Feb. 9, 2018, the Hearing Examiner issued a certification of stipulation (certification) recommending approval of all but one aspect of the stipulation, which is the provision for interim rate recovery of SPS’ investment in the two wind farms. On Feb. 19, 2018, SPS filed exceptions to the recommended decision, as did other parties to the stipulation.

In addition, SPS has reached a settlement in principle with parties in Texas and is working towards finalizing a stipulation. SPS has shared an updated analysis with all parties which shows the wind projects remain cost-effective following the passage of the TCJA. The settlements require approval by the NMPRC and PUCT. Both commissions are expected to rule on the settlements by the end of the first quarter of 2018. The Hale wind project in Texas and the Sagamore wind project in New Mexico are scheduled to be in service by mid-2019 and year-end 2020, respectively.

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

In February 2018, SPS, LP&L, the PUCT Staff and various other parties filed a stipulation that provides SPS’ customers with an Interconnection Switching Fee of approximately $24 million to compensate them for the transfer of LP&L’s load from SPP to ERCOT. Under the settlement, SPS would allocate the Interconnection Switching Fee to its Texas and New Mexico retail and wholesale transmission customers through a bill credit following LP&L’s load transition to ERCOT (tentatively, June 2021). A PUCT decision is expected in March 2018. No final decision regarding LP&L’s departure or its potential timing is expected until completion of the PUCT proceedings.
Texas State ROFR Request for Declaratory Order — In February 2017, SPS and SPP filed a joint petition with the PUCT for a declaratory order regarding SPS’ ROFR. SPS contended that Texas law grants an incumbent electric utility, operating in areas outside of ERCOT, the ROFR to construct new transmission facilities located in the utility’s service area. SPP stated that Texas law does not provide a clear statement regarding the ROFR for incumbent utilities and therefore SPP was abiding by the portion of its OATT, which requires competitive solicitation to construct and operate new transmission facilities within areas of Texas’ SPP footprint.
In October 2017, the PUCT issued an order finding that SPS does not possess an exclusive right to construct and operate transmission facilities within its service area. In January 2018, SPS and two other parties filed appeals of the PUCT’s order in the Texas State District Court. The appeals have been consolidated. A schedule has not been set for the case.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.
 
 
Coal
 
Natural Gas
 
Weighted Average
Owned Fuel Cost
SPS Generating Plants
 
Cost
 
Percent
 
Cost
 
Percent
 
2017
 
$
2.18

 
74
%
 
$
3.39

 
26
%
 
$
2.50

2016
 
2.12

 
70

 
2.81

 
30

 
2.32

2015
 
2.12

 
73

 
3.11

 
27

 
2.39


See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal  SPS purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. The coal supply contract with TUCO expires on Dec. 31, 2022 for both Harrington and Tolk.

7



SPS normally maintains approximately 35 - 50 days of coal inventory. As of Dec. 31, 2017 and 2016, coal inventories at SPS were approximately 52 and 64 day supply, respectively. Milder weather, purchase commitments and relatively low power and natural gas prices resulted in coal inventories being above optimal levels. SPS’ generation stations primarily use low-sulfur western coal from mines operating in Wyoming. TUCO has coal agreements to supply 79 percent of SPS’ estimated coal requirements in 2018 and a declining percentage of requirements in subsequent years. SPS’ general coal purchasing objective is to contract for approximately 75 percent of requirements for the first year, 40 percent of requirements in year two and 20 percent of requirements in year three.

Natural gas  SPS uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas for SPS’ power plants is procured under contracts to provide an adequate supply of fuel, which typically is purchased with terms of one year or less. The transportation and storage contracts expire between 2018 to 2033. All of the natural gas supply contracts have variable pricing that is tied to various natural gas indices.

Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. SPS’ commitments related to gas supply contracts were approximately $11 million and $17 million and commitments related to gas transportation and storage contracts were approximately $191 million and $161 million at Dec. 31, 2017 and 2016, respectively.

SPS has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and solar power from PPAs. As of Dec. 31, 2017, SPS is in compliance with mandated RPS, which require generation from renewable resources of 3.7 percent of Texas electric retail sales and 15.0 percent of New Mexico electric retail sales.

Renewable energy as a percentage of SPS’ total energy:
 
 
2017
 
2016
Renewable
 
24.0
%
 
22.8
%
Wind
 
21.2

 
21.6

Solar
 
1.8

 
1.2


SPS also offers customer-focused renewable energy initiatives. Windsource® allows customers in New Mexico to purchase electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 940 in 2017 from 900 in 2016.

Wind — SPS acquires its wind energy from IPP contracts and QF tariffs. SPS currently has 24 of these agreements in place, with facilities ranging in size from under two MW to 250 MW.

SPS had approximately 1,500 MW of wind energy on its system at the end of 2017 and 2016. In addition to receiving purchased wind energy under these agreements, SPS typically receives wind RECs on certain agreements which are used to meet state renewable resource requirements.
The average cost per MWh of wind energy under the IPP contracts and QF tariffs was approximately $27 for 2017 and $25 for 2016. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements and the year of contract execution.  Generally, contracts executed in 2017 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the federal PTCs. In December 2015, the federal PTCs were extended through 2019 with a phase down on sites that began construction in 2017.

Wholesale and Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. See Item 7 for further discussion.


8


Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 10 to the accompanying financial statements for a discussion of other regulatory matters.

Xcel Energy, which includes SPS, attempts to mitigate the risk of regulatory penalties through formal training on prohibited practices and a compliance function that reviews interaction with the markets under FERC and CFTC jurisdictions. Public campaigns are conducted to raise awareness of the public safety issues of interacting with our electric systems. While programs to comply with regulatory requirements are in place, there is no guarantee the compliance programs or other measures will be sufficient to ensure against violations.

DOE Grid Resiliency Notice of Proposed Rule (NOPR) — In September 2017, the DOE requested the FERC to consider and adopt a Grid Resiliency and Pricing Rule to address threats to the U.S. electrical grid. Under the proposed rule, coal and nuclear generation facilities would have to meet certain criteria to qualify for full recovery of their costs including a fair rate of return. In January 2018, the FERC rejected the DOE’s proposal, but alternatively initiated an inquiry into how RTOs and Independent System Operators address grid resilience. Efforts to resolve U.S. grid resilience issues may result from this proceeding and Xcel Energy plans to monitor and respond as necessary.


