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Section 1: 10-K (10-K)

XCEL 12.31.2013 10-K

 

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, 2013
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
 
New York Stock Exchange
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.  ý Yes  o 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.  o Yes  ý 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.  ý Yes  o 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).  ý Yes  o 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  ý Large accelerated filer  o Accelerated filer  o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller Reporting Company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  o Yes ý No
As of June 30, 2013, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $14,093,360,676 and there were 497,295,719 shares of common stock outstanding.
As of February 17, 2014, there were 498,288,164 shares of common stock outstanding, $2.50 par value.
DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2014 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.
 



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 —
 
 

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Table of Contents

PART I

Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Cheyenne
Cheyenne Light, Fuel and Power Company
Eloigne
Eloigne Company
NCE
New Century Energies, Inc.
NMC
Nuclear Management Company, LLC
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
PSCo
Public Service Company of Colorado
PSRI
P.S.R. Investments, Inc.
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
 
 
Federal and State Regulatory Agencies
ASLB
Atomic Safety and Licensing Board
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
DOI
United States Department of the Interior
DOT
United States Department of Transportation
EPA
United States Environmental Protection Agency
FERC
Federal Energy Regulatory Commission
IRS
Internal Revenue Service
MPCA
Minnesota Pollution Control Agency
MPSC
Michigan Public Service Commission
MPUC
Minnesota Public Utilities Commission
NDPSC
North Dakota Public Service Commission
NERC
North American Electric Reliability Corporation
NMAG
New Mexico Attorney General
NMPRC
New Mexico Public Regulation Commission
NRC
Nuclear Regulatory Commission
PNM
Public Service Company of New Mexico
PSCW
Public Service Commission of Wisconsin
PUCT
Public Utility Commission of Texas
SDPUC
South Dakota Public Utilities Commission
SEC
Securities and Exchange Commission
WDNR
Wisconsin Department of Natural Resources
 
 

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Electric, Purchased Gas and Resource Adjustment Clauses
CIP
Conservation improvement program
DCRF
Distribution cost recovery factor
DRC
Deferred renewable cost rider
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)
EPU
Extended power uprate
ERP
Electric resource plan
FCA
Fuel clause adjustment
FPPCAC
Fuel and purchased power cost adjustment clause
GAP
Gas affordability program
GCA
Gas cost adjustment
OATT
Open access transmission tariff
PCCA
Purchased capacity cost adjustment
PCRF
Power cost recovery factor (recovers the costs of certain purchased power costs)
PGA
Purchased gas adjustment
PSIA
Pipeline system integrity adjustment
QSP
Quality of service plan
RDF
Renewable development fund
RES
Renewable energy standard (recovers the costs of new renewable generation)
RESA
Renewable energy standard adjustment
SCA
Steam cost adjustment
SEP
State energy policy
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)
 
 
Other Terms and Abbreviations
AFUDC
Allowance for funds used during construction
ALJ
Administrative law judge
APBO
Accumulated postretirement benefit obligation
ARO
Asset retirement obligation
ASU
FASB Accounting Standards Update
BART
Best available retrofit technology
CAA
Clean Air Act
CACJA
Clean Air Clean Jobs Act
CAIR
Clean Air Interstate Rule
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
CO2
Carbon dioxide
COLI
Corporate owned life insurance
CON
Certificate of need
CP
Coincident peak
CPCN
Certificate of public convenience and necessity
CSAPR
Cross-State Air Pollution Rule

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CWIP
Construction work in progress
EEI
Edison Electric Institute
EGU
Electric generating unit
EPS
Earnings per share
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
HTY
Historic test year
IFRS
International Financial Reporting Standards
LCM
Life cycle management
LLW
Low-level radioactive waste
LNG
Liquefied natural gas
MACT
Maximum achievable control technology
MGP
Manufactured gas plant
MISO
Midcontinent Independent Transmission System Operator, Inc.
Moody’s
Moody’s Investor Services
MVP
Multi-value project
Native load
Customer demand of retail and wholesale customers that a utility has an obligation to serve
under statute or long-term contract
NEI
Nuclear Energy Institute
NOL
Net operating loss
NOx
Nitrogen oxide
NOV
Notice of violation
NSPS
New source performance standard
NTC
Notifications to construct
NYISO
New York Independent System Operator
O&M
Operating and maintenance
OCC
Office of Consumer Counsel
OCI
Other comprehensive income
PCB
Polychlorinated biphenyl
PFS
Private Fuel Storage, LLC
PJM
PJM Interconnection, LLC
PM
Particulate matter
PPA
Purchased power agreement
PRP
Potentially responsible party
PSP
Performance share plan
PTC
Production tax credit
PV
Photovoltaic
QF
Qualifying facilities
REC
Renewable energy credit
RFP
Request for proposal
ROE
Return on equity
RPS
Renewable portfolio standards
RSG
Revenue sufficiency guarantee
RSU
Restricted stock unit
RTO
Regional Transmission Organization
ROFR
Right of first refusal
SCR
Selective catalytic reduction

