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Section 1: 10-K (10-K)

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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: 001-3034
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota
 
41-0448030
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
414 Nicollet Mall
Minneapolis, MN 55401
(Address of principal executive offices)
Registrant’s telephone number, including area code: 612-330-5500
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, $2.50 par value per share
 
Nasdaq Stock Market LLC
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.  x Yes  ¨ 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. ¨
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.  x Large accelerated filer  ¨ Accelerated filer  ¨ Non-accelerated filer (Do not check if a smaller reporting company) ¨ 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 June 30, 2017, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $23,304,874,235 and there were 507,952,795 shares of common stock outstanding.
As of Feb. 19, 2018, there were 508,064,983 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2018 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.
 


Table of Contents

TABLE OF CONTENTS
Index
PART I
 
 
Item 1 —
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Item 1A —
Item 1B —
Item 2 —
Item 3 —
Item 4 —
 
 
 
PART II
 
 
Item 5 —
Item 6 —
Item 7 —
Item 7A —
Item 8 —
Item 9 —
Item 9A —
Item 9B —
 
 
 
PART III
 
 
Item 10 —
Item 11 —
Item 12 —
Item 13 —
Item 14 —
 
 
 
PART IV
 
 
Item 15 —
Item 16 —
 
 

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PART I

Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Capital Services
Capital Services, LLC
Eloigne
Eloigne Company
NCE
New Century Energies, Inc.
NSP-Minnesota
Northern States Power Company, a Minnesota corporation
NSP System
The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin
Northern States Power Company, a Wisconsin corporation
Operating companies
NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
PSCo
Public Service Company of Colorado
SPS
Southwestern Public Service Co.
Utility subsidiaries
NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI
WestGas InterState, Inc.
WYCO
WYCO Development, LLC
Xcel Energy
Xcel Energy Inc. and its subsidiaries
XETD
Xcel Energy Transmission Development Company, LLC
XEST
Xcel Energy Southwest Transmission Company, LLC
XEWT
Xcel Energy West Transmission Company, LLC
 
 
Federal and State Regulatory Agencies
 
 
CFTC
Commodity Futures Trading Commission
CPUC
Colorado Public Utilities Commission
D.C. Circuit
United States Court of Appeals for the District of Columbia Circuit
DOC
Minnesota Department of Commerce
DOE
United States Department of Energy
DOT
United States Department of Transportation
EPA
United States Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
Fifth Circuit
United States Court of Appeals for the Fifth Circuit
IRS
Internal Revenue Service
MPSC
Michigan Public Service Commission
MPUC
Minnesota Public Utilities Commission
NDPSC
North Dakota Public Service Commission
NERC
North American Electric Reliability Corporation
NMPRC
New Mexico Public Regulation Commission
NRC
Nuclear Regulatory Commission
PHMSA
Pipeline and Hazardous Materials Safety Administration
PSCW
Public Service Commission of Wisconsin
PUCT
Public Utility Commission of Texas
SDPUC
South Dakota Public Utilities Commission
SEC
Securities and Exchange Commission

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Electric, Purchased Gas and Resource Adjustment Clauses
CIP
Conservation improvement program
DCRF
Distribution cost recovery factor
DSM
Demand side management
DSMCA
Demand side management cost adjustment
ECA
Retail electric commodity adjustment
EE
Energy efficiency
EECRF
Energy efficiency cost recovery factor
EIR
Environmental improvement rider (recovers the costs associated with investments in
environmental improvements to fossil fuel generation plants)
FCA
Fuel clause adjustment
FPPCAC
Fuel and purchased power cost adjustment clause
GCA
Gas cost adjustment
GUIC
Gas utility infrastructure cost rider
PCCA
Purchased capacity cost adjustment
PCRF
Power cost recovery factor (recovers the costs of certain purchased power costs)
PGA
Purchased gas adjustment
RDF
Renewable development fund
RER
Renewable energy rider
RES
Renewable energy standard
RESA
Renewable energy standard adjustment (recovers the costs of new renewable generation)
PSIA
Pipeline system integrity adjustment
SCA
Steam cost adjustment
SEP
State energy policy rider
TCA
Transmission cost adjustment
TCR
Transmission cost recovery adjustment
TCRF
Transmission cost recovery factor (recovers transmission infrastructure improvement costs
and changes in wholesale transmission charges)
WCA
Windsource® cost adjustment
 
 
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
C&I
Commercial and Industrial
CAA
Clean Air Act
CACJA
Clean Air Clean Jobs Act
CAIR
Clean Air Interstate Rule
CAISO
California Independent System Operator
CapX2020
Alliance of electric cooperatives, municipals and investor-owned utilities in the upper
Midwest involved in a joint transmission line planning and construction effort
CCN
Certificate of convenience and necessity
CIG
Colorado Interstate Gas Company, LLC
CO2
Carbon dioxide
CON
Certificate of need

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CPCN
Certificate of public convenience and necessity
CPP
Clean Power Plan
CSAPR
Cross-State Air Pollution Rule
CWA
Clean Water Act
CWIP
Construction work in progress
EEI
Edison Electric Institute
EGU
Electric generating unit
EPS
Earnings per share
EPU
Extended power uprate
ERCOT
Electric Reliability Council of Texas
ETR
Effective tax rate
FASB
Financial Accounting Standards Board
FTR
Financial transmission right
FTY
Forecast test year
GAAP
Generally accepted accounting principles
GHG
Greenhouse gas
Golden Spread
Golden Spread Electric Cooperative, Inc.
HTY
Historic test year
IM
Integrated market
IPP
Independent power producing entities
IRC
Internal Revenue Code
IRP
Integrated Resource Plan
ISFSI
Independent Spent Fuel Storage Installation
ITC
Investment Tax Credit
LCM
Life cycle management
LLW
Low-level radioactive waste
LNG
Liquefied natural gas
MGP
Manufactured gas plant
MISO
Midcontinent Independent System Operator, Inc.
Moody’s
Moody’s Investor Services
MWTG
Mountain West Transmission Group
NAAQS
National Ambient Air Quality Standard
Native load
Customer demand of retail and wholesale customers that 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
OATT
Open Access Transmission Tariff
OCC
Office of Consumer Counsel
OCI
Other comprehensive income
PI
Prairie Island nuclear generating plant
PJM
PJM Interconnection, LLC
PM
Particulate matter
PPA
Purchased power agreement
PRP
Potentially responsible party
PTC
Production tax credit
PV
Photovoltaic
QF
Qualifying facilities
R&E
Research and experimentation
REC
Renewable energy credit

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RFP
Request for proposal
ROE
Return on equity
RPS
Renewable portfolio standards
RTO
Regional Transmission Organization
SIP
State implementation plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool, Inc.
S&P
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

TOs
Transmission owners
TransCo
Transmission-only subsidiary
TSR
Total shareholder return
VIE
Variable interest entity
 
 
Measurements
 
Bcf
Billion cubic feet
GWh
Gigawatt hours
KV
Kilovolts
KWh
Kilowatt hours
Mcf
Thousand cubic feet
MMBtu
Million British thermal units
MW
Megawatts
MWh
Megawatt hours


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COMPANY OVERVIEW

Xcel Energy Inc. is a holding company with subsidiaries engaged primarily in the utility business. In 2017, Xcel Energy Inc.’s continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, and serve customers. Along with WYCO, a joint venture formed with CIG to develop and lease natural gas pipelines, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the regulated utility operations.

Xcel Energy Inc. was incorporated under the laws of Minnesota in 1909. Xcel Energy’s executive offices are located at 414 Nicollet Mall, Minneapolis, Minn. 55401. Its website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The public may read and copy any materials that Xcel Energy files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

NSP-Minnesota

NSP-Minnesota is a utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.5 million customers and natural gas utility service to approximately 0.5 million customers. Approximately 88 percent of NSP-Minnesota’s retail electric operating revenues were derived from operations in Minnesota during 2017 and 2016. Although NSP-Minnesota’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of NSP-Minnesota’s large C&I electric sales include: petroleum refining and related industries, food products and health services. For small C&I customers, significant electric retail sales include the following industries: real estate and educational services. Generally, NSP-Minnesota’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC-approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.

The wholesale customers served by NSP-Minnesota comprised approximately 14 percent of its total KWh sold in 2017.

NSP-Minnesota owns the following direct subsidiary: United Power and Land Company, which holds real estate.

NSP-Wisconsin

NSP-Wisconsin is a utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in this service territory. NSP-Wisconsin provides electric utility service to approximately 259,000 customers and natural gas utility service to approximately 114,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2017 and 2016. Although NSP-Wisconsin’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of NSP-Wisconsin’s large C&I electric sales include: food products, paper, allied products and electric, gas and sanitary services. For small C&I customers, significant electric retail sales include the following industries: grocery and dining establishments, educational services and health services. Generally, NSP-Wisconsin’s earnings contribute approximately five percent to 10 percent of Xcel Energy’s consolidated net income.

The management of the electric generation and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.