9


Electric Operating Statistics

Electric Sales Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
Electric sales (Millions of KWh)
 
 
 
 
 
Residential
3,356

 
3,478

 
3,536

Large C&I
10,721

 
10,518

 
10,334

Small C&I
4,701

 
4,708

 
4,719

Public authorities and other
527

 
555

 
538

Total retail
19,305

 
19,259

 
19,127

Sales for resale
7,759

 
8,689

 
8,694

Total energy sold
27,064

 
27,948

 
27,821

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
306,248

 
305,076

 
304,711

Large C&I
221

 
219

 
221

Small C&I
77,351

 
77,319

 
77,238

Public authorities and other
6,316

 
6,377

 
6,354

Total retail
390,136

 
388,991


388,524

Wholesale
7

 
8

 
8

Total customers
390,143

 
388,999


388,532

 
 
 
 
 
 
Electric revenues (Thousands of Dollars)
 
 
 
 
 
Residential
$
367,234

 
$
343,475

 
$
347,966

Large C&I
516,786

 
462,576

 
445,853

Small C&I
375,961

 
322,599

 
353,450

Public authorities and other
48,045

 
44,892

 
42,963

Total retail
1,308,026

 
1,173,542

 
1,190,232

Wholesale
388,715

 
414,815

 
409,956

Other electric revenues
221,259

 
262,602

 
187,030

Total electric revenues
$
1,918,000

 
$
1,850,959

 
$
1,787,218

 
 
 
 
 
 
KWh sales per retail customer
49,483

 
49,510

 
49,230

Revenue per retail customer
$
3,353

 
$
3,017

 
$
3,063

Residential revenue per KWh

10.94
¢
 

9.88
¢
 

9.84
¢
Large C&I revenue per KWh
4.82

 
4.40

 
4.31

Small C&I revenue per KWh
8.00

 
6.85

 
7.49

Total retail revenue per KWh
6.78

 
6.09

 
6.22

Wholesale revenue per KWh
5.01

 
4.77

 
4.72


10


Energy Source Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal
10,999

 
40
%
 
10,990

 
39
%
 
12,441

 
44
%
Natural Gas
9,950

 
36

 
10,909

 
38

 
10,514

 
36

Wind (a)
5,828

 
21

 
6,120

 
22

 
5,252

 
19

Other (b)
770

 
3

 
347

 
1

 
150

 
1

Total
27,547

 
100
%
 
28,366

 
100
%
 
28,357

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
12,845

 
47
%
 
15,015

 
53
%
 
16,480

 
58
%
Purchased generation
14,702

 
53

 
13,351

 
47

 
11,877

 
42

Total
27,547

 
100
%
 
28,366

 
100
%
 
28,357

 
100
%

(a) 
This category includes wind energy de-bundled from RECs and also includes Windsource RECs. SPS uses RECs to meet or exceed state resource requirements and may sell surplus RECs.
(b) 
Distributed generation from the Solar*Rewards program is not included, and was approximately 26, 14 and 13 million net KWh for 2017, 2016, and 2015, respectively.

Natural Gas Facilities Used for Electric Generation

SPS does not provide retail natural gas service, but purchases and transports natural gas for certain of its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce, and to the jurisdiction of the PHMSA and the PUCT for pipeline safety compliance.

GENERAL

Seasonality

The demand for electric power is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, SPS’ operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. See Item 7 for further discussion.

Competition

SPS is a vertically integrated utility, subject to traditional cost-of-service regulation. However, SPS is subject to different public policies that promote competition and the development of energy markets. SPS’ industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states, including New Mexico, have policies designed to promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to SPS’ electric service business.


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The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, SPS can purchase generation resources from competing wholesale suppliers and use the transmission systems of Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions, including the NMPRC, have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition, FERC Order 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. SPS has franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. While facing these challenges, SPS believes its rates and services are competitive with currently available alternatives.

ENVIRONMENTAL MATTERS

SPS’ facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. SPS’ facilities have been designed and constructed to operate in compliance with applicable environmental standards. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon SPS’ operations. See Notes 10 and 11 to the financial statements for further discussion.

There are significant present and future environmental regulations to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. SPS has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. SPS believes, based on prior state commission practice, it would recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2017, SPS had 1,169 full-time employees and one part-time employee, of which 791 were covered under collective-bargaining agreements. See Note 7 to the financial statements for further discussion.

Item 1A — Risk Factors

Xcel Energy, which includes SPS, is subject to a variety of risks, many of which are beyond our control. Important risks that may adversely affect the business, financial condition and results of operations are further described below. These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.

Oversight of Risk and Related Processes

A key accountability of the Board of Directors is the oversight of material risk, and our Board of Directors employs an effective process for doing so. Management and the Board of Directors have responsibility for overseeing the identification and mitigation of key risks.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Management broadly considers our business, the utility industry, the domestic and global economies and the environment when identifying, assessing, managing and mitigating risk. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the financial disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing SPS’ strategy. The business planning process also identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals, and determines how to prevent inappropriate risk-taking.


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At a threshold level, SPS has developed a robust compliance program and promotes a culture of compliance, including tone at the top, which mitigates risk. The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups and overall business management to mitigate the risks inherent in the implementation of strategy. Building on this culture of compliance, management further mitigates risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of internal corporate areas such as internal audit, the corporate controller and legal services.

Management communicates regularly with the Board of Directors and key stakeholders regarding risk. Senior management presents a periodic assessment of key risks to the Board of Directors. The presentation and the discussion of the key risks provides the Board of Directors with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Management also provides information to the Board of Directors in presentations and communications over the course of the year.

Overall, the Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of SPS. Processes are in place to ensure appropriate risk oversight, as well as identification and consideration of new risks. The Board of Directors regularly reviews management’s key risk assessment informed by these processes, and analyzes areas of existing and future risks and opportunities.

Risks Associated with Our Business

Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain permits, licenses, and other approvals and to comply with a wide variety of environmental requirements including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archaeological and historical resources). Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, shift generation to lower-emitting, but potentially more costly facilities, install pollution control equipment at our facilities, clean up spills and other contamination and correct environmental hazards. Environmental regulations may also lead to shutdown of existing facilities, either due to the difficulty in assuring compliance or that the costs of compliance makes operation of the units no longer economical. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e., clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates or other environmental requirements, it could have a material effect on our results of operations, financial position or cash flows.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2 and other GHGs, particulates, cooling water intakes, water discharges and ash management. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change and other weather, natural disaster and resource depletion impacts.

Climate change can create physical and financial risk. Physical risks from climate change can include changes in weather conditions, changes in precipitation and extreme weather events.


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Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease. Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may result in decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions. Weather conditions could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand may raise electricity prices, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms and associated flooding, tornadoes, wildfires and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages, whether caused by climate change or otherwise, could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought or water depletion conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.

Climate change may impact a region’s economic health, which could impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as regulation of GHG or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Financial Risks

Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies. The state utility commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service and the sale of electric energy in interstate commerce.

The profitability of our operations is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment. We provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of our costs incurred in a test year. We are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing an opportunity to earn a reasonable rate of return on invested capital, in a continued low interest rate environment there has been pressure pushing down ROE. There can also be no assurance that the applicable regulatory commission will judge all of our costs to have been prudent, which could result in cost disallowances, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Changes in the long-term cost-effectiveness or changes to the operating conditions of our assets may result in early retirements and while regulation typically provides relief for these types of changes, there is no assurance that regulators would allow full recovery of all remaining costs leaving all or a portion of these asset costs stranded. Higher than expected inflation may increase costs of construction and operations. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers, or these factors could cause us to exceed commitments made regarding cost caps and result in less than full recovery. Overall, management currently believes prudently incurred costs are generally recoverable given the existing regulatory mechanisms in place.