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Sharyland
Sharyland Distribution and Transmission Services, LLC
SIP
State implementation plan
SO2
Sulfur dioxide
SPP
Southwest Power Pool, Inc.
Standard & Poor’s
Standard & Poor’s Ratings Services
TSR
Total shareholder return
 
 
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 2013, Xcel Energy Inc.’s continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in eight states.  These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, and serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin.  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.

Xcel Energy’s corporate strategy focuses on four core objectives: driving operational excellence; providing options and solutions to customers; investing for the future; and enhancing engagement with employees, customers, shareholders, communities and policy makers. These core objectives are designed to provide an attractive total return to our investors, including long-term annual EPS growth of four to six percent and annual dividend increases of four to six percent.  Xcel Energy files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. Environmental leadership is a core priority for Xcel Energy and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value.

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.  The wholesale customers served by NSP-Minnesota comprised approximately four percent of its total KWh sold in 2013.  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 1.4 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 2013.  Although NSP-Minnesota’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Minnesota’s large commercial and industrial electric sales include the following industries:  petroleum, coal and food products.  For small commercial and industrial 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.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Company, which holds real estate; and NSP Nuclear Corporation, which owns NMC, an inactive company.


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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 253,000 customers and natural gas utility service to approximately 110,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2013.  Although NSP-Wisconsin’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Wisconsin’s large commercial and industrial electric sales include the following industries: food products, paper, allied products, oil and gas extraction and sand mining.  For small commercial and industrial customers, significant electric retail sales include the following industries:  grocery and dining establishments, educational services and food products.  Generally, NSP-Wisconsin’s earnings contribute approximately five percent to 10 percent of Xcel Energy’s consolidated net income.

The management of the electric production 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.

PSCo

PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado.  The wholesale customers served by PSCo comprised approximately 13 percent of its total KWh sold in 2013.  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 1.4 million customers and natural gas utility service to approximately 1.3 million customers.  All of PSCo’s retail electric operating revenues were derived from operations in Colorado during 2013.  Although PSCo’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large commercial and industrial electric sales include the following industries:  fabricated metal products, oil and gas extraction and communications. For small commercial and industrial customers, significant electric retail sales include the following industries: real estate and dining establishments. Generally, PSCo’s earnings contribute approximately 45 percent to 55 percent of Xcel Energy’s consolidated net income.

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 owns PSRI, which held certain former employees’ life insurance policies.  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.  The wholesale customers served by SPS comprised approximately 33 percent of its total KWh sold in 2013.  SPS provides electric utility service to approximately 383,000 retail customers in Texas and New Mexico.  Approximately 73 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2013.  Although SPS’ large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large commercial and industrial electric sales include the following industries:  oil and gas extraction, as well as petroleum and coal products.  For small commercial and industrial customers, significant electric retail sales include the following industries: oil and gas extraction and crop related agricultural industries. Generally, SPS’ earnings contribute approximately five percent to 15 percent of Xcel Energy’s consolidated net income.

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 the Cheyenne system near Cheyenne, Wyo.


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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.

Xcel Energy Inc.’s nonregulated subsidiary is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits.

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.

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 ERPs for meeting customers’ future energy needs.  The MPUC also certifies the need 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 with respect to 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 has been granted continued authorization from the FERC to make wholesale electric sales at market-based prices.  NSP-Minnesota is a transmission owning member of the MISO RTO.