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PSCo

PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility service to approximately 1.5 million customers and natural gas utility service to approximately 1.4 million customers. All of PSCo’s retail electric operating revenues were derived from operations in Colorado. Although PSCo’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large C&I electric sales include: fabricated metal products, communications and health services. For small C&I customers, significant electric retail sales include the following industries: real estate and dining establishments. Generally, PSCo’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.

The wholesale customers served by PSCo comprised approximately 14 percent of its total KWh sold in 2017.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests. PSCo also holds a controlling interest in several other relatively small ditch and water companies.

SPS

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.

Other Subsidiaries

WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to Cheyenne, Wyo.

WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. The gas pipeline and storage facilities are leased under a FERC-approved agreement to CIG.

Xcel Energy Services Inc. is the service company for Xcel Energy Inc.

XETD and XEST are TransCos that will, respectively, participate in MISO and SPP competitive bidding processes for transmission projects. XEWT is a TransCo formed to competitively bid on transmission projects in the western United States.
Xcel Energy Inc.’s nonregulated subsidiaries include Eloigne and Capital Services. Eloigne invests in rental housing projects that qualify for low-income housing tax credits, and Capital Services procures equipment for construction of renewable generation facilities at other subsidiaries.
Xcel Energy conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. See Note 17 to the consolidated financial statements for further discussion relating to comparative segment revenues, income from operations and related financial information.


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ELECTRIC UTILITY OPERATIONS

NSP-Minnesota
Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC also has regulatory authority over security issuances, property transfers, mergers, dispositions of assets and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s IRPs for meeting customers’ future energy needs. The MPUC also certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV that will be located within the state. No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC for its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota is a transmission owning member of the MISO RTO and operates within the MISO RTO and MISO wholesale market. NSP-Minnesota and NSP-Wisconsin are jointly authorized by the FERC to make wholesale electric sales at market-based prices.

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

CIP rider — Recovers the costs of conservation and demand-side management programs.
EIR — Recovers the costs of environmental improvement projects.
RDF — Allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies.
RES — Recovers the cost of renewable generation in Minnesota.
RER — Recovers the cost of renewable generation in North Dakota.
SEP — Recovers costs related to various energy policies approved by the Minnesota legislature.
TCR — Recovers costs associated with investments in electric transmission and distribution grid modernization costs.
Infrastructure rider — Recovers costs for investments in generation and incremental property taxes in South Dakota.

NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments to recover changes in prudently incurred costs of fuel related items and purchased energy. In general, capacity costs are recovered through base rates and are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or base rates. In 2017, the MPUC voted to change the process in which utilities seek fuel cost recovery under the FCA in Minnesota to be implemented in July 2019. Under the new process, each month utilities would collect amounts equal to the baseline cost of energy set at the start of the plan year. Monthly variations to the baseline costs would be tracked and netted over a 12-month period. Subsequently, utilities would issue refunds above the baseline costs, and could seek recovery of any overage.  

Minnesota state law requires NSP-Minnesota to invest two percent of its state electric revenues and half a percent of its state gas revenues in CIP. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures. Minnesota state law also requires NSP-Minnesota to submit a CIP plan at least every three years.

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility 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
NSP System
8,546

 
9,002

 
8,621

 
9,208



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The peak demand for the NSP System typically occurs in the summer. The 2017 system peak demand for the NSP System occurred on July 17, 2017. The decline in peak load from 2016 to 2017 is in part due to considerably cooler weather in 2017. The 2018 forecast assumes normal peak day weather, which is warmer than actual 2017 peak day weather.

Energy Sources and Related Transmission Initiatives

NSP-Minnesota expects to use existing power plants, power purchases, CIP/DSM options, new generation facilities and expansion of existing power plants to meet its system capacity requirements.

Purchased Power NSP-Minnesota has contracts to purchase power from other utilities and IPPs. Generally, long-term dispatchable purchased power contracts require a periodic capacity payment and a charge for the delivered associated energy. Some long-term purchased power contracts only contain a charge for the purchased energy. NSP-Minnesota 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 NSP-Minnesota and NSP-Wisconsin have contracts with MISO and other regional transmission service providers to deliver power and energy to their customers.

NSP System Resource Plans — In January 2017, the MPUC approved NSP-Minnesota’s IRP that includes:

Retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026. The resulting need for 750 MW of capacity in 2026 will be addressed in a future CON proceeding;
Acquisition of at least 1,000 MW of wind by 2019. The mix of purchased power and owned facilities was not specified;
Acquisition of 650 MW of solar by 2021 either through the community solar gardens program or other cost-effective resources. The mix of purchased power and owned facilities was not specified;
Acquisition of at least 400 MW of additional demand response by 2023, and a study of the technical and economic achievability of 1,000 MW of additional demand response in total by 2025; and
Achievement of at least 444 GWh of energy efficiency in all planning years.

Minnesota Legislation — In February 2017, the Minnesota governor signed a bill into law allowing NSP-Minnesota to build a natural gas combined-cycle power plant at NSP-Minnesota’s Sherco site. The plant was originally proposed as part of NSP-Minnesota’s resource plan, which enables the retirement of two coal units at the Sherco site. The plant’s in-service date is anticipated for 2026. Cost recovery of the plant will be subject to MPUC approval.

Wind Development — In July 2017, the MPUC approved NSP-Minnesota’s proposal to add 1,550 MW of new wind generation including ownership of 1,150 MW of wind generation by NSP-Minnesota, which will help achieve NSP-Minnesota’s wind acquisition goal outlined in the IRP. In March 2017, NSP-Minnesota filed an Advanced Determination of Prudence with the NDPSC and reached a settlement with the NDPSC Staff. The timing of a NDPSC order is uncertain. These projects are expected to be completed by the end of 2020 and would qualify for 100 percent of the PTC. NSP-Minnesota’s total capital investment for these wind ownership projects is expected to be approximately $1.9 billion.

In September 2017, NSP-Minnesota filed with the MPUC seeking approval to build and own the Dakota Range project, a 300 MW wind project in South Dakota. The project is expected to be placed into service by the end of 2021 and qualify for 80 percent of the PTC. The DOC recommended the MPUC deny the petition on the basis that NSP-Minnesota did not follow the standard regulatory selection process of issuing a new RFP. However, the DOC acknowledged the Dakota Range project would benefit ratepayers and the MPUC could approve the project if it determines the public interest outweighs their concern about the regulatory selection process.

These wind projects are expected to provide significant savings to NSP-Minnesota’s customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with various commission approved resource plans. NSP-Minnesota will provide supplemental filings to the MPUC in March 2018, which will estimate impacts of the TCJA on the wind projects.


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PPA Terminations and Amendments — In 2017, NSP-Minnesota filed requests with the MPUC and the NDPSC for several initiatives including changes to four PPAs to reduce future costs for customers. These actions include the following:

The termination of a PPA with Benson Power LLC (Benson) for its 55 MW biomass facility in Benson, Minn., including the purchase and closure of the facility. The purchase of the Benson biomass facility requires FERC approval, which was requested in August 2017. The transaction would result in payments of $95 million to terminate the PPA and acquire the facility, as well as additional expenditures of approximately $26 million to temporarily operate and close the facility.
The termination of a PPA with Laurentian Energy Authority I, LLC (Laurentian) for its 35 MW of biomass facilities in Hibbing and Virginia, Minn. The termination of the Laurentian PPA would result in approximately $109 million of contract cancellation payments over six years.
The remaining two requested PPA changes involve a PPA extension of the Hennepin Energy Recovery Center (HERC) 34 MW waste-to-energy facility at a price reflective of current market conditions and termination of the Pine Bend 12 MW waste-to-energy PPA.

In November 2017, the MPUC approved NSP-Minnesota’s request to terminate the Pine Bend PPA but rejected its request to extend the HERC PPA.
In January 2018, the MPUC issued an order approving NSP-Minnesota’s petition to terminate the PPAs with Benson and Laurentian, as well as purchase and close the Benson biomass facility. All approved costs are expected to be recoverable through the FCA, including a return on NSP-Minnesota’s total investment in the Benson transaction through 2028. NSP-Minnesota also reached a settlement agreement with the NDPSC Staff which allows for the termination of the PPAs with Benson, Laurentian and Pine Bend, as well as the purchase and closure of the Benson biomass facility. The NDPSC is expected to issue an order on the settlement in the second quarter of 2018. NSP-Minnesota and NSP-Wisconsin will jointly request FERC approval to modify the Interchange Agreement to share a portion of the termination costs with NSP-Wisconsin.
These terminations and amendments are intended to provide in excess of $600 million in net cost savings to NSP System customers over the next 10 years.
Jurisdictional Cost Recovery Allocation — In December 2016, NSP-Minnesota filed a resource treatment framework with the NDPSC and MPUC. The filing proposed a framework to allow NSP-Minnesota’s operations in North Dakota and Minnesota to gradually become more independent of one another with respect to future generation resource selection while also identifying a path for cost sharing of current resources. NSP-Minnesota’s filing identified two options: a legal separation, creating a separate North Dakota operating company; or a pseudo-separation, which maintains the current corporate structure but directly assigns the costs and benefits of each resource to the jurisdiction that supports it. In October 2017, NDPSC staff filed testimony recommending no change to the current system of proxy pricing and policy-based disallowances claiming there is a likelihood of overall increased costs and potential loss of resource diversity. Hearings are planned for the second quarter of 2018.