Adverse regulatory rulings or the imposition of additional regulations could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.


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Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that any of our current ratings will remain in effect for any given period of time, or that a rating will not be lowered or withdrawn entirely by a rating agency. Significant events including a major disallowance of costs, significantly lower returns on equity or equity ratios or impacts of tax policy changes, among others, may impact our cash flows and credit metrics, potentially resulting in a change in our credit ratings. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. Any downgrade could lead to higher borrowing costs and could impact our ability to access capital markets. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment. As a result, we frequently need to access capital markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy. Capital market disruption events, and resulting broad financial market distress could prevent us from issuing short term commercial paper, issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

Credit risk includes the risk that our customers will not pay their bills, which may lead to a reduction in liquidity and an increase in bad debt expense. Credit risk is comprised of numerous factors including the price of products and services provided, the overall economy and local economies in the geographic areas we serve, including local unemployment rates.

Credit risk also includes the risk that various counterparties that owe us money or product will become insolvent and/or breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to participation in organized markets, such as SPP, MISO and ERCOT, in which any credit losses are socialized to all market participants.

We do have additional indirect credit exposures to various domestic and foreign financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long-term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party could be in technical default under the contract, which would enable us to exercise our contractual rights.

Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect our results of operations, financial position or liquidity.

We have defined benefit pension and postretirement plans that cover most of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions, including mortality tables, have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans with modifications that allowed additional flexibility in the timing of contributions. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving SPS could trigger settlement accounting and could require SPS to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.


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Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees have increased in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Changes in industry standards utilized by management in key assumptions (e.g., mortality tables) could have a significant impact on future liabilities and benefit costs. Legislation related to health care could also significantly change our benefit programs and costs.

Federal tax law may significantly impact our business.

SPS collects through regulated rates its estimated federal, state and local tax payments. There are a number of provisions in federal tax law designed to incentivize capital investments which have benefited our customers by keeping our utility subsidiaries’ rates lower than rates calculated without such provisions. Examples include the use of accelerated depreciation for most of our capital investments, PTCs for wind energy, ITCs for solar energy and R&E tax credits and deductions. Changes to federal tax law may benefit or adversely affect our earnings and customer costs. Changes to tax depreciable lives and the value of various tax credits could change the economics of resources and our resource selections. While regulation allows us to incorporate changes in tax law into the rate-setting process, there could be timing delays before regulated rates provide for realization of the tax changes in revenues. In addition, certain IRS tax policies such as the requirement to utilize normalization may impact our ability to economically deliver certain types of resources relative to market prices.

Operational Risks

Our natural gas and electric transmission and operations involve numerous risks that may result in accidents and other operating risks and costs.

Our natural gas transmission and distribution activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. Our electric transmission and distribution activities also include inherent hazards and operating risks such as contact, fire and widespread outages which could cause substantial financial losses. In addition, these natural gas and electric risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. We maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events not fully covered by insurance could have a material effect on our financial position and results of operations. For our natural gas transmission lines located near populated areas, the level of potential damages resulting from these risks is greater.

Additionally, for natural gas the operating or other costs that may be required in order to comply with potential new regulations, including the Pipeline Safety Act, could be significant. The Pipeline Safety Act requires verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. We have programs in place to comply with the Pipeline Safety Act and for systematic infrastructure monitoring and renewal over time. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.


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Our utility operations are subject to long-term planning risks.

Most electric utility investments are long-lived and are planned to be used for decades. Transmission and generation investments typically have long lead times, and therefore are planned well in advance of when they are brought in-service subject to long-term resource plans. These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage, commodity prices, economic activity, costs, regulatory mechanisms, customer behavior, available technology and public policy. The electric utility sector is undergoing a period of significant change. For example, public policy has driven increases in appliance and lighting efficiency and energy efficient buildings, wider adoption and lower cost of renewable generation and distributed generation, including community solar gardens and customer-sited solar, shifts away from coal generation to decrease CO2 emissions and increasing use of natural gas in electric generation driven by lower natural gas prices. Over time, customer adoption of these technologies and increased energy efficiency could result in excess transmission and generation resources as well as stranded costs if SPS is not able to fully recover the costs and investments. These changes also introduce additional uncertainty into long-term planning which gives rise to a risk that the magnitude and timing of resource additions and growth in customer demand may not coincide, and that the preference for the types of additions may change from planning to execution. In addition, we are also subject to longer-term availability of the natural resource inputs such as coal, natural gas, uranium and water to cool our facilities. Lack of availability of these resources could jeopardize long-term operations of our facilities or make them uneconomic to operate.
  
The resource plans reviewed and approved by our state regulators assume continuation of the traditional utility cost of service model under which utility costs are recovered from customers as they receive the benefit of service. SPS is engaged in significant and ongoing infrastructure investment programs to accommodate renewable distributed generation and to maintain high system reliability. Changing customer expectations and changing technologies are requiring significant investments in advanced grid infrastructure. This also increases the exposure to potential outdating of technologies and the resultant risks. SPS is also investing in renewable and natural gas-fired generation to reduce our CO2 emissions profile. The inability of coal mining companies to attract capital could disrupt longer-term supplies. Early plant retirements that may result from these changes could expose us to premature financial obligations, which could result in less than full recovery of all remaining costs. Both decreasing use per customer driven by appliance and lighting efficiency and the availability of cost-effective distributed generation puts downward pressure on load growth. This could lead to under recovery of costs, excess resources to meet customer demand and increases in electric rates. Finally, multiple states served by a single system may not agree as to the appropriate resource mix and the differing views may lead to costs incurred to comply with one jurisdiction that are not recoverable across all of the jurisdictions served by the same assets.

We are subject to commodity risks and other risks associated with energy markets and energy production.

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products as well as natural gas. In many markets in which we operate, emission allowances and/or renewable energy credits are also needed to comply with various statutes and commission rulings associated with energy transactions. As a result we are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting). Actual settlements can vary significantly from estimated fair values recorded, and significant changes from the assumptions underlying our fair value estimates could cause earnings variability.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our customers at previously anticipated costs. Therefore, a significant disruption could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments could have a negative impact on our cash flows and potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and may cause short-term disruptions in our ability to provide electric services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation including rail shipments of coal, electric generation capacity, transmission, natural gas pipeline capacity, etc. Failure to provide service due to disruptions could also result in fines, penalties or cost disallowances through the regulatory process.


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As we are a subsidiary of Xcel Energy Inc. we may be negatively affected by events impacting the credit or liquidity of Xcel Energy Inc. and its affiliates.