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 — The CIP recovers the costs of programs that help customers save energy.  The CIP includes a comprehensive list of programs that benefit all customers including Saver’s Switch®, energy efficiency rebates and energy audits.
EIR — The EIR recovers the costs of environmental improvement projects.
RDF — The RDF allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies.
RES — The RES recovers the cost of new renewable generation.
SEP — The SEP recovers costs related to various energy policies approved by the Minnesota legislature.
TCR — The TCR recovers costs associated with new investments in electric transmission.
Infrastructure — The Infrastructure rider recovers costs associated with specific investments in generation and incremental property taxes.

The MPUC approved NSP-Minnesota’s request that the recovery of the costs associated with the EIR and RES be included in base rates in the Minnesota electric rate case in 2012.  No costs are being recovered through the EIR at this time.  NSP-Minnesota will continue to track PTCs associated with company-owned renewable projects and reflect the difference between the base rate amount and actual costs in the RES adjustment clause.

NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred costs of fuel, fuel related items and purchased energy.  NSP-Minnesota is permitted to recover these costs through FCA mechanisms approved by the regulators in each jurisdiction.  In general, capacity costs are not recovered through the FCA.  In addition, costs associated with MISO are generally recovered through either the FCA or base rates.


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Minnesota state law requires NSP-Minnesota to invest two percent of its state electric revenues in CIP.  NSP-Minnesota was in compliance with this standard in 2013 and expects to be in compliance in 2014.  These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

CIP Triennial Plan In October 2012, the DOC approved NSP-Minnesota’s 2013 through 2015 CIP Triennial Plan, which increases the savings goals and budgets over the previous plan. The plan sets an electric goal of annually saving the equivalent of 1.5 percent of sales (calculated on a historical three-year average, excluding opt-out customers) and an annual natural gas goal of saving 1.0 percent of sales.  The combined electric and gas budgets average $104.9 million per year over the 2013 through 2015 period.

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 2014, assuming normal weather, is listed below.
 
System Peak Demand (in MW)
 
2011
 
2012
 
2013
 
2014 Forecast
NSP System
9,792

 
9,475

 
9,524

 
9,212


The peak demand for the NSP System typically occurs in the summer. The 2013 uninterrupted system peak demand for the NSP System occurred on Aug. 26, 2013. The 2011 peak demand occurred on a day with extremely high temperatures and humidity, which resulted in the highest uninterrupted system peak demand since July 31, 2006. The 2012 peak demand occurred uninterrupted on a day with weather much closer to normal peak day conditions. The 2013 peak demand includes the effect of warmer weather partially offset by the impact of the termination of several firm wholesale contracts primarily at NSP-Wisconsin and also reflects the impact of two large commercial and industrial customers at NSP-Minnesota that have ceased operations. These two large customers represented 1.3 percent, 0.4 percent, and zero percent of NSP System sales in 2011, 2012, and 2013 respectively. The 2014 forecast assumes normal peak day weather.

Energy Sources and Related Transmission Initiatives

NSP-Minnesota expects to use existing power plants, power purchases, CIP 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 independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased.  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 In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contracts with MISO and regional transmission service providers to deliver power and energy to the NSP System.

NSP System Resource Plans — In March 2013, the MPUC approved NSP-Minnesota’s 2011-2025 Resource Plan and ordered a competitive acquisition process be conducted with the goal of adding approximately 500 MW of generation to the NSP System by 2019. Bid proposals were received in April 2013.

In September 2013, NSP-Minnesota recommended a self-build, 215 MW natural gas combustion turbine at the Black Dog site and a PPA with either Calpine’s Mankato combined cycle natural gas project or Invenergy’s Cannon Falls combustion turbine natural gas project. In October 2013, the DOC recommended the MPUC approve NSP-Minnesota’s proposal.

On Dec. 31, 2013, the ALJ recommended the MPUC select a combination of a 100 MW solar proposal by Geronimo Energy, LLC and capacity credits offered by Great River Energy.


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In January 2014, NSP-Minnesota filed exceptions to the ALJ’s report which supported NSP-Minnesota’s original proposal, reiterated its commitment to meeting the solar mandate and made the following points:

The ALJ’s report focused on meeting a portion of the solar mandate even though the docket was designed to meet our resource need;
Solar acquisition to meet the solar mandate should be conducted separately to encourage competition among solar developers;
One or more gas fueled plants should be selected because they are large enough to meet the range of reasonably expected need, are least cost, and comply with environmental regulations; and
Resource need uncertainty should be addressed through contract options to delay or cancel resources.