Minnesota State Right-Of-First Refusal (ROFR) Statute Complaint — In September 2017, LSP Transmission Holdings, LLC filed a complaint in the U.S. District Court for the District of Minnesota (Minnesota District Court) against the Minnesota Attorney General, the MPUC and the DOC. The complaint was in response to MISO assigning NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 KV transmission line from near Mankato, Minn. to Winnebago, Minn. The line was estimated by MISO to cost $103 million. The project was assigned to NSP-Minnesota and ITC Midwest as the incumbent utilities, consistent with a Minnesota state ROFR statute. The complaint challenges the constitutionality of the state ROFR statute and is seeking declaratory judgment that the statute violates the Commerce Clause of the U.S. Constitution and should not be enforced. The Minnesota state agencies and NSP-Minnesota filed motions to dismiss. Oral arguments were heard in February 2018, and the matter is now pending before the Minnesota District Court. The timing and outcome of the litigation is uncertain.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes which are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in a plant.


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NSP-Minnesota participates with regulators and in industry groups including the NRC, the Institute of Nuclear Power Operations and Utilities Service Alliance to stay informed of advancements in nuclear safety, mitigation strategies, performance and operational effectiveness. NSP-Minnesota applies this acquired knowledge by investing in technology and services that improve nuclear operations and detect, mitigate and protect NPS-Minnesota’s nuclear facilities.

NRC Regulation — The NRC regulates nuclear operations. Decisions by the NRC can significantly impact the operations of the nuclear generating plants. The costs of complying with NRC orders and requirements can affect both operating expenses and capital investments of the plants. NSP-Minnesota has obtained recovery of these compliance costs in customer rates, and expects future compliance costs will continue to be recoverable from customers. Estimates of the future nuclear capital expenditures related to costs of NRC compliance are included in Xcel Energy’s capital forecast for electric generation. See Item 7 for further discussion of capital requirements.

Nuclear Regulatory Performance The NRC has a Reactor Oversight Process that classifies U.S. nuclear reactors into various categories (referred to as Columns, from 1 to 5).  Issues are evaluated as either green, white, yellow, or red based on their safety significance, with green representing the least safety concern and red representing the most concern. 

As of Dec. 31, 2017, Monticello and PI Units 1 and 2 were in Column 1 (licensee response) with all green performance indicators and no greater than green findings or violations. Plants in Column 1 are subject to only a pre-defined set of basic NRC inspections.

LLW Disposal LLW from NSP-Minnesota’s Monticello and PI nuclear plants is currently disposed at the Clive facility located in Utah and the Waste Control Specialists facility located in Texas. If off-site LLW disposal facilities become unavailable, NSP-Minnesota has storage capacity available on-site at PI and Monticello that would allow both plants to continue to operate until the end of their current licensed lives.

High-Level Radioactive Waste Disposal The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility. The federal government has been evaluating a nuclear geologic repository at Yucca Mountain, Nevada for many years. At this time, there are no definitive plans for a permanent federal storage site at Yucca Mountain or any other site.

Review of PI Costs As part of NSP-Minnesota’s 2016 multi-year electric rate case and IRP the MPUC ordered an investigation into NSP-Minnesota’s PI nuclear investments. The issue was resolved for the 2016 multi-year electric rate case settlement; however the DOC is continuing to investigate costs of operation and performance at PI in anticipation of NSP-Minnesota’s 2019 resource plan.

Nuclear Spent Fuel Storage
NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. As of Dec. 31, 2017, there were 40 casks loaded and stored at the PI plant and 16 canisters loaded and stored at the Monticello plant. An additional 24 casks for PI and 14 canisters for Monticello have been authorized by the State of Minnesota. This currently authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not begin operation of a consolidated interim storage installation.

In 2013, NSP-Minnesota’s Monticello nuclear generating plant loaded and placed five storage canisters (canisters #11-15) in the ISFSI and a sixth canister (canister #16) was loaded but remained in the plant pending resolution of weld inspection issues.  Successful pressure and leak testing demonstrated the safety and integrity of all six canisters involved.  NSP-Minnesota took several actions to assure compliance with the NRC’s regulations and Monticello’s storage license.

In 2016, the NRC issued an order approving a settlement in which NSP-Minnesota agreed to a timeline for attaining compliance on all six canisters, as well as additional training and communications. During 2016, the NRC approved an exemption request for the completion of canister #16.  That canister is now considered in compliance, and was placed in the ISFSI during 2016.  In 2017, NSP-Minnesota submitted a plan and request to the NRC to restore Monticello canisters #11-15 to compliance through an exemption request.  NSP-Minnesota requested that the NRC grant the exemption by October 2018.

Costs attributable to Monticello canisters #11-15 achieving full regulatory compliance within five years are currently being evaluated.  No public safety issues have been raised, or are believed to exist, in this matter.

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See Note 14 to the consolidated financial statements for further discussion regarding nuclear related items.

Energy Source Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
NSP System
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Nuclear
14,167

 
30
%
 
14,191

 
30
%
 
12,425

 
27
%
Coal
14,737

 
30

 
13,681

 
28

 
15,961

 
35

Wind (a)
8,893

 
18

 
7,897

 
16

 
6,235

 
14

Natural Gas
5,786

 
12

 
7,810

 
16

 
6,689

 
15

Hydroelectric
3,080

 
6

 
3,203

 
7

 
3,326

 
7

Other (b)
2,052

 
4

 
1,480

 
3

 
1,083

 
2

Total
48,715

 
100
%
 
48,262

 
100
%
 
45,719

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
36,640

 
75
%
 
36,381

 
75
%
 
33,818

 
74
%
Purchased generation
12,075

 
25

 
11,881

 
25

 
11,901

 
26

Total
48,715

 
100
%
 
48,262

 
100
%
 
45,719

 
100
%
(a) 
This category includes wind energy de-bundled from RECs and also includes Windsource® RECs. The NSP System uses RECs to meet or exceed state resource requirements and may sell surplus RECs.
(b) 
Includes energy from other sources, including solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards® program is not included, and was approximately 17, 21 and eight million net KWh for 2017, 2016, and 2015, respectively.

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 (a)
 
Nuclear
 
Natural Gas
 
Weighted
Average Owned Fuel Cost
NSP System Generating Plants
 
Cost
 
Percent
 
Cost
 
Percent
 
Cost
 
Percent
 
2017
 
$
2.08

 
45
%
 
$
0.78

 
45
%
 
$
4.10

 
10
%
 
$
1.72

2016
 
2.03

 
42

 
0.80

 
44

 
3.30

 
14

 
1.67

2015
 
2.15

 
47

 
0.83

 
40

 
3.89

 
13

 
1.85

(a) 
Includes refuse-derived fuel and wood.

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

Fuel Sources

Nuclear — NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its nuclear plants. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2021 and approximately 57 percent of the requirements for 2022 through 2033;
Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 50 percent of the requirements for 2022 through 2033; and
Current enrichment service contracts cover 100 percent of the requirements through 2025 and approximately 29 percent of the requirements for 2026 through 2033.

Fabrication services for Monticello and PI are 100 percent committed through 2030 and 2019, respectively. 


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NSP-Minnesota expects sufficient uranium concentrates, conversion services and enrichment services to be available for the total fuel requirements of its nuclear generating plants. Some exposure to market price volatility will remain due to index-based pricing structures contained in certain supply contracts.

Coal — The NSP System normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2017 and 2016 were approximately 53 and 55 days of usage, respectively. Milder weather, purchase commitments and relatively low power and natural gas prices resulted in coal inventories being above optimal levels. NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana. Coal requirements for the NSP System’s major coal-fired generating plants were approximately 8.0 million tons for 2017 and 7.5 million tons for 2016. Coal requirements for 2017 increased primarily due to slightly higher natural gas prices during the year. The estimated coal requirements for 2018 are approximately 8.3 million tons.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 79 percent of their estimated coal requirements in 2018 and a declining percentage of the requirements in subsequent years. The NSP System’s 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. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have coal transportation contracts that provide for delivery of 100 and 25 percent of their coal requirements in 2018 and 2019, respectively. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Natural gas — The NSP System uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas supplies, transportation and storage services for power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to various natural gas indices. Most transportation contract pricing is based on FERC 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. At Dec. 31, 2017 and 2016, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $398 million and $382 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2018 to 2037.

The NSP System also has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2017, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 25.0 percent and 12.9 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.

Renewable energy as a percentage of the NSP System’s total energy:
 
 
2017
 
2016
Renewable
 
28.8
%
 
26.1
%
Wind
 
18.3

 
16.4

Hydroelectric
 
6.3

 
6.6

Biomass and solar
 
4.2

 
3.1


The NSP System also offers customer-focused renewable energy initiatives. Windsource allows customers in Minnesota, Wisconsin and Michigan to purchase electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 60,900 in 2017 from 54,000 in 2016.