If Xcel Energy Inc. were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s credit rating below investment grade, Xcel Energy Inc. may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy Inc.’s debt securities below investment grade, it would increase Xcel Energy Inc.’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2017, Xcel Energy Inc. and its utility subsidiaries had approximately $14.5 billion of long-term debt and $1.3 billion of short-term debt and current maturities. Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2017, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $19 million and immaterial exposure. Xcel Energy also had additional guarantees of $53 million at Dec. 31, 2017 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We are a wholly owned subsidiary of Xcel Energy Inc. Xcel Energy Inc. can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

All of the members of our Board of Directors, as well as many of our executive officers, are officers of Xcel Energy Inc. Our Board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy Inc. In 2017, 2016 and 2015 we paid $109 million, $85 million and $101 million of dividends to Xcel Energy Inc., respectively. If Xcel Energy Inc.’s cash requirements increase, our Board of Directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs. This could adversely affect our liquidity. The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc., by requiring a minimum equity-to-total capitalization ratio. See Item 5 for further discussion on dividend limitations.

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Increased public awareness and concern regarding climate change may result in more state, regional and/or federal requirements to reduce or mitigate the effects of GHGs. Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities may be subject to additional regulation at either the state or federal level in the future. Such regulations could impose substantial costs on our system. International agreements could have an impact to the extent they lead to future federal or state regulations.


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In 2015, the 21st Conference of the Parties to the United Nations Framework Convention on Climate Change reached consensus among 190 nations on an agreement (the Paris Agreement) that establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”), with a goal of holding the increase in global average temperature to below 2o Celsius above pre-industrial levels and an aspiration to limit the increase to 1.5o Celsius. If implemented, the Paris Agreement could result in future additional GHG reductions in the United States. On June 21, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement. Such a withdrawal, under terms of the Agreement, becomes effective in four years. Many state and local government entities, however, have indicated that they intend to pursue GHG mitigation with a goal of achieving the GHG reductions in the United States anticipated by the Paris Agreement.

We have been, and in the future may be, subject to climate change lawsuits. An adverse outcome in any of these cases could require substantial capital expenditures and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows and financial condition if such costs are not recovered through regulated rates.

Some states and localities have indicated a desire to continue to pursue climate policies even in the absence of federal mandates. All of the steps that Xcel Energy has taken to date to reduce GHG emissions, including energy efficiency measures, adding renewable generation or retiring or converting coal plants to natural gas, occurred under state-endorsed resource plans, renewable energy standards and other state policies. While those actions likely would have put Xcel Energy in a good position to meet federal standards under the CPP or the Paris Agreement, repeal of these policies would not impact those state-endorsed actions and plans.

Whether under state or federal programs, an important factor is our ability to recover the costs incurred to comply with any regulatory requirements in a timely manner. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of up to $1.2 million per violation per day, particularly as it relates to energy trading activities for both electricity and natural gas. Under statute, the FERC can adjust penalties for inflation. In addition, NERC electric reliability standards and critical infrastructure protection requirements are mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations. Additionally, the PHMSA, the Occupational Safety and Health Administration and other federal agencies also have penalty authority. In the event of serious incidents, these agencies have become more active in pursuing penalties. Some states have the authority to impose substantial penalties in the event of non-compliance. If a serious reliability or safety incident did occur, it could have a material effect on our operations or financial results.

Macroeconomic Risks

Economic conditions impact our business.

Our operations are affected by local, national and worldwide economic conditions. Growth in our customer base is correlated with economic conditions. SPS serves a large number of petrochemical extraction and processing businesses in Texas and New Mexico. While the number of customers is growing, sales growth is relatively modest due to depressed oil commodity prices. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which is discussed in the capital market risk factor section above.

Economic conditions may be impacted by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. We operate in a capital intensive industry, and federal policy on trade could significantly impact the costs of the materials we use. We may be at risk for higher than anticipated inflation both with respect to our own workforce, as well as our materials and labor that we contract for with others. There may be delays before these higher costs can be recovered in rates.


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Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information and control systems may be targets of terrorist activities. Any such disruption could impact operations or result in a decrease in revenues and additional costs to repair and insure our assets. These disruptions could have a material impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business. We have already incurred increased costs for security and capital expenditures in response to these risks. In addition, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection. In addition, we may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business, as well as our brand and reputation. Because our generation, the transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (such as severe storm, severe temperature extremes, wildfires, solar storms, generator or transmission facility outage, breakdown or failure of equipment, pipeline rupture, railroad disruption, operator error, sudden and significant increase or decrease in wind generation or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.

The degree to which we are able to maintain day-to-day operations in response to unforeseen events will in part determine the financial impact of certain events on our financial condition and results. It is difficult to predict the magnitude of such events and associated impacts.

A cyber incident or cyber security breach could have a material effect on our business.

We operate in an industry that requires the continued operation of sophisticated information technology and control systems and network infrastructure. In addition, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems (such as information about our customers, employees, operations, infrastructure and assets) could be affected by cyber security incidents, including those caused by human error. Our industry has begun to see an increased volume and sophistication of cyber security incidents from international activist organizations, Nation States and individuals. Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations or exposing us to liability. Our generation, transmission systems and natural gas pipelines are part of an interconnected system. Therefore, a disruption caused by the impact of a cyber security incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources of our third party service providers’ operations, could also negatively impact our business. Our supply chain for procurement of digital equipment may expose software or hardware to these risks and could result in a breach or significant costs of remediation. In addition, such an event would likely receive regulatory scrutiny at both the federal and state level. We are unable to quantify the potential impact of cyber security threats or subsequent related actions. These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may cause significant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.


20


We maintain security measures designed to protect our information technology and control systems, network infrastructure and other assets. However, these assets and the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information. If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our business, our brand, and our reputation. The cyber security threat is dynamic and evolves continually, and our efforts to prioritize network monitoring may not be effective given the constant changes to threat vulnerability.

Rising energy prices could negatively impact our business.

Although commodity prices are currently relatively low, if fuel costs increase, customer demand could decline and bad debt expense may rise, which could have a material impact on our results of operations. While we have fuel clause recovery mechanisms, higher fuel costs could significantly impact our results of operations if costs are not recovered. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. Low fuel costs could have a positive impact on sales, though low oil and natural prices could negatively impact oil and gas production activities and subsequently our sales volumes and revenue. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric utility business is seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition, results of operations, or cash flows.

Our operations use third party contractors in addition to employees to perform periodic and on-going work.
We rely on third party contractors with specific qualifications to perform work both for ongoing operations and maintenance and for capital construction. We have contractual arrangements with these contractors which typically include performance standards, progress payments, insurance requirements and security for performance. Cyber security breaches seen in the news have at times exploited third party equipment or software in order to gain access. Poor vendor performance could impact on going operations, restoration operations, our reputation and could introduce financial risk or risks of fines.

Item 1B — Unresolved Staff Comments

None.


21


Item 2 — Properties

Virtually all of the utility plant property of SPS is subject to the lien of its first mortgage bond indenture.