The MPUC is expected to make its selection determination in March 2014.

In the first half of 2013, NSP-Minnesota also issued a RFP for cost effective wind generation. In the summer of 2013, NSP-Minnesota filed a petition with the MPUC and the NDPSC seeking approval of four wind generation projects. The projects are as follows:

A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota, which is expected to be operational by October 2015;
A 150 MW ownership project for the Border Winds wind farm in North Dakota, which is expected to be operational by 2015;
A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and
A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota.

In October 2013, the four wind projects were approved by the MPUC. A NDPSC decision is anticipated in early 2014. The feasibility of the Border Winds and Pleasant Valley projects are also dependent on the finalization of estimated transmission costs, which MISO is expected to determine in the first half of 2014.

CapX2020 — In 2009, the MPUC granted CONs to construct one 230 KV electric transmission line and three 345 KV electric transmission lines as part of the CapX2020 project.  The estimated cost of the four major transmission projects is $1.9 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total investment.

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV transmission line
In May 2012, the MPUC issued a route permit for the Minnesota portion of the project and the PSCW approved a CPCN for the Wisconsin portion of the project.  Federal approval of the project was granted in January 2013.  All avenues of appeal for the grant of project permits have now been exhausted. In July 2013, the FERC denied a complaint filed by two citizen groups in March 2013 against the project. Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2015.

Monticello, Minn. to Fargo, N.D. 345 KV transmission line
In December 2011, the Monticello, Minn. to St. Cloud, Minn. portion of the Monticello, Minn. to Fargo, N.D. project was placed in service. The MPUC issued a route permit for the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. section in June 2011. Construction started on the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. segment in January 2012. The NDPSC granted a CPCN in January 2011 and a certificate of corridor compatibility and route permit for the portion of the line in North Dakota in September 2012.  In January 2013, construction started on the project in North Dakota. The project is expected to go fully into service in 2015, although segments will be placed in service as they are completed.

Brookings County, S.D. to Hampton, Minn. 345 KV transmission line
The MPUC route permit approvals for the Minnesota segments were obtained in 2010 and 2011.  In June 2011, the SDPUC approved a facility permit for the South Dakota segment. In December 2011, MISO granted the final approval of the project as a MVP. Construction started on the project in Minnesota in May 2012. The project is expected to go fully into service in 2015, although segments will be placed in service as they are completed.

Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line
The Bemidji, Minn. to Grand Rapids, Minn. line was placed in service in September 2012.


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Minnesota Solar Initiatives In May 2013, Minnesota’s Governor signed into law legislation requiring that 1.5 percent of a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. Of the 1.5 percent, 10 percent must come from systems sized less than 20 kilowatts. The legislation also authorized NSP-Minnesota to offer two new solar programs: a community solar garden program that will provide bill credits to participating solar garden subscribers and a new solar energy incentive program for solar energy systems equal to or less than 20 kilowatts that authorizes the spending of $5.0 million over five years for production incentive payments. NSP-Minnesota is continuing to work toward bringing solar energy generation on line in support of these solar programs and legislative requirements. NSP-Minnesota submitted its proposal for a community solar garden program to the MPUC in September 2013. The MPUC may approve, disapprove or modify the program. NSP-Minnesota is currently developing the new solar energy incentive program. The legislation also provides for an alternative tariff based on a distributed solar value or Value of Solar methodology. As required by the legislation, the DOC developed and filed a distributed solar value methodology with the MPUC on Jan. 31, 2014. The MPUC must approve, modify with the consent of the DOC or disapprove the methodology within 60 days. Once the methodology is approved, NSP-Minnesota may elect to file a Value of Solar tariff. NSP-Minnesota provided comments to the DOC on the methodology of this Value of Solar alternative tariff on Oct. 1 and Oct. 8, 2013.

On Jan. 24, 2014, the MPUC approved $42 million in grants for renewable energy generation and research projects in Minnesota. Xcel Energy will fund the grants through its renewable development fund.