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Additionally, to encourage the growth of solar energy in Minnesota, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® and Made in Minnesota solar incentive programs. Over 2,800 PV systems with approximately 33.75 MW of aggregate capacity have been installed in Minnesota as of Dec. 31, 2017 and 2,000 PV systems with approximately 25.2 MW of aggregate capacity were installed as of Dec. 31, 2016. The Solar*Rewards® Community® program is another option made available to encourage use of solar energy in Minnesota. This program allows for offsite development of solar and bill credits to customers based on an approved tariffed rate.
 
Wind  The NSP System acquires the majority of its wind energy from PPAs. Currently, the NSP System has more than 130 of these agreements in place, with facilities ranging in size from under one MW to more than 200 MW. The NSP System owns and operates five wind farms which have the capacity to generate 852 MW.

The NSP System had approximately 2,600 MW of wind energy on its system at the end of 2017 and 2016. In addition to receiving purchased wind energy under these agreements, the NSP System typically receives wind RECs, which are used to meet state renewable resource requirements.
The average cost per MWh of wind energy under existing contracts was approximately $44 for 2017 and $43 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.

Hydroelectric  The NSP System acquires its hydroelectric energy from both owned generation and PPAs. The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide approximately 263 MW of capacity. For 2017, PPAs provided approximately 34 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 850 MW of generation from Manitoba Hydro, which is sourced primarily from its fleet of hydroelectric facilities.

Wholesale and Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy-related products. NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. NSP-Minnesota also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. NSP-Minnesota does not serve any wholesale requirements customers at cost-based regulated rates. See Item 7 for further discussion.

NSP-Wisconsin
Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC for its wholesale electric operations, hydroelectric generation licensing, 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. NSP- Wisconsin is a transmission owning member of the MISO RTO and operates within the MISO RTO and wholesale energy market. NSP-Wisconsin and NSP-Minnesota are jointly authorized by the FERC to make wholesale electric sales at market-based prices.

The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. In recent years, NSP-Wisconsin has been submitting rate filings each year.


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Fuel and Purchased Energy Cost Recovery Mechanisms NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. Instead, under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW for approval. Once the PSCW approves the fuel cost plan, utilities defer the amount of any fuel cost under-recovery or over-recovery in excess of a two percent annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW. Rate recovery of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE. Fuel cost under-collections that exceed the two percent annual tolerance band may not be recovered if the utility earnings for that year exceed the authorized ROE.

NSP-Wisconsin’s electric fuel costs for 2017 were lower than authorized in rates and outside the two percent annual tolerance band, primarily due to lower purchased power costs coupled with moderate weather and generation sales into the MISO market.  Under the fuel cost recovery rules, NSP-Wisconsin may retain approximately $4 million of fuel costs and defer approximately $10 million through Dec. 31, 2017. NSP-Wisconsin will file a reconciliation of 2017 fuel costs with the PSCW.  The amount of any potential refund is subject to review and approval by the PSCW, which is not expected until mid-2018.

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-recoveries are refunded and any under-recoveries are collected from the customers over the subsequent 12-month period.

Wisconsin Energy Efficiency Program In Wisconsin, the primary energy efficiency program is funded by the state’s utilities, but operated by independent contractors subject to oversight by the PSCW and the utilities. NSP-Wisconsin recovers these costs in rates charged to Wisconsin retail customers.

Capacity and Demand

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Capacity and Demand.

Energy Sources and Related Transmission Initiatives

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Energy Sources and Related Transmission Initiatives.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse to Madison, Wis. Transmission Line — In 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a 345 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis.  NSP-Wisconsin’s half of the line will be shared with three co-owners, Dairyland Power Cooperative, WPPI Energy and Southern Minnesota Municipal Power Agency-Wisconsin.

In 2015, the PSCW issued its order approving a CPCN and route for the project. Two groups have appealed the CPCN order to the La Crosse County Circuit Court (Circuit Court). In May 2017, the Circuit Court determined that the project was necessary, allowing construction to continue on a seven mile segment near La Crosse, Wis. The parties have appealed various aspects of the case to the Wisconsin Court of Appeals which is currently pending. The CPCN remains in full effect unless one of the parties seeks and receives a stay from the court and posts a bond to cover damages the utilities may incur due to delay. The 180-mile project is expected to cost approximately $541 million. NSP-Wisconsin’s portion of the investment, which includes AFUDC, is estimated to be approximately $200 million. Construction on the line began in January 2016, with completion anticipated by late 2018.

Fuel Supply and Costs

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Fuel Supply and Costs.

Wholesale and Commodity Marketing Operations

NSP-Wisconsin operates an integrated system with NSP-Minnesota. NSP-Wisconsin does not serve any wholesale requirements customers at cost-based regulated rates. See NSP-Minnesota Wholesale and Commodity Marketing Operations.


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Table of Contents

PSCo
Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC for its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce. PSCo is not presently a member of an RTO and does not operate within an RTO energy market. PSCo is authorized by the FERC to make wholesale electric sales at market-based prices to customers outside PSCo’s balancing authority area.

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

ECA — Recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly.
PCCA — Recovers purchased capacity payments.
SCA — Recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised on a quarterly basis.
DSMCA — Recovers DSM, interruptible service costs and performance initiatives for achieving energy savings goals.
RESA — Recovers the incremental costs of compliance with the RES with a maximum of two percent of the customer’s bill.
WCA — Premium service for customers who choose to pay for renewable resources.
TCA — Recovers costs associated with transmission investment outside of rate cases.
CACJA — Recovers costs associated with the CACJA.

PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. PSCo’s wholesale customers pay the full cost of certain renewable energy purchase and generation costs through a fuel clause and in exchange receive RECs associated with those resources. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility 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
PSCo
6,671

 
6,585

 
6,284

 
6,462


The peak demand for PSCo’s system typically occurs in the summer. The 2017 system peak demand for PSCo occurred on July 19, 2017. The 2017 system peak demand was higher than 2016 due to warmer July summer weather. The forecast of system peak assumes normal weather conditions.

Energy Sources and Related Transmission Initiatives

PSCo expects to meet its system capacity requirements through existing electric generating stations, power purchases, new generation facilities, DSM options and phased expansion of existing generation at select power plants.

Purchased Power PSCo has contracts to purchase power from other utilities and IPPs. Long-term purchased power contracts for dispatchable resources typically require a periodic capacity charge and an energy charge for energy actually purchased. PSCo also contracts to purchase power for both wind and solar resources. In addition, PSCo 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 In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to PSCo’s customers.


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Table of Contents

Rush Creek Wind Ownership Proposal — In 2016, the CPUC granted PSCo a CPCN to build, own and operate a 600 MW wind generation facility in Colorado at Rush Creek. The CPCN includes a hard cost-cap of $1.096 billion (including transmission costs) and a capital cost sharing mechanism between customers and PSCo of 82.5 percent to customers and 17.5 percent to PSCo for every $10 million the project comes in below the cost-cap.

All major contracts required to complete the project have been executed. PTC components for safe harboring the facility have been fabricated and construction began in April 2017.

Investment costs will be recovered through the RESA and ECA riders until PSCo’s next rate case following Rush Creek’s in-service date. The wind generation facility is anticipated to be in service in October 2018.

Colorado Energy Plan (CEP) — In 2016, PSCo filed its 2016 Electric Resource Plan (ERP) which included the estimated need for additional generation resources through spring of 2024. In 2017, PSCo filed an updated capacity need with the CPUC of 450 MW in 2023.

In August 2017, PSCo and various other stakeholders filed a stipulation agreement proposing the CEP, an alternative plan that increases the amount of new resources sought under the ERP. The CEP would increase PSCo’s potential capacity need up to 1,110 MW due to the proposed retirement of two coal units. The major components include:

Early retirement of 660 MWs of coal-fired generation at Comanche Units 1 (2022) and 2 (2025);
Accelerated depreciation for the early retirement of the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs;
A RFP for up to 1,000 MW of wind, 700 MW of solar and 700 MW of natural gas and/or storage;
Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources;
Reduction of the RESA rider, from two percent to one percent effective beginning 2021 or 2022; and
Construction of a new transmission switching station to further the development of renewable generating resources.

Hearings were held in February 2018 with two parties opposing both the coal retirements and utility ownership. Fifteen parties in the proceeding support the CEP. The CPUC is expected to rule on the stipulation agreement in March 2018. PSCo is currently evaluating bids from a RFP and anticipates filing its recommended portfolios in April 2018. A CPUC decision on the recommended portfolio is anticipated in the summer of 2018.

Approval of the CEP portfolio could increase capital investment up to $1.5 billion, based on a preliminary estimate. The level of capital investment may decline due to lower renewable pricing and the ultimate composition of assets selected as part of the RFP process. The expected cost and potential capital investment of the CEP will be determined once a recommended portfolio is filed with the CPUC. The CEP portfolio is not included in PSCo and Xcel Energy’s base capital expenditures forecast. See Item 7. Management’s Discussion and Analysis of Financial Condition and Result of Operations - Liquidity and Capital Resources for further discussion of the capital forecast.

Boulder, Colorado Municipalization — In 2011, in the City of Boulder, Colorado (Boulder), voters passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Since that time, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility as premature and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. Subsequently, the Colorado Supreme Court granted Boulder’s petition to review the Court of Appeals decision and oral arguments were held on Feb. 14, 2018. A ruling on the petition is anticipated in 2018.