Electric Utility Generating Stations:
 
 
 
 
 
 
 
Station, Location and Unit
 
Fuel
 
Installed
 
Summer 2017
Net Dependable
Capability (MW)
 
Steam:
 
 
 
 
 
 
 
Cunningham-Hobbs, N.M., 2 Units
 
Natural Gas
 
1957-1965
 
254

 
Harrington-Amarillo, Texas, 3 Units
 
Coal
 
1976-1980
 
1,018

 
Jones-Lubbock, Texas, 2 Units
 
Natural Gas
 
1971-1974
 
486

 
Maddox-Hobbs, N.M., 1 Unit
 
Natural Gas
 
1967
 
112

 
Nichols-Amarillo, Texas, 3 Units
 
Natural Gas
 
1960-1968
 
457

 
Plant X-Earth, Texas, 4 Units
 
Natural Gas
 
1952-1964
 
411

 
Tolk-Muleshoe, Texas, 2 Units
 
Coal
 
1982-1985
 
1,067

 
Combustion Turbine:
 
 
 
 
 
 
 
Carlsbad-Carlsbad, N.M., 1 Unit
 
Natural Gas
 
1968
 

 (a)
Cunningham-Hobbs, N.M., 2 Units
 
Natural Gas
 
1998
 
212

 
Jones-Lubbock, Texas, 2 Units
 
Natural Gas
 
2011-2013
 
336

 
Maddox-Hobbs, N.M., 1 Unit
 
Natural Gas
 
1963-1976
 
61

 
 
 
 
 
Total
 
4,414

 
(a) Carlsbad Unit 5 was retired on Dec. 31, 2017.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2017:
Conductor Miles
 
345 KV
8,516

230 KV
9,608

115 KV
13,555

Less than 115 KV
24,795


SPS had 454 electric utility transmission and distribution substations at Dec. 31, 2017.

Item 3 — 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 11 to the financial statements for further discussion of legal claims and environmental proceedings. See Item 1 and Note 10 to the financial statements for a discussion of proceedings involving utility rates and other regulatory matters.

Item 4Mine Safety Disclosures

None.


22


PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

SPS is a wholly owned subsidiary of Xcel Energy Inc. and there is no market for its common equity securities. SPS has dividend restrictions imposed by FERC rules and state regulatory commissions:

Dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.
The most restrictive dividend limitation for SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating. SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.8 percent at Dec. 31, 2017 and $542 million in retained earnings was not restricted.

See Note 4 to the financial statements for further discussion of SPS’ dividend policy.

The dividends declared during 2017 and 2016 were as follows:
(Thousands of Dollars)
 
2017
 
2016
First quarter
 
$
26,715

 
$
25,645

Second quarter
 
25,014

 
19,388

Third quarter
 
26,166

 
27,498

Fourth quarter
 
26,753

 
30,870


Item 6 — Selected Financial Data

This is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7 — 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 I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions I(2)(a) of Form 10-K 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 financial statements and the related notes to the financial statements.


23


Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements, including the TCJA’s impact to SPS and its customers, as well as assumptions and other statements identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2017 (including risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

Results of Operations

SPS’ net income was approximately $159 million for 2017, compared with net income of approximately $152 million for 2016. Rate increases in New Mexico and a lower ETR were partially offset by higher depreciation expense and O&M expenses.

Electric Revenues and Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Changes in fuel or purchased power costs can impact earnings as the fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses. The following tables details the electric revenues and margin:
(Millions of Dollars)
 
2017
 
2016
Electric revenues
 
$
1,918

 
$
1,851

Electric fuel and purchased power
 
(1,055
)
 
(1,035
)
Electric margin
 
$
863

 
$
816


The following tables summarize the components of the changes in electric revenues and electric margin for the year ended Dec. 31:

Electric Revenues
(Millions of Dollars)
 
2017 vs. 2016
Retail rate increases (Texas and New Mexico)
 
$
62

Wholesale transmission revenue, net of costs
 
16

Demand revenue
 
12

Firm wholesale
 
(20
)
Estimated impact of weather
 
(7
)
Other, net
 
4

Total increase in electric revenues
 
$
67



24


Electric Margin
(Millions of Dollars)
 
2017 vs. 2016
Retail rate increases (Texas and New Mexico)
 
$
62

Demand revenue
 
12

Renewable energy credits
 
7

Firm wholesale
 
(20
)
Estimated impact of weather
 
(7
)
Fuel handling and procurement
 
(5
)
Wholesale transmission revenue, net of costs
 
(3
)
Other, net
 
1

Total increase in electric margin
 
$
47


Non-Fuel Operating Expense and Other Items

O&M Expenses O&M expenses increased $20 million, or 7.5 percent, for 2017 compared with 2016. The increase primarily relates to prior year deferrals associated with the Texas 2016 rate case. The significant changes are summarized in the table below:
(Millions of Dollars)
 
2017 vs. 2016
Texas 2016 electric rate case cost deferral
 
$
16

Electric distribution costs
 
4

Employee benefits expense
 
1

Plant generation costs
 
(4
)
Other, net
 
3

Total increase in O&M expenses
 
$
20


Depreciation and Amortization — Depreciation and amortization expense increased $31 million, or 19.4 percent, for 2017 compared with 2016. The increase was primarily attributable to deferred depreciation expense from the 2016 Texas electric rate case and capital investments.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $6 million, or 10.0 percent, for 2017 compared with 2016. The increase was primarily due to higher property taxes in Texas.

Income Taxes — Income tax expense decreased $14 million for 2017 compared with 2016. The decrease in income tax expense was primarily due to the estimated one-time, non-cash, income tax benefit recognized in the fourth quarter related to the TCJA (see Note 6) and a net tax benefit related to the resolution of appeals/audits in 2017. The ETR was 30.1 percent for 2017, compared with 35.1 percent for 2016. The lower ETR in 2017 was primarily due to the adjustments referenced above.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

SPS is exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 9 to the financial statements for further discussion of market risks associated with derivatives.

SPS is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While SPS expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose SPS to some credit and nonperformance risk.


25


Though no material non-performance risk currently exists with the counterparties to SPS’ commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securities in the master pension trust, as well as SPS’ ability to earn a return on short-term investments of excess cash.

Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into short- and long-term physical purchase and sales contracts for electric capacity, energy and energy-related products. Commodity price risk is also managed through the use of financial derivative instruments. SPS’ risk management policy allows it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans.

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

Interest Rate Risk — SPS is subject to the risk of fluctuating interest rates in the normal course of business. SPS’ risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

At Dec. 31, 2017, a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would have no impact annual pretax interest expense, and at Dec. 31, 2016 a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would impact annual pretax impact interest expense by approximately $0.5 million. See Note 9 to the financial statements for a discussion of SPS’ interest rate derivatives.

Credit Risk — SPS is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance on their contractual obligations. SPS maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

At Dec. 31, 2017, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $1.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $1.3 million. At Dec. 31, 2016, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $0.3 million, while a decrease in prices of 10 percent would have resulted in a decrease in credit exposure of $0.3 million.

SPS conducts standard credit reviews for all counterparties. 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. Distress in the financial markets could increase SPS’ credit risk.

Fair Value Measurements

SPS follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 9 to the financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — SPS continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2017. SPS also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2017.


26


Commodity derivative assets and liabilities assigned to Level 3 consist of FTRs. Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities included $14.7 million and $2.0 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2017.