Annual Automatic Adjustment (AAA) of Charges — In June 2013, the DOC proposed that the MPUC adopt a fuel clause incentive that would normalize FCA recovery using monthly patterns derived from averages of the prior three year period, setting and fixing this level during a rate case with no adjustment between rate cases. In August 2013, NSP-Minnesota filed comments opposing the DOC’s proposal including a demonstration of the random and volatile results the DOC’s fuel clause incentive proposal would have had if it were in place during the 2008-2012 period. Other utilities filed comments expressing similar concern with the DOC’s incentive proposal, further indicating no support for modification to operation of the fuel clause. Subsequently, the DOC requested the MPUC convene a stakeholder meeting to discuss general purpose and function of the FCA program. In October 2013, the MPUC allowed the DOC an opportunity to discuss current challenges in evaluating the prudence of fuel clause costs and the DOC recommended that the MPUC consider using a three-year average of fuel costs established in base rates. The DOC continues to independently meet with a stakeholder group to explore alternative options to their proposal. The 2012 AAA docket is pending.

Additionally, the DOC has indicated it will review prudence of replacement power costs associated with the Sherco Unit 3 outage event within the 2013 AAA docket.

Minneapolis, Minn. Franchise Agreement The franchise agreement with the City of Minneapolis expires Dec. 31, 2014. In June 2013, the Minneapolis City Council authorized (i) public hearings to be held regarding the establishment of a municipal electric and natural gas utility and (ii) a $250,000 study that will explore the various paths the City of Minneapolis could take to achieve its energy goals, including examination of potential utility partnerships, changes to how the City of Minneapolis uses energy utility franchise fees and the potential for municipalization of one or both energy utilities. In August 2013, following public hearings, the Minneapolis City Council elected not to conduct a special election to pursue forming a municipal utility. Results of the exploratory study authorized by the Minneapolis City Council are due in the first quarter of 2014.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant.  Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes.  The discharge and handling of such wastes 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.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact the operations of the nuclear generating plants.  The event at the nuclear generating plant in Fukushima, Japan in 2011 has resulted in additional regulation, which is expected to require additional capital expenditures and operating expenses.  The NRC created an internal task force that developed recommendations on requirements for immediate emergency preparedness and mitigating enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures and licensing processes.  The task force released its recommendations in July 2011 in a written report which recommended actions to enhance U.S. nuclear generating plant readiness to safely manage severe events.


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In March 2012, the NRC issued three orders which included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant.  The NRC also requested additional information including requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards and to assess the emergency preparedness staffing and communications capabilities at each plant.  Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance to meet the orders is expected to begin in the second quarter of 2015 with all units expected to be fully compliant by December 2016.

In June 2013, the NRC issued a revised order with regard to reliable hardened containment vents. The revised order added severe accident conditions under which the existing hardened vent which comes off of the wet portion of the containment needs to operate and requires a second hardened vent off of the dry portion of the containment. The revised order requires that any necessary changes to the existing vent are to be completed by the second quarter of the 2017 refueling outage at the Monticello plant and a new vent to be added by the second quarter of the 2019 refueling outage. Portions of the work that fall under the requests for additional information are expected to be completed by 2018.

NSP-Minnesota expects that complying with these external event requirements will cost approximately $50 to $60 million at the Monticello and Prairie Island plants. The majority of these costs are expected to be capital in nature and are included in NSP-Minnesota’s capital expenditure forecasts. NSP-Minnesota believes the costs associated with compliance would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

LLW Disposal LLW from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah.  If off-site LLW disposal facilities become unavailable, NSP-Minnesota has storage capacity available on-site at Prairie Island 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.

Nuclear Geologic Repository - Yucca Mountain Project
In 2002, the U.S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository.  In 2008, the DOE submitted an application to construct a deep geologic repository at this site to the NRC.  In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC approve the withdrawal of the application.  In June 2010, the ASLB issued a ruling that the DOE could not withdraw the Yucca Mountain application.  In September 2011, the NRC announced that it was evenly divided on whether to take the affirmative action of overturning or upholding the ASLB decision.  Because the NRC could not reach a decision, an order was issued instructing that information associated with the ASLB adjudication should be preserved.  The ASLB complied and the proceeding has been suspended.

The DOE’s decision and the resulting stoppage of the NRC’s review has prompted multiple legal challenges, including the DOE’s authority to stop the project and withdraw the application, the DOE’s authority to continue to collect the nuclear waste fund fee and the NRC’s authority to stop their review of the DOE’s application.  The utility industry, including Xcel Energy Inc. and NSP-Minnesota, are represented in these challenges by the NEI.