In 2015, the Boulder District Court (District Court) affirmed a prior CPUC decision that Boulder cannot serve customers outside its city limits; these customers were included in Boulder’s plan at the time. The District Court also ruled the CPUC has jurisdiction over the transfer of any facilities to Boulder and in determining how the systems are separated. Further, the District Court found that the CPUC must give approval before Boulder files any condemnation proceeding. Boulder does not have authorization to initiate a condemnation proceeding at this time.

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Table of Contents

Boulder has filed multiple separation applications, the most recent one being in May 2017, which was challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position, stating PSCo is not required to undertake many of Boulder’s proposals, such as acting as a financier and contractor for Boulder. Additionally, the CPUC approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain items, including:

Filing an agreement between Boulder and PSCo providing permanent rights for PSCo to place and access facilities in Boulder needed to continue to serve its customers;
Filing a complete and accurate revised list of distribution assets desired to be transferred; and
Filing an agreement to address payments from Boulder to PSCo for costs of Boulder’s municipalization efforts.

Boulder has requested that the CPUC grant an extension through March 13, 2018 to complete such filings. Once those filings have been submitted, additional hearings may be held.

In November 2017, Boulder voters passed certain measures regarding Boulder’s pursuit of municipalization, including an extension and increase of the Utility Occupational Tax for funding Boulder’s exploration of municipalization.

MWTG — PSCo, along with nine other electric service providers from the Rocky Mountain region, have been considering creating and operating a joint transmission tariff to increase wholesale market efficiency and improve regional transmission planning.  In September 2017, the MWTG determined that membership in the SPP RTO could provide opportunities to reduce customer costs, and maximize resource and electric grid utilization. In October 2017, the MWTG commenced negotiations with SPP through the SPP public stakeholder process.

SPP’s Board of Directors and organizational groups have begun to address the MWTG’s proposed terms for integration into the SPP RTO. Should the MWTG decide to move forward, SPP would make filings with the FERC and PSCo would make filings with the CPUC and the FERC, in the later part of 2018. If approved, MWTG operations within the SPP RTO would not be expected to begin until late 2019 at the earliest. PSCo recently engaged a consultant to conduct an analysis of the benefits associated with membership in the SPP RTO. The analysis assumed gas price forecasts that are lower than gas price forecasts used by the other MWTG utilities in their analysis of the benefits associated with membership in the SPP RTO. PSCo is in the process of evaluating that analysis.

Energy Source Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
PSCo
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal
14,609

 
44
%
 
15,895

 
47
%
 
18,601

 
54
%
Natural Gas
9,195

 
28

 
8,632

 
25

 
7,948

 
23

Wind (a)
7,804

 
24

 
8,106

 
24

 
6,699

 
19

Hydroelectric
624

 
2

 
1,179

 
3

 
662

 
2

Other (b)
670

 
2

 
393

 
1

 
705

 
2

Total
32,902

 
100
%
 
34,205

 
100
%
 
34,615

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
23,053

 
70
%
 
22,753

 
67
%
 
22,981

 
66
%
Purchased generation
9,849

 
30

 
11,452

 
33

 
11,634

 
34

Total
32,902

 
100
%
 
34,205

 
100
%
 
34,615

 
100
%
(a) 
This category includes wind energy de-bundled from RECs and also includes Windsource RECs. PSCo 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 393, 396 and 245 million net KWh for 2017, 2016, and 2015, respectively.


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Table of Contents

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
PSCo Generating Plants
 
Cost
 
Percent
 
Cost
 
Percent
 
2017
 
$
1.56

 
70
%
 
$
3.82

 
30
%
 
$
2.25

2016
 
1.75

 
72

 
3.79

 
28

 
2.33

2015
 
1.75

 
75

 
3.89

 
25

 
2.29


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

Fuel Sources

Coal  PSCo normally maintains approximately 35 - 50 days of coal inventory. Coal supply inventories at Dec. 31, 2017 and 2016 were approximately 48 and 36 days of usage, respectively. PSCo has contracted for coal supply to provide 75 percent of its 9.1 million tons of estimated coal requirements in 2018, and a declining percentage of requirements in subsequent years. PSCo’s 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. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 100 percent its coal requirements in 2018 and 2019. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Natural gas  PSCo uses both firm and interruptible natural gas supply in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid spot market. The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company and the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 11 to the consolidated financial statements for further discussion.

Most transportation contract pricing is based on FERC 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.

At Dec. 31, 2017, PSCo’s commitments related to gas supply contracts, which expire between 2021 through 2023, were approximately $545 million and commitments related to gas transportation and storage contracts, which expire between 2018 through 2040, were approximately $620 million.
At Dec. 31, 2016, PSCo’s commitments related to gas supply contracts were approximately $654 million and commitments related to gas transportation and storage contracts were approximately $573 million.

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


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Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2017, PSCo was in compliance with mandated RPS, which requires generation from renewable resources of 20.0 percent of electric retail sales.

Renewable energy as a percentage of PSCo’ total energy:
 
 
2017
 
2016
Renewable
 
27.7
%
 
28.3
%
Wind
 
23.7

 
23.7

Hydroelectric, biomass and solar
 
3.9

 
4.6


PSCo also offers customer-focused renewable energy initiatives. Windsource® allows customers to purchase electricity from renewable sources. The number of customers utilizing Windsource increased to approximately 50,000 in 2017 from 46,000 in 2016.

Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program. Over 34,900 PV systems with approximately 310 MW of aggregate capacity have been installed in Colorado as of Dec. 31, 2017 and over 32,500 PV systems with approximately 276 MW of aggregate capacity were installed as of Dec. 31, 2016. Additionally, 33 community solar gardens with 33.5 MW of capacity have been completed in Colorado as of Dec. 31, 2017.

Wind — PSCo acquires the majority of its wind energy from PPAs. Currently, PSCo has 18 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.

PSCo had approximately 2,560 MW of wind energy on its system at the end of 2017 and 2016. In addition to receiving purchased wind energy under these agreements, PSCo typically receives wind RECs which are used to meet state renewable resource requirements.
The average cost per MWh of wind energy under these contracts was approximately $42 in 2017 and 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, previously executed contracts continued to benefit from improvements in wind 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

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy, ancillary services and energy related products. PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. PSCo also engages in trading activity unrelated to hedging and sharing of any margins is determined through state regulatory proceedings as well as the operation of the FERC approved joint operating agreement. See Item 7 for further discussion.


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SPS
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.

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



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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 12).

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.

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.

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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.

Energy Source Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
SPS
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, was approximately 26, 14 and 13 million net KWh for 2017, 2016, and 2015, respectively.

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.


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Table of Contents

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.

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.


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Table of Contents

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.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of Xcel Energy Inc.’s utility subsidiaries and TransCos, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy Inc.’s utility subsidiaries’ activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 12 to the accompanying consolidated financial statements for a discussion of other regulatory matters.

Xcel Energy 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.

FERC Order, ROE Policy — In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order issued in a complaint proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including two ROE complaints involving the MISO TOs, which include NSP-Minnesota and NSP-Wisconsin. In April 2017, the District of Columbia Circuit (D.C. Circuit) vacated and remanded the June 2014 ROE order. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for the NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. The FERC has yet to act on the D.C. Circuit’s decision. See Note 12 to the consolidated financial statements for discussion of the D.C. Circuit’s decision and the impact on the MISO ROE Complaints.

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.

Public Utility Regulatory Policies Act (PURPA) Enforcement Complaint against CPUC In December 2016, Sustainable Power Group, LLC (sPower) petitioned the FERC to initiate an enforcement action in federal court against the CPUC under PURPA. The petition asserts that a December 2016 CPUC ruling, which indicated that a QF must be a successful bidder in a PSCo resource acquisition bidding process, violated PURPA and FERC rules. In January 2017, PSCo filed a motion to intervene and protest, arguing that the FERC should decline the petition. The CPUC filed a similar pleading. sPower has proposed to construct 800 MW of solar generation and 700 MW of wind generation in Colorado and seeks to require PSCo to contract for these resources under PURPA.

If sPower were to prevail, PSCo’s ability to select generation resources through competitive bidding would be negatively affected. However, due to a lack of quorum at the FERC, the FERC did not act on that petition within the sixty days contemplated by PURPA.
Subsequently sPower filed a complaint for declaratory and injunctive relief in the United States District Court for the District of Colorado (District Court) requesting that the court find the bidding requirement in the CPUC QF rules to be unlawful. PSCo intervened in that proceeding and the CPUC filed a motion to dismiss. In June 2017, the United States Magistrate Judge issued a recommendation to the District Court that sPower’s complaint be dismissed because sPower failed to establish that it faced a substantial risk of harm. In October 2017, the District Court denied the CPUC’s motion to dismiss and instead allowed sPower to file an amended complaint. The case effectively started over and PSCo intervened. The CPUC filed a motion to dismiss the amended complaint which is currently pending before the District Court. The timing of a resolution in this case is unclear.