Item 8 — Financial Statements and Supplementary Data

See 15-1 in Part IV for an index of financial statements included herein.

See Note 15 to the financial statements for summarized quarterly financial data.


27


Management Report on Internal Controls Over Financial Reporting

The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting. SPS’ internal control system was designed to provide reasonable assurance to Xcel Energy Inc.’s and SPS’ management and board of directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

In 2016, SPS implemented the general ledger modules of a new enterprise resource planning system. SPS initiated and implemented additional work management systems modules in 2017. SPS does not believe this implementation had an adverse effect on its internal control over financial reporting.

SPS management assessed the effectiveness of SPS’ internal control over financial reporting as of Dec. 31, 2017. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we believe that, as of Dec. 31, 2017, SPS’ internal control over financial reporting is effective at the reasonable assurance level based on those criteria.

/s/ BEN FOWKE
 
/s/ ROBERT C. FRENZEL
Ben Fowke
 
Robert C. Frenzel
Chairman and Chief Executive Officer
 
Executive Vice President, Chief Financial Officer
Feb. 23, 2018
 
Feb. 23, 2018


28


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
Southwestern Public Service Company

Opinion on the Financial Statements
We have audited the accompanying balance sheets of Southwestern Public Service Company (the "Company") as of December 31, 2017 and 2016, the related statements of income, comprehensive income, cash flows, and common stockholder’s equity, for each of the three years in the period ended December 31, 2017, and the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 23, 2018

We have served as the Company's auditor since 2002.


29


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME
(amounts in thousands of dollars)
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
 
 
 
 
 
 
Operating revenues
$
1,918,000

 
$
1,850,959

 
$
1,787,218

 
 
 
 
 
 
Operating expenses
 
 
 
 
 
Electric fuel and purchased power
1,055,333

 
1,034,950

 
1,001,083

Operating and maintenance expenses
289,555

 
269,471

 
289,856

Demand side management program expenses
15,525

 
16,028

 
13,365

Depreciation and amortization
193,915

 
162,429

 
150,913

Taxes (other than income taxes)
66,863

 
60,800

 
57,536

Total operating expenses
1,621,191

 
1,543,678

 
1,512,753

 
 
 
 
 
 
Operating income
296,809

 
307,281

 
274,465

 
 
 
 
 
 
Other income (expense), net
2,359

 
91

 
(6
)
Allowance for funds used during construction — equity
9,310

 
9,981

 
7,378

 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
Interest charges — includes other financing costs of
$2,491, $3,055 and $3,158, respectively
86,233

 
88,671

 
84,040

Allowance for funds used during construction — debt
(5,384
)
 
(5,589
)
 
(4,491
)
Total interest charges and financing costs
80,849

 
83,082

 
79,549

 
 
 
 
 
 
Income before income taxes
227,629

 
234,271

 
202,288

Income taxes
68,416

 
82,114

 
75,025

Net income
$
159,213

 
$
152,157

 
$
127,263


See Notes to Financial Statements


30


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMPREHENSIVE INCOME
(amounts in thousands of dollars)
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
Net income
$
159,213

 
$
152,157

 
$
127,263

 
 
 
 
 
 
Other comprehensive income (loss)
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
 
 
Amortization of losses (gains) included in net periodic benefit cost, net of tax of
$26, $(84), and $(260), respectively
44

 
(148
)
 
(464
)
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
Reclassification of losses to net income, net of tax of
$24, $80, and $97, respectively
39

 
139

 
172

 
 
 
 
 
 
Other comprehensive income (loss)
83

 
(9
)
 
(292
)
Comprehensive income
$
159,296

 
$
152,148

 
$
126,971


See Notes to Financial Statements


31


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS
(amounts in thousands of dollars)

Year Ended Dec. 31
 
2017
 
2016
 
2015
Operating activities
 
 
 
 
 
Net income
$
159,213

 
$
152,157

 
$
127,263

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
193,870

 
162,957

 
153,241

Demand side management program amortization
1,673

 
1,673

 
1,673

Deferred income taxes
126,465

 
122,983

 
62,836

Amortization of investment tax credits
(133
)
 
(213
)
 
(213
)
Allowance for equity funds used during construction
(9,310
)
 
(9,981
)
 
(7,378
)
Provision for bad debts
5,091

 
6,066

 
4,655

Net derivative losses
63

 
217

 
268

Other
(28
)
 
122

 
(3,827
)
Changes in operating assets and liabilities:
 
 
 
 
 
Accounts receivable
(10,392
)
 
(8,868
)
 
(3,291
)
Accrued unbilled revenues
(10,386
)
 
(15,637
)
 
25,506

Inventories
(1,928
)
 
(959
)
 
5,686

Prepayments and other
4,267

 
22,651

 
(24,712
)
Accounts payable
11,836

 
13,776

 
(24,570
)
Net regulatory assets and liabilities
38,137

 
(55,689
)
 
26,452

Other current liabilities
3,427

 
5,156

 
(30,762
)
Pension and other employee benefit obligations
(21,679
)
 
(15,276
)
 
(9,405
)
Change in other noncurrent assets
(1,206
)
 
(200
)
 
2,352

Change in other noncurrent liabilities
(18,524
)
 
6,748

 
8,974

Net cash provided by operating activities
470,456

 
387,683

 
314,748

 
 
 
 
 
 
Investing activities
 
 
 
 
 
Utility capital/construction expenditures
(559,865
)
 
(512,522
)
 
(599,511
)
Allowance for equity funds used during construction
9,310

 
9,981

 
7,378

Proceeds from insurance recoveries

 
3,901

 

Investments in utility money pool arrangement
(142,000
)
 
(75,000
)
 
(92,000
)
Receipts from utility money pool arrangement
77,000

 
75,000

 
92,000

Other
(493
)
 
(1,174
)
 
3,136

Net cash used in investing activities
(616,048
)
 
(499,814
)
 
(588,997
)
 
 
 
 
 
 
Financing activities
 
 
 
 
 
(Repayment of) proceeds from short-term borrowings, net
(50,000
)
 
35,000

 
(22,000
)
Proceeds from issuance of long-term debt
442,338

 
295,985

 
198,496

Repayment of long-term debt, including reacquisition premiums
(271,613
)
 
(200,000
)
 

Borrowings under utility money pool arrangement
335,000

 
636,500

 
579,700

Repayments under utility money pool arrangement
(335,000
)
 
(636,500
)
 
(595,700
)
Capital contributions from parent
143,659

 
66,225

 
214,535

Dividends paid to parent
(108,765
)
 
(85,069
)
 
(100,544
)
Net cash provided by financing activities
155,619

 
112,141

 
274,487

 
 
 
 
 
 
Net change in cash and cash equivalents
10,027

 
10

 
238

Cash and cash equivalents at beginning of year
844

 
834

 
596

Cash and cash equivalents at end of year
$
10,871

 
$
844

 
$
834

 
 

 
 

 
 

Supplemental disclosure of cash flow information:
 