In August 2013, the D.C. Court of Appeals ordered the NRC to complete their review of the DOE’s application to construct the Yucca Mountain repository. In November 2013, the NRC complied by issuing an order to the NRC Staff to complete and publish a safety evaluation report on the proposed Yucca Mountain nuclear spent fuel and waste repository. The NRC also requested that the DOE prepare a supplemental environmental impact statement (EIS) so the NRC Staff can complete its review.

In November 2013, the U.S. Court of Appeals ordered the DOE to suspend the collection of the nuclear waste fund fee from nuclear utilities. The order required the DOE to recommend to Congress that the nuclear waste fund fee be set to zero. In January 2014, the DOE sent its court mandated proposal to adjust the current fee to zero. The Nuclear Waste Policy Act provides that a proposal by the Secretary of Energy to adjust the fee shall be effective after a period of 90 days of continuous session unless either House of Congress adopts a resolution disapproving the Secretary’s proposed adjustment.


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At the time that the DOE decided to stop the Yucca Mountain project and withdraw the application, the Secretary of Energy convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposal of used nuclear fuel.  In January 2012, the Blue Ribbon Commission report was issued.  The report provided numerous policy recommendations that are being considered by the Secretary of Energy.  In January 2013, the DOE provided its report to Congress relative to their plans to implement the Blue Ribbon Commission’s recommendations including the required legislative changes and authorizations.  The report also announced the Obama Administration’s intent to make a pilot consolidated interim storage facility available in 2021, a larger consolidated interim storage facility available in 2025 and a deep geologic repository available in 2048. See Note 13 and Note 14 to the consolidated financial statements for further discussion.

Nuclear Spent Fuel Storage
NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.  As of Dec. 31, 2013, there were 35 casks loaded and stored at the Prairie Island plant and 15 canisters loaded and stored at the Monticello plant. An additional 29 casks for Prairie Island and 15 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 Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.

PFS — The eight partners of PFS, including NSP-Minnesota, have agreed to dissolve the LLC.  PFS filed a letter with the NRC in December 2012 requesting to terminate the PFS license effective immediately. Subsequent to PFS requesting that the NRC terminate the PFS license, the NRC granted PFS a fee exemption for the 2013 license fees. Therefore, PFS has requested a 2014 fee exemption and is re-evaluating the future of the project. The efforts to dissolve the LLC are pending.

NRC Waste Confidence Decision (WCD) — In June 2012, the D.C. Circuit issued a ruling to vacate and remand the NRC’s WCD. The WCD assesses how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available.  The D.C. Circuit remanded the WCD to the NRC and directed it to prepare an EIS if there are significant impacts or an environmental assessment to support a finding of no significant impact.  In September 2012, the NRC directed the NRC Staff to develop a Generic Environmental Impact Statement (GEIS) and revised WCD rule on the temporary storage of spent nuclear fuel, and to issue the final GEIS and WCD rule by September 2014.

NSP-Minnesota does not believe that there will be an immediate impact on operations at the Prairie Island or Monticello nuclear generating plants.

See Notes 13 and 14 to the consolidated financial statements for further discussion regarding nuclear related items.

Nuclear Plant Power Uprates and Life Extension

Prairie Island Independent Spent Fuel Storage Installation (ISFSI) License Renewal — The current license to operate an ISFSI at Prairie Island was scheduled to expire in October 2013.  An application to renew the ISFSI license for an additional 40 years until 2053 was submitted by NSP-Minnesota to the NRC in October 2011.  As Prairie Island met the NRC’s criteria for timely renewal by submitting its ISFSI license renewal application more than two years in advance of the expiration of the ISFSI’s current license, it will be allowed to continue to operate under the current license until the NRC has rendered a decision on the license renewal application. In December 2012, the ASLB found that the Prairie Island Indian Community (PIIC) had standing to intervene and admitted three of the seven contentions put forward by the PIIC.  The ASLB will establish a schedule for the hearing which should be completed by mid-2014.

Monticello Nuclear Uprate Project NSP-Minnesota has filed with the MPUC two CONs related to changes at its Monticello nuclear generating plant. The first CON is related to state approval of a 20-year extension of the plant’s operating license, which also needed approval by the NRC. The second CON is related to the expansion of output capacity at the plant by 71 MW, or 12 percent, referred to as an EPU. The MPUC approved the first life extension CON for resource planning purposes in 2008. In 2006, the NRC approved the 20-year extension of Monticello’s operating license through 2030. The MPUC approved the second CON for EPU in 2008, and the NRC approved an EPU license amendment for the plant in December 2013.