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Table of Contents

Electric Operating Statistics

Electric Sales Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
Electric sales (Millions of KWh)
 
 
 
 
 
Residential
24,216

 
24,726

 
24,498

Large C&I
27,951

 
27,664

 
27,719

Small C&I
35,493

 
35,830

 
35,806

Public authorities and other
1,055

 
1,103

 
1,071

Total retail
88,715

 
89,323

 
89,094

Sales for resale
18,349

 
18,694

 
15,283

Total energy sold
107,064

 
108,017

 
104,377

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
3,082,974

 
3,053,732

 
3,023,494

Large C&I
1,241

 
1,228

 
1,229

Small C&I
433,883

 
432,012

 
429,617

Public authorities and other
69,376

 
68,935

 
68,595

Total retail
3,587,474

 
3,555,907

 
3,522,935

Wholesale
58

 
52

 
47

Total customers
3,587,532

 
3,555,959

 
3,522,982

 
 
 
 
 
 
Electric revenues (Millions of Dollars)
 
 
 
 
 
Residential
$
2,975

 
$
2,966

 
$
2,891

Large C&I
1,779

 
1,707

 
1,690

Small C&I
3,463

 
3,328

 
3,304

Public authorities and other
143

 
140

 
137

Total retail
8,360

 
8,141

 
8,022

Wholesale
719

 
693

 
660

Other electric revenues
597

 
666

 
594

Total electric revenues
$
9,676

 
$
9,500

 
$
9,276

 
 
 
 
 
 
KWh sales per retail customer
24,729

 
25,120

 
25,290

Revenue per retail customer
$
2,330

 
$
2,289

 
$
2,277

Residential revenue per KWh

12.29
¢
 

11.99
¢
 

11.80
¢
Large C&I revenue per KWh
6.36

 
6.17

 
6.10

Small C&I revenue per KWh
9.76

 
9.29

 
9.23

Total retail revenue per KWh
9.42

 
9.11

 
9.00

Wholesale revenue per KWh
3.92

 
3.71

 
4.32


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Table of Contents

Energy Source Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
Xcel Energy
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal
40,344

 
36
%
 
40,566

 
36
%
 
47,003

 
43
%
Natural Gas
24,932

 
23

 
27,351

 
25

 
25,151

 
23

Wind (a)
22,526

 
21

 
22,123

 
20

 
18,186

 
17

Nuclear
14,168

 
13

 
14,191

 
13

 
12,895

 
12

Hydroelectric
3,866

 
4

 
4,435

 
4

 
4,001

 
4

Other (b)
3,329

 
3

 
2,167

 
2

 
1,456

 
1

Total
109,165

 
100
%
 
110,833

 
100
%
 
108,692

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
72,539

 
66
%
 
74,149

 
67
%
 
73,279

 
67
%
Purchased generation
36,626

 
34

 
36,684

 
33

 
35,413

 
33

Total
109,165

 
100
%
 
110,833

 
100
%
 
108,692

 
100
%
(a) 
This category includes wind energy de-bundled from RECs and also includes Windsource RECs. Xcel Energy uses RECs to meet or exceed state resource requirements and may sell surplus RECs.
(b) 
Includes energy from other sources, including solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, and was approximately 435, 430 and 266 million net KWh for 2017, 2016 and 2015, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

Xcel Energy operates natural gas local distribution companies in six states, including Minnesota, Wisconsin, Michigan, South Dakota, North Dakota, and Colorado with PSCo being the largest. The most significant developments in the natural gas operations of the utility subsidiaries are uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small C&I customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 2000 to 2017, average annual sales to the typical residential customer declined 17 percent, while sales to the typical small C&I customer declined 10 percent, each on a weather-normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost-recovery mechanisms, high prices can encourage further efficiency efforts by customers.

The PHMSA

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

PHMSA is currently working through the rule with its Pipeline Advisory Committee. Current estimates are the rule will likely go into effect in late 2018 or early 2019.  
 
Xcel Energy has been taking actions that were intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.  PSCo and NSP-Minnesota can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA and GUIC riders, respectively.


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Table of Contents

NSP-Minnesota
Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction Retail rates, services and other aspects of NSP-Minnesota’s retail natural gas operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority over security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting customers’ future energy needs. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Minnesota is subject to the DOT, the Minnesota Office of Pipeline Safety, the NDPSC and the SDPUC for pipeline safety compliance, including pipeline facilities used in electric utility operations for fuel deliveries.

Purchased Gas and Conservation Cost-Recovery Mechanisms NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas, transportation service and storage service. The annual difference between the natural gas cost revenues collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period.

NSP-Minnesota also recovers costs associated with transmission and distribution pipeline integrity management programs through its GUIC rider. Costs recoverable under the GUIC rider include funding for pipeline assessments as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

Minnesota state law requires utilities to invest 0.5 percent of their state natural gas revenues in CIP. These costs are recovered through customer base rates and an annual cost-recovery mechanism for the CIP expenditures.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 893,062 MMBtu, which occurred on Dec. 26, 2017 and 800,232 MMBtu, which occurred on Jan. 18, 2016.

NSP-Minnesota purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 640,489 MMBtu per day. In addition, NSP-Minnesota contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 26 percent of winter natural gas requirements and 29 percent of peak day firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 30 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another. In February 2017, the MPUC approved NSP-Minnesota’s contract demand levels for the 2016 through 2017 heating season. Demand levels for the 2017 through 2018 heating season were filed with the MPUC in August 2017.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC.


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The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Minnesota’s regulated retail natural gas distribution business:
2017
$
3.89

2016
3.47

2015
4.07


The cost of natural gas in 2017 increased due to higher wholesale commodity prices.

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2018 through 2033.

NSP-Minnesota has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2017, NSP-Minnesota was committed to approximately $439 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 27 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

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

NSP-Wisconsin
Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction NSP-Wisconsin is regulated by the PSCW and the MPSC. The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Wisconsin is subject to the DOT, the PSCW and the MPSC for pipeline safety compliance.

Natural Gas Cost-Recovery Mechanisms NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin operations to recover the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds NSP-Wisconsin was not prudent in its procurement activities.

NSP-Wisconsin’s natural gas rate schedules for Michigan customers include a natural gas cost-recovery factor, which is based on 12-month projections and trued-up to the actual amounts on an annual basis.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 160,170 MMBtu, which occurred on Dec. 26, 2017 and 155,583 MMBtu, which occurred on Jan. 18, 2016.

NSP-Wisconsin purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 139,293 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 33 percent of winter natural gas requirements and 34 percent of peak day firm requirements of NSP-Wisconsin.


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NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent to help meet its peak requirements. This peak-shaving facility has a production capacity equivalent to 18,000 MMBtu of natural gas per day, or approximately 12 percent of peak day firm requirements. LNG plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2017-2018 supply plan was approved by the PSCW in October 2017.

Natural Gas Supply and Costs

NSP-Wisconsin actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Wisconsin conducts natural gas price hedging activity that has been approved by the PSCW.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Wisconsin’s regulated retail natural gas distribution business:
2017
$
3.88

2016
3.62

2015
4.11


The cost of natural gas in 2017 increased due to higher commodity prices.

The cost of natural gas supply, transportation service and storage service is recovered through various cost-recovery adjustment mechanisms. NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2018 through 2029.

NSP-Wisconsin has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2017, NSP-Wisconsin was committed to approximately $84 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 10 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

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

PSCo
Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the Federal Natural Gas Act. PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance.

Purchased Natural Gas and Conservation Cost-Recovery Mechanisms PSCo has retail adjustment clauses that recover purchased natural gas and other resource costs:

GCA — Recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in natural gas rates.
DSMCA — Recovers costs of DSM and performance initiatives to achieve various energy savings goals.
PSIA — Recovers costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines.


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Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for PSCo was 1,948,167 MMBtu, which occurred on Jan. 5, 2017 and 1,932,070 MMBtu, which occurred on Dec. 17, 2016.

PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,818,151 MMBtu per day, which includes 854,852 MMBtu of natural gas held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 43,500 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations.

PSCo is required by CPUC regulations to file a natural gas purchase plan each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 12-month period of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the previous 12-month period.

Natural Gas Supply and Costs

PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, PSCo conducts natural gas price hedging activities that have been approved by the CPUC.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail natural gas distribution business:
2017
$
3.45

2016
3.27

2015
3.92


The cost of natural gas in 2017 increased due to higher wholesale commodity prices.

PSCo has natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2017, PSCo was committed to approximately $1.4 billion in such obligations under these contracts, which expire in various years from 2018 through 2029.

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2017, PSCo purchased natural gas from approximately 31 suppliers.

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

SPS
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.