 
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(75,978
)
 
$
(78,236
)
 
$
(76,474
)
Cash received (paid) for income taxes, net
41,548

 
61,813

 
(23,987
)
Supplemental disclosure of non-cash investing transactions:
 
 
 
 
 
Property, plant and equipment additions in accounts payable
$
77,563

 
$
43,074

 
$
44,335

See Notes to Financial Statements

32


SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS
(amounts in thousands, except share and per share data)
 
 
Dec. 31
 
 
2017
 
2016
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
10,871

 
$
844

Accounts receivable, net
 
79,581

 
74,190

Accounts receivable from affiliates
 
1,297

 
949

Investments in money pool arrangements
 
65,000

 

Accrued unbilled revenues
 
129,804

 
119,418

Inventories
 
40,433

 
38,505

Regulatory assets
 
31,538

 
38,721

Derivative instruments
 
15,882

 
5,114

Prepaid taxes
 
15,025

 
21,779

Prepayments and other
 
10,341

 
7,855

Total current assets
 
399,772

 
307,375

 
 
 
 
 
Property, plant and equipment, net
 
5,095,609

 
4,695,819

 
 
 
 
 
Other assets
 
 
 
 
Regulatory assets
 
362,943

 
346,683

Derivative instruments
 
18,954

 
22,113

Other
 
11,266

 
7,477

Total other assets
 
393,163

 
376,273

Total assets
 
$
5,888,544

 
$
5,379,467

 
 
 
 
 
Liabilities and Equity
 
 
 
 
Current liabilities
 
 
 
 
Short-term debt
 
$

 
$
50,000

Accounts payable
 
211,756

 
176,157

Accounts payable to affiliates
 
22,577

 
14,414

Regulatory liabilities
 
68,835

 
41,577

Taxes accrued
 
35,243

 
39,742

Accrued interest
 
23,275

 
19,162

Dividends payable
 
26,753

 
30,870

Derivative instruments
 
3,565

 
3,565

Other
 
29,641

 
29,703

Total current liabilities
 
421,645

 
405,190

 
 
 
 
 
Deferred credits and other liabilities
 
 
 
 
Deferred income taxes
 
574,906

 
989,137

Regulatory liabilities
 
784,564

 
233,454

Asset retirement obligations
 
28,524

 
28,663

Derivative instruments
 
19,949

 
23,513

Pension and employee benefit obligations
 
90,266

 
107,872

Other
 
8,386

 
24,084

Total deferred credits and other liabilities
 
1,506,595

 
1,406,723

 
 
 
 
 
Commitments and contingencies
 


 


Capitalization
 
 
 
 
Long-term debt
 
1,829,941

 
1,635,858

Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2017 and 2016, respectively
 

 

Additional paid in capital
 
1,590,242

 
1,446,223

Retained earnings
 
541,588

 
486,763

Accumulated other comprehensive loss
 
(1,467
)
 
(1,290
)
Total common stockholder’s equity
 
2,130,363

 
1,931,696

Total liabilities and equity
 
$
5,888,544

 
$
5,379,467


See Notes to Financial Statements

33


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
(amounts in thousands of dollars, except share data)
 
Common Stock Issued
 
 
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Common
Stockholder’s
Equity
 
Shares
 
Par Value
 
Additional
Paid In
Capital
 
Retained
Earnings
 
 
Balance at Dec. 31, 2014
100

 
$

 
$
1,165,463

 
$
395,998

 
$
(989
)
 
$
1,560,472

Net income
 
 
 
 
 
 
127,263

 
 
 
127,263

Other comprehensive loss
 
 
 
 
 
 
 
 
(292
)
 
(292
)
Common dividends declared to parent
 
 
 
 
 
 
(85,254
)
 
 
 
(85,254
)
Contribution of capital by parent
 
 
 
 
205,760

 
 
 
 
 
205,760

Balance at Dec. 31, 2015
100

 
$

 
$
1,371,223

 
$
438,007

 
$
(1,281
)
 
$
1,807,949

Net income
 
 
 
 
 
 
152,157

 
 
 
152,157

Other comprehensive loss
 
 
 
 
 
 
 
 
(9
)
 
(9
)
Common dividends declared to parent
 
 
 
 
 
 
(103,401
)
 
 
 
(103,401
)
Contribution of capital by parent
 
 
 
 
75,000

 
 
 
 
 
75,000

Balance at Dec. 31, 2016
100

 
$

 
$
1,446,223

 
$
486,763

 
$
(1,290
)
 
$
1,931,696

Net income
 
 
 
 
 
 
159,213

 
 
 
159,213

Other comprehensive income
 
 
 
 
 
 
 
 
83

 
83

Common dividends declared to parent
 
 
 
 
 
 
(104,648
)
 
 
 
(104,648
)
Contribution of capital by parent
 
 
 
 
144,019

 
 
 
 
 
144,019

Adoption of ASU No. 2018-02
 
 
 
 
 
 
260

 
(260
)
 

Balance at Dec. 31, 2017
100

 
$

 
$
1,590,242

 
$
541,588

 
$
(1,467
)
 
$
2,130,363


See Notes to Financial Statements


34


SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CAPITALIZATION
(amounts in thousands of dollars, except share data)
 
Dec. 31
 
2017
 
2016
Long-Term Debt
 
 
 
First Mortgage Bonds, Series due:
 
 
 
   June 15, 2024, 3.3%
$
350,000

 
$
350,000

   Aug. 15, 2041, 4.5%
400,000

 
400,000

   Aug. 15, 2046, 3.4%
300,000

 
300,000

   Aug. 15, 2047, 3.7%
450,000

 

Unsecured Senior G Notes, due Dec. 1, 2018, 8.75%

 
250,000

Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%
100,000

 
100,000

Unsecured Senior F Notes, due Oct. 1, 2036, 6%
250,000

 
250,000

Unamortized (discount) premium
(1,746
)
 
365

Unamortized debt expense
(18,313
)
 
(14,507
)
Total long-term debt
$
1,829,941

 
$
1,635,858

 
 
 
 
Common Stockholder’s Equity
 
 
 
Common stock — 200 shares authorized of $1.00 par value,
100 shares outstanding at Dec. 31, 2017 and 2016, respectively
$

 
$

Additional paid in capital
1,590,242

 
1,446,223

Retained earnings
541,588

 
486,763

Accumulated other comprehensive loss
(1,467
)
 
(1,290
)
Total common stockholder’s equity
$
2,130,363

 
$
1,931,696


See Notes to Financial Statements


35


NOTES TO FINANCIAL STATEMENTS

1.
Summary of Significant Accounting Policies

Business and System of Accounts — SPS is engaged in the regulated generation, purchase, transmission, distribution and sale of electricity. SPS’ financial statements and disclosures are presented in accordance with GAAP. All of SPS’ underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Variable Interest Entities — SPS evaluates its arrangements and contracts with other entities, including but not limited to, PPAs and fuel contracts, to determine if the other party is a variable interest entity, if SPS has a variable interest and if SPS is the primary beneficiary. SPS follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether SPS is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.