NSP-Minnesota prepared for the upgrading and replacement of equipment at the plant to support an extended license period through a capital program known as LCM. Since the EPU project design also affected equipment needs and modifications at the plant, the LCM and EPU projects were integrated from an implementation standpoint to leverage project planning and efficiency.


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The plant life extension CON dealt mainly with the need for additional on-site storage of spent nuclear fuel, pending resolution of the longer-term federal issues with permanent fuel storage. The economic modeling for the life extension CON included underlying assumptions regarding future capital requirements, but the scope of the life extension CON proceeding did not specifically include discussion or request approval of capital investment for LCM work.

The EPU project CON dealt mainly with a resource planning proposal to expand output capacity at the plant and was planned to occur with the LCM project. The MPUC approval of the EPU CON authorized the resource need for additional capacity but did not include approval of a total project cost estimate. However, the modeling assumptions that combined EPU and LCM work were estimated to be $320 million in NSP-Minnesota’s internal models. Estimated capital expenditures for the EPU portion of the integrated project were discussed in the EPU CON filing, and at the time such capital expenditures were estimated at approximately $133 million based on an allocation method.

In July 2013, NSP-Minnesota completed the Monticello 20-year life extension and EPU projects. Final costs for the integrated LCM/EPU project were approximately $665 million, excluding possible reductions from the results of ongoing vendor negotiations. Of that total cost amount, NSP-Minnesota estimated that approximately $146 million related to EPU capital work and $519 million related to LCM capital work. This cost level for the EPU work completed exceeded the CON estimate by approximately 10 percent. NSP-Minnesota believes that the LCM/EPU costs, while substantially higher than the preliminary estimates assumed at the time of the EPU CON, were reasonable and prudently incurred to allow for safe and reliable operations of the plant until 2030. NSP-Minnesota asserts that had it known of the higher costs at any earlier date, it would still have made economic sense to complete the project. NSP-Minnesota also believes that even at the higher cost level, the total capital investment made to prepare the Monticello plant for another 20 years of operation provides customers with a highly reliable, cost-effective carbon free generation source.

With the approval of the NRC EPU license amendment, the Monticello plant began testing ascension to higher power levels in December 2013. A second NRC license amendment (Maximum Extended Load Line Limit Analysis Plus, or MELLLA+) is also needed to proceed to full uprate capacity, for final approval of fuel configuration and utilization under full uprate conditions. NRC approval of this complementary MELLLA+ fuel license amendment, which includes a plant safety analysis allowing for greater operational flexibility, is anticipated to be received in the first half of 2014.

The method and timing of rate recovery of the costs associated with the Monticello life extension and EPU construction projects were included as part of the 2013 electric rate case and 2014 electric rate case filed in November 2013. The project costs will be subject to a prudence review by the MPUC coincident with the 2014 electric rate case, as discussed below.

In the 2013 Minnesota electric rate case final order, the MPUC initiated an investigation to determine whether the costs in excess of those included in the CON for NSP-Minnesota’s Monticello LCM/EPU project were prudent. In October 2013, NSP-Minnesota filed a summary report and witness testimony to further support the change in and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors; (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendor’s ability to attract and retain experienced workers; and (3) additional NRC licensing related requests over the five-plus year application process. The prudence investigation is currently scheduled to conclude in the fourth quarter of 2014.

In NSP-Wisconsin’s recent rate case for 2014 rates, the PSCW ordered NSP-Wisconsin to defer cost recovery of $4.1 million, the portion of the interchange agreement amounts from NSP-Minnesota relating to the Monticello EPU project costs until the MPUC completes its prudence review.