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


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Natural Gas Operating Statistics
 
Year Ended Dec. 31
 
2017
 
2016
 
2015
Natural gas deliveries (Thousands of MMBtu)
 
 
 
 
 
Residential
134,189

 
132,853

 
135,394

C&I
87,271

 
84,082

 
86,093

Total retail
221,460

 
216,935

 
221,487

Transportation and other
142,497

 
133,498

 
125,263

Total deliveries
363,957

 
350,433

 
346,750

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
1,856,221

 
1,835,507

 
1,814,321

C&I
157,798

 
157,286

 
156,306

Total retail
2,014,019

 
1,992,793

 
1,970,627

Transportation and other
7,705

 
7,316

 
6,981

Total customers
2,021,724

 
2,000,109

 
1,977,608

 
 
 
 
 
 
Natural gas revenues (Millions of Dollars)
 
 
 
 
 
Residential
$
1,006

 
$
930

 
$
1,043

C&I
524

 
469

 
547

Total retail
1,530

 
1,399

 
1,590

Transportation and other
120

 
132

 
82

Total natural gas revenues
$
1,650

 
$
1,531

 
$
1,672

 
 
 
 
 
 
MMBtu sales per retail customer
109.96

 
108.86

 
112.39

Revenue per retail customer
$
760

 
$
702

 
$
807

Residential revenue per MMBtu
7.50

 
7.00

 
7.70

C&I revenue per MMBtu
6.00

 
5.58

 
6.36

Transportation and other revenue per MMBtu
0.84

 
0.99

 
0.65


GENERAL

Seasonality

The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s 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

Xcel Energy is a vertically integrated utility in all of its jurisdictions, subject to traditional cost-of-service regulation by state public utilities commissions. However, Xcel Energy is subject to different public policies that promote competition and the development of energy markets. Xcel Energy’s 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 distributed generation including solar generation and in most jurisdictions can avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Several states 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 Xcel Energy’s 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, Xcel Energy Inc.’s utility subsidiaries and their wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load.

In addition, FERC Order 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. State public utilities commissions have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. Xcel Energy Inc.’s utility subsidiaries also have 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 each of Xcel Energy Inc.’s utility subsidiaries faces these challenges, Xcel Energy believes their rates and services are competitive with currently available alternatives.

ENVIRONMENTAL MATTERS

Xcel Energy’s 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. Xcel Energy has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Xcel Energy’s 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 Xcel Energy’s operations. See Item 7 and Notes 12 and 13 to the consolidated 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. Xcel Energy 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. Xcel Energy believes, based on prior state commission practice, it would recover the cost of these initiatives through rates.

Xcel Energy is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. Starting in 2011, Xcel Energy began reporting GHG emissions to the EPA under the EPA’s mandatory GHG Reporting Program.

Xcel Energy estimates that in 2017, it reduced the CO2 emissions associated with the electric generating resources used to serve its customers by 35 percent from 2005 levels. This reduction accounts for emissions both from electric generating plants owned by Xcel Energy as well as purchased power. To achieve this goal, Xcel Energy primarily relied on strategies that resulted in:

Development of renewable energy facilities;
Retirement and replacement of existing generating plants; and
Customer energy efficiency programs.

CAPITAL SPENDING AND FINANCING

See Item 7 for a discussion of expected capital expenditures and funding sources.

EMPLOYEES

As of Dec. 31, 2017, Xcel Energy had 11,075 full-time employees and 59 part-time employees, of which 5,115 were covered under collective-bargaining agreements. See Note 9 to the consolidated financial statements for further discussion.


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EXECUTIVE OFFICERS (a)
Name
 
Age (b)
 
Current and Recent Positions Held
Ben Fowke
 
59
 
Chairman of the Board, President and Chief Executive Officer and Director, Xcel Energy Inc., August 2011 to present. Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS, January 2015 to present. Previously, President and Chief Operating Officer, Xcel Energy Inc., August 2009 to August 2011.
Christopher B. Clark
 
51
 
President and Director, NSP-Minnesota, January 2015 to present. Previously, Regional Vice President, Rates and Regulatory Affairs, NSP-Minnesota, October 2012 to December 2014; Managing Director, Government and Regulatory Affairs, NSP-Minnesota, January 2012 to October 2012; Managing Attorney, Xcel Energy Inc., November 2007 to January 2012.
David L. Eves
 
59
 
President and Director, PSCo, January 2015 to present. Previously, President, Director and Chief Executive Officer, PSCo, December 2009 to December 2014. Effective March 1, 2018 he will serve as Executive Vice President and Group President, Utilities.
Robert C. Frenzel
 
47
 
Executive Vice President, Chief Financial Officer, Xcel Energy Inc., May 2016 to present.  Previously, Senior Vice President and Chief Financial Officer, Luminant, a subsidiary of Energy Future Holdings Corp., an electric utility and power generation company, February 2012 to April 2016; Senior Vice President for Corporate Development, Strategy and Mergers and Acquisitions, Energy Future Holdings Corp., February 2009 to February 2012.  In April 2014, Energy Future Holdings Corp., the majority of its subsidiaries, including Texas Competitive Energy Holdings (TCEH) the parent company of Luminant, filed a voluntary bankruptcy petition under Chapter 11 of the United States Bankruptcy Code.  TCEH emerged from Chapter 11 in October 2016. 
David T. Hudson
 
57
 
President and Director, SPS, January 2015 to present. Previously, President, Director and Chief Executive Officer, SPS, January 2014 to December 2014; Director, Community Service & Economic Development, SPS, April 2011 to January 2014; Director, Strategic Planning, SPS, May 2008 to April 2011.
Kent T. Larson
 
58
 
Executive Vice President and Group President Operations, Xcel Energy Inc., January 2015 to present. Previously, Senior Vice President, Group President Operations, Xcel Energy Services Inc., August 2014 to December 2014; Senior Vice President Operations, Xcel Energy Services Inc., September 2011 to August 2014; Chief Energy Supply Officer, Xcel Energy Services Inc., March 2010 to September 2011.
Marvin E. McDaniel, Jr.
 
58
 
Executive Vice President, Group President, Utilities, and Chief Administrative Officer, Xcel Energy Inc., January 2015 to present. Previously, Senior Vice President, Chief Administrative Officer, Xcel Energy Inc., August 2012 to December 2014; Senior Vice President and Chief Administrative Officer, Xcel Energy Services Inc., September 2011 to August 2012; Vice President and Chief Administrative Officer, Xcel Energy Services Inc., August 2009 to September 2011 and Vice President, Talent and Technology Business Areas, Xcel Energy Services Inc., August 2009 to September 2011. Xcel Energy has previously announced that Marvin E. McDaniel, Jr. will retire in 2018. Effective March 1, 2018 he will serve as Executive Vice President and Chief Administrative Officer.
Timothy O’Connor
 
58
 
Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc., February 2013 to present. Previously, Acting Chief Nuclear Officer, NSP-Minnesota, September 2012 to February 2013; Vice President, Engineering and Nuclear Regulatory Compliance and Licensing July 2012 to September 2012; Monticello Site Vice President, May 2007 to July 2012.
Judy M. Poferl
 
58
 
Senior Vice President, Corporate Secretary and Executive Services, Xcel Energy Inc., January 2015 to present. Previously, Vice President, Corporate Secretary, Xcel Energy Inc., May 2013 to December 2014; President, Director and Chief Executive Officer, NSP-Minnesota, August 2009 to May 2013.
Jeffrey S. Savage
 
46
 
Senior Vice President, Controller, Xcel Energy Inc., January 2015 to present. Previously, Vice President, Controller, Xcel Energy Inc., September 2011 to December 2014; Senior Director, Financial Reporting, Corporate and Technical Accounting, Xcel Energy Services Inc., December 2009 to September 2011.
Mark E. Stoering
 
57
 
President and Director, NSP-Wisconsin, January 2015 to present. Previously, President, Director and Chief Executive Officer, NSP-Wisconsin, January 2012 to December 2014; Vice President, Portfolio Strategy and Business Development, Xcel Energy Services Inc., August 2000 to December 2011.
Scott M. Wilensky
 
61
 
Executive Vice President, General Counsel, Xcel Energy Inc., January 2015 to present. Previously, Senior Vice President, General Counsel, Xcel Energy Inc., September 2011 to December 2014; Vice President, Regulatory and Resource Planning, Xcel Energy Services Inc., September 2009 to September 2011.
 
(a)    No family relationships exist between any of the executive officers or directors.
(b)    Ages as of Dec. 31, 2017.

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Item 1A — Risk Factors

Xcel Energy 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 each Board of Directors’ committee have responsibility for overseeing the identification and mitigation of key risks and reporting its assessments and activities to the full Board of Directors.

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 Xcel Energy’s 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.

At a threshold level, Xcel Energy 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, Xcel Energy manages and 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.

The Board of Directors approaches oversight, management and mitigation of risk as an integral and continuous part of its governance of Xcel Energy. First, the Board of Directors regularly reviews management’s key risk assessment and analyzes areas of existing and future risks and opportunities. In addition, the Board of Directors assigns oversight of certain critical risks to each of its four standing committees to ensure these risks are well understood and are given focused oversight by the appropriate committee. The Audit Committee is responsible for reviewing the adequacy of risk oversight and affirming that appropriate oversight occurs. New risks are considered and assigned as appropriate during the annual Board of Directors’ and committee evaluation process, and committee charters and annual work plans are updated accordingly. Committees regularly report on their oversight activities and certain risk issues may be brought to the full Board of Directors for consideration where deemed appropriate to ensure broad Board of Directors’ understanding of the nature of the risk. Finally, the Board of Directors conducts an annual strategy session where Xcel Energy’s future plans and initiatives are reviewed.
 