Use of Estimates — In recording transactions and balances resulting from business operations, SPS uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting — SPS accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, SPS may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on SPS’ financial condition, results of operations and cash flows. See Note 12 for further discussion of regulatory assets and liabilities.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.

SPS participates in SPP. SPS recognizes sales to both native load and other end use customers on a gross basis. Revenues and charges for short-term wholesale sales of excess energy transacted through SPP are recorded on a gross basis in electric revenues and cost of sales. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in cost of sales.

SPS has various rate-adjustment mechanisms in place that provide for the recovery of electric fuel costs and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.


36


Certain rate rider mechanisms qualify as alternative revenue programs under generally accepted accounting principles. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers.

Conservation Programs — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system. These programs include commercial motor, air conditioner and lighting upgrades, as well as residential rebates for participation in air conditioner interruption and home weatherization.

The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the annual period in which they are earned. SPS recovers approved conservation program costs in base rate revenue or through a rider.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

SPS records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was 2.8, 2.7 and 2.6 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.

Leases — SPS evaluates a variety of contracts for lease classification at inception, including PPAs and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in SPS’ rate base for establishing utility service rates.

AROs — SPS accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. SPS also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.


37


Income Taxes — SPS accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. SPS defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. SPS uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the period that includes the enactment date.

The effects of SPS’ tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

SPS follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. SPS recognizes a tax position in its financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax.

SPS reports interest and penalties related to income taxes within the other income and interest charges sections in the statements of income.

Xcel Energy Inc. and its subsidiaries, including SPS, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments SPS uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification as a regulatory asset or liability is based on expected recovery of derivative instrument settlements through fuel and purchased energy cost recovery mechanisms.

Interest rate hedging transactions are recorded as a component of interest expense. For further information on derivatives entered to mitigate market risk associated with transmission in organized markets, see Note 9.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — SPS enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.


38


SPS evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

See Note 9 for further discussion of SPS’ risk management and derivative activities.

Fair Value Measurements — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its financial statements. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, SPS may use quoted prices for similar contracts or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Notes 7 and 9 for further discussion.

Cash and Cash Equivalents — SPS considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. SPS establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

Inventory — All inventory is recorded at average cost.

RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. SPS acquires RECs from the generation or purchase of renewable power.

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. As a result of certain state regulatory orders, SPS reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.

Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. SPS follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the statements of cash flows.

Environmental Costs — Environmental costs are recorded when it is probable SPS is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for SPS’ expected share of the cost.


39


Any future costs of restoring sites where operation may be extended are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits — SPS maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 7 for further discussion of benefit plans and other postretirement benefits.

Guarantees — SPS recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as SPS is released from risk under the guarantee. See Note 11 for specific details of issued guarantees.

Segment Information — SPS has only one reportable segment. SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico. Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2.
Accounting Pronouncements

Recently Issued

Revenue Recognition In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity, SPS’ adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs. The guidance is effective for interim and annual periods beginning after Dec. 15, 2017. SPS is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018.

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

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. SPS has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. SPS expects that similar agreements entered after Dec. 31, 2018 will generally qualify as leases under the new standard.

40



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

Recently Adopted

Accounting for the TCJA In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118 Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), to supplement the accounting requirements of ASC Topic 740 Income Taxes (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 6 to the financial statements.

Reporting Comprehensive Income — In February 2018, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, Topic 220 (ASU No. 2018-02), which addresses the stranded amounts of accumulated OCI which may result from enactment of a new tax law. Though accumulated OCI is presented on a net-of-tax basis, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI be recognized without a corresponding adjustment to accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts of accumulated OCI specifically resulting from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. SPS adopted the guidance in the fourth quarter of 2017, and elected to recognize a $0.3 million increase to accumulated other comprehensive loss and retained earnings in the financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate.


3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
Dec. 31, 2017
 
Dec. 31, 2016
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
85,929

 
$
80,569

Less allowance for bad debts
 
(6,348
)
 
(6,379
)
 
 
$
79,581

 
$
74,190

(Thousands of Dollars)
 
Dec. 31, 2017
 
Dec. 31, 2016
Inventories
 
 
 
 
Materials and supplies
 
$
26,218

 
$
25,453

Fuel
 
14,215

 
13,052

 
 
$
40,433

 
$
38,505

(Thousands of Dollars)
 
Dec. 31, 2017
 
Dec. 31, 2016
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
6,765,371

 
$
6,362,189

Construction work in progress
 
351,875

 
260,327

Total property, plant and equipment
 
7,117,246

 
6,622,516

Less accumulated depreciation
 
(2,021,637
)
 
(1,926,697
)
 
 
$
5,095,609

 
$
4,695,819



41


4.
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. SPS had no money pool borrowings outstanding during the three months ended Dec. 31, 2017. Money pool borrowings for SPS were as follows:
(Amounts in Millions, Except Interest Rates)
 
Twelve Months Ended Dec. 31, 2017
 
Twelve Months Ended Dec. 31, 2016
 
Twelve Months Ended Dec. 31, 2015
Borrowing limit
 
$
100

 
$
100

 
$
100

Amount outstanding at period end
 

 

 

Average amount outstanding
 
13

 
28

 
21

Maximum amount outstanding
 
100

 
100

 
100

Weighted average interest rate, computed on a daily basis
 
1.12
%
 
0.67
%
 
0.40
%
Weighted average interest rate at end of period
 
N/A

 
N/A

 
N/A


Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. SPS had no commercial paper borrowings outstanding during the three months ended Dec. 31, 2017. Commercial paper outstanding for SPS was as follows:
(Amounts in Millions, Except Interest Rates)
 
Twelve Months Ended Dec. 31, 2017
 
Twelve Months Ended Dec. 31, 2016
 
Twelve Months Ended Dec. 31, 2015
Borrowing limit
 
$
400

 
$
400

 
$
400

Amount outstanding at period end
 

 
50

 
15

Average amount outstanding
 
69

 
43

 
100

Maximum amount outstanding
 
176

 
140

 
246

Weighted average interest rate, computed on a daily basis
 
1.13
%
 
0.67
%
 
0.46
%
Weighted average interest rate at end of period
 
NA

 
0.95

 
0.60


Letters of Credit — SPS may use letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2017 and 2016, there were $3 million and $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.

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.

SPS has the right to request an extension of the June 2021 termination date for two additional one-year periods. The extension requests are subject to majority bank group approval.

Other features of SPS’ credit facility include:

The credit facility may be increased by up to $50 million.
The credit facility has a financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent. SPS was in compliance as its debt-to-total capitalization ratio was 46 percent and 47 percent at Dec. 31, 2017 and 2016, respectively. If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.
The credit facility has a cross-default provision that provides SPS will be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15 percent of SPS’ total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.
SPS was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2017 and 2016.


42


At Dec. 31, 2017, SPS had the following committed credit facility available (in millions):
Credit Facility (a)
 
Drawn (b)
 
Available
$
400

 
$
3

 
$
397