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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.

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.


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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 the ability of our utility subsidiaries to recover their costs from their customers and there may be changes in circumstances or in the regulatory environment that impair the ability of our utility subsidiaries to recover costs from their customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies. The utility commissions in the states where we operate 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, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.

The profitability of our utility 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. Our utility subsidiaries provide service at rates approved by one or more regulatory commissions. These rates are generally regulated and based on an analysis of the utility’s costs incurred in a test year. Our utility subsidiaries are subject to both future and historical test years depending upon the regulatory mechanisms approved in each jurisdiction. Thus, the rates a utility is allowed to charge may or may not match its 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 the costs of our utility subsidiaries 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 our utility subsidiaries will not be able to fully recover their fuel costs from their customers. Furthermore, there could be changes in the regulatory environment that would impair the ability of our utility subsidiaries to recover costs historically collected from their customers, or these factors could cause the operating utilities 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 and the payment of dividends on our common stock.

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 or our subsidiaries’ 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, our utility subsidiaries 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.


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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 nuclear decommissioning fund and 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 CAISO, SPP, PJM, 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 Xcel Energy could trigger settlement accounting and could require Xcel Energy to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

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.


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We must rely on cash from our subsidiaries to make dividend payments.

We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and our ability to service our indebtedness and pay dividends depends upon the operating cash flows of our subsidiaries and the payment of dividends to us. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for dividends on our common stock. In addition, each subsidiary’s ability to pay dividends to us depends on any statutory and/or contractual restrictions which may include requirements to maintain minimum levels of equity ratios, working capital or assets. Also, our utility subsidiaries are regulated by various state utility commissions, which possess broad powers to ensure that the needs of the utility customers are being met.

If our utility subsidiaries were to cease making dividend payments, our ability to pay dividends on our common stock or otherwise meet our financial obligations could be adversely affected.

Federal tax law may significantly impact our business.

Xcel Energy’s utility subsidiaries collect 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 distribution 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 or distribution 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 Xcel Energy 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. Xcel Energy 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. Xcel Energy 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.

Our subsidiary, NSP-Minnesota, is subject to the risks of nuclear generation.

NSP-Minnesota’s two nuclear stations, PI and Monticello, subject it to the risks of nuclear generation, which include:

The risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal and the current lack of a long-term disposal solution for radioactive materials;
Limitations on the amounts and types of insurance available to cover losses that might arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor; and
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. For example, similar to pensions, interest rate and other assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or a substantial increase in operating expenses. In addition, the Institute for Nuclear Power Operations reviews NSP-Minnesota’s nuclear operations and nuclear generation facilities. Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

If an incident did occur, it could have a material effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.


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NSP-Wisconsin’s production and transmission system is operated on an integrated basis with NSP-Minnesota’s production and transmission system, and NSP-Wisconsin may be subject to risks associated with NSP-Minnesota’s nuclear generation.

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 and/or natural gas services to our customers. The impact of these cost and reliability issues vary in magnitude for each operating subsidiary depending upon unique 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.

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.

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.


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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. While the number of customers is growing, sales growth is relatively modest due to an increased focus on energy efficiency including federal standards for appliance and lighting efficiency and distributed generation, primarily solar PV. 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.

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, including our nuclear power plants under the NRC’s design basis threat requirements. 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.


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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, shareholders 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.

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 in most of our states, 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 gas 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.


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

Our electric and natural gas utility businesses are 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. Because natural gas is heavily used for residential and commercial heating, the demand depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. 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.


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Item 2 — Properties

Virtually all of the utility plant property of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS is subject to the lien of their first mortgage bond indentures.

Electric Utility Generating Stations:
NSP-Minnesota

Station, Location and Unit
 
Fuel
 
Installed
 
Summer 2017
Net Dependable
Capability (MW)
 
Steam:
 
 
 
 
 
 
 
A.S. King-Bayport, Minn., 1 Unit
 
Coal
 
1968
 
511

 
Sherco-Becker, Minn.
 
 
 
 
 
 
 
Unit 1
 
Coal
 
1976
 
680

 
Unit 2
 
Coal
 
1977
 
682

 
Unit 3
 
Coal
 
1987
 
517

 (a)
Monticello-Monticello, Minn., 1 Unit
 
Nuclear
 
1971
 
617

 
PI-Welch, Minn.
 
 
 
 
 
 
 
Unit 1
 
Nuclear
 
1973
 
521

 
Unit 2
 
Nuclear
 
1974
 
519

 
Various locations, 4 Units
 
Wood/Refuse-derived fuel
 
Various
 
36

 (b)
Combustion Turbine:
 
 
 
 
 
 
 
Angus Anson-Sioux Falls, S.D., 3 Units
 
Natural Gas
 
1994-2005
 
327

 
Black Dog-Burnsville, Minn., 2 Units
 
Natural Gas
 
1987-2002
 
282

 
Blue Lake-Shakopee, Minn., 6 Units
 
Natural Gas
 
1974-2005
 
453

 
High Bridge-St. Paul, Minn., 3 Units
 
Natural Gas
 
2008
 
530

 
Inver Hills-Inver Grove Heights, Minn., 6 Units
 
Natural Gas
 
1972
 
282

 
Riverside-Minneapolis, Minn., 3 Units
 
Natural Gas
 
2009
 
454

 
Various locations, 14 Units
 
Natural Gas
 
Various
 
67

 
Wind:
 
 
 
 
 
 
 
Border-Rolette County, N.D., 75 Units
 
Wind
 
2015
 
148

 (c)
Courtenay Wind, N.D., 100 Units
 
Wind
 
2016
 
195

 (c)
Grand Meadow-Mower County, Minn., 67 Units
 
Wind
 
2008
 
101

 (c)
Nobles-Nobles County, Minn., 134 Units
 
Wind
 
2010
 
201

 (c)
Pleasant Valley-Mower County, Minn., 100 Units
 
Wind
 
2015
 
196

 (c)
 
 
 
 
Total
 
7,319

 
(a) 
Based on NSP-Minnesota’s ownership of 59 percent.
(b) 
Refuse-derived fuel is made from municipal solid waste.
(c) 
This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.  Therefore, the on-demand net dependable capacity is zero.

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NSP-Wisconsin

Station, Location and Unit
 
Fuel
 
Installed
 
Summer 2017
Net Dependable
Capability (MW)
 
Steam:
 
 
 
 
 
 
 
Bay Front-Ashland, Wis., 3 Units
 
Coal/Wood/Natural Gas
 
1948-1956
 
56

 
French Island-La Crosse, Wis., 2 Units
 
Wood/Refuse-derived fuel
 
1940-1948
 
16

(a) 
Combustion Turbine:
 
 
 
 
 
 
 
Flambeau Station-Park Falls, Wis., 1 Unit
 
Natural Gas
 
1969
 

(b) 
French Island-La Crosse, Wis., 2 Units
 
Oil
 
1974
 
122

 
Wheaton-Eau Claire, Wis., 5 Units
 
Natural Gas/Oil
 
1973
 
238

 
Hydro:
 
 
 
 
 
 
 
Various locations, 63 Units
 
Hydro
 
Various
 
135

 
 
 
 
 
Total
 
567

 
(a) 
Refuse-derived fuel is made from municipal solid waste.
(b) 
Flambeau Station was retired on Dec. 31, 2017.
PSCo

Station, Location and Unit
 
Fuel
 
Installed
 
Summer 2017
Net Dependable
Capability (MW)
 
Steam:
 
 
 
 
 
 
 
Comanche-Pueblo, Colo.
 
 
 
 
 
 
 
Unit 1
 
Coal
 
1973
 
325

 
Unit 2
 
Coal
 
1975
 
335

 
Unit 3
 
Coal
 
2010
 
500

 (b)
Craig-Craig, Colo., 2 Units
 
Coal
 
1979-1980
 
83

 (c)
Hayden-Hayden, Colo., 2 Units
 
Coal
 
1965-1976
 
233

 (d)
Pawnee-Brush, Colo., 1 Unit
 
Coal
 
1981
 
505

 
Valmont-Boulder, Colo., 1 Unit
 
Coal
 
1964
 

 (e)
Combustion Turbine:
 
 
 
 
 
 
 
Blue Spruce-Aurora, Colo., 2 Units
 
Natural Gas
 
2003
 
264

 
Cherokee-Denver, Colo., 1 Unit
 
Natural Gas
 
1968
 
310

 (a)
Cherokee-Denver, Colo., 3 Units
 
Natural Gas
 
2015
 
576

 
Fort St. Vrain-Platteville, Colo., 6 Units
 
Natural Gas
 
1972-2009
 
968

 
Rocky Mountain-Keenesburg, Colo., 3 Units
 
Natural Gas
 
2004
 
580

 
Various locations, 6 Units
 
Natural Gas
 
Various
 
171

 
Hydro:
 
 
 
 
 
 
 
Cabin Creek-Georgetown, Colo.
 
 
 
 
 
 
 
Pumped Storage, 2 Units
 
Hydro
 
1967
 
210

 
Various locations, 9 Units
 
Hydro
 
Various