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Energy Source Statistics
 
Year Ended Dec. 31
 
2013
 
2012
 
2011
NSP System
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal
15,844

 
36
%
 
16,023

 
35
%
 
20,131

 
44
%
Nuclear
12,161

 
28

 
13,231

 
29

 
13,332

 
29

Natural Gas
5,550

 
13

 
6,200

 
13

 
3,016

 
7

Wind (a)
5,481

 
13

 
5,443

 
12

 
4,312

 
9

Hydroelectric
3,223

 
7

 
3,193

 
7

 
3,444

 
8

Other (b)
1,323

 
3

 
1,617

 
4

 
1,453

 
3

Total
43,582

 
100
%
 
45,707

 
100
%
 
45,688

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
29,249

 
67
%
 
31,365

 
69
%
 
31,668

 
69
%
Purchased generation
14,333

 
33

 
14,342

 
31

 
14,020

 
31

Total
43,582

 
100
%
 
45,707

 
100
%
 
45,688

 
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 0.008, 0.006, and 0.003 net million KWh for 2013, 2012, and 2011, 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
 
2013
 
$
2.20

 
49
%
 
$
0.95

 
40
%
 
$
5.08

 
11
%
 
$
2.03

2012
 
2.13

 
47

 
0.90

 
42

 
4.21

 
11

 
1.88

2011
 
2.06

 
55

 
0.89

 
40

 
6.56

 
5

 
1.82

(a) 
Includes refuse-derived fuel and wood.

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

Fuel Sources

Coal — The NSP System normally maintains approximately 41 days of coal inventory.  Coal supply inventories at Dec. 31, 2013 and 2012 were approximately 34 and 39 days usage, respectively.  NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana.  During 2013 and 2012, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.3 million tons and 7.2 million tons, respectively.  The estimated coal requirements for 2014 are approximately 9.2 million tons. The coal requirements estimated for 2014 are higher primarily due to Sherco Unit 3 being placed back in service.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 94 percent of their estimated coal requirements in 2014, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years.  Remaining requirements will be filled through the procurement process or over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2014 and 2015.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.


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Nuclear — To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication.  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 2018 and approximately 67 percent of the requirements for 2019 through 2026.
Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 57 percent of the requirements for 2022 through 2026.
Current enrichment service contracts cover 100 percent of the requirements through 2024 and approximately 48 percent of the requirements for 2025 through 2026.

Fabrication services for Monticello and Prairie Island are 100 percent committed through 2027 and 2019, respectively. 

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 spot market price volatility will remain due to index-based pricing structures contained in certain supply contracts.

Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas supplies and associated transportation and storage services for power plants are procured under contracts with various terms 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 pricing that is tied to various natural gas indices.  Most transportation contract pricing is based on FERC approved transportation tariff rates. These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  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, 2013 and 2012, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $389 million and $384 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2014 to 2028.

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, 2013, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18 percent and 8.89 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively. Renewable energy comprised 22.9 percent and 22.4 percent of the NSP System’s total owned and purchased energy for 2013 and 2012, respectively.  Wind energy comprised 12.6 percent and 11.9 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively.  Hydroelectric energy comprised 7.4 percent and 7.0 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively.  Biomass and solar power comprised approximately 3.0 percent and 3.5 percent of the total owned and purchased energy on the NSP System for 2013 and 2012, respectively.

The NSP System also offers customer-focused renewable energy initiatives.  Windsource®, one of the nation’s largest voluntary renewable energy programs, allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources.  In 2013, the number of customers increased to approximately 37,000 from 24,000 in 2012. Windsource MWh sales declined slightly due to the loss of a large commercial participant from approximately 184,000 MWh in 2012 to 181,000 MWh in 2013. 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 679 PV systems with approximately 7.3 MW of aggregate capacity and over 561 PV systems with approximately 6.3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2013 and 2012, respectively.


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Wind  The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Southwestern Minnesota. The NSP System currently has more than 100 of these agreements in place, with facilities ranging in size from under one MW to more than 200 MW. In October 2013, the MPUC approved four new projects, which are anticipated to provide up to 750 MW of capacity, including two projects totaling 350 MW that will be owned by NSP-Minnesota.   Two of the projects, the Pleasant Valley wind farm in Minnesota and the Border Winds wind farm in North Dakota are expected to be operational by 2015. In addition to receiving purchased wind energy under these agreements, the NSP System also 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 $41 for 2013 and 2012.  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 2013 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2013.

The NSP System also owns and operates two wind farms.  The 101 MW Grand Meadow Wind Farm and the 201 MW Nobles Wind Farm began generating electricity in 2008 and 2010, respectively.  Collectively, the NSP System had approximately 1,870 MW of wind energy on its system at the end of 2013 and 2012. With the new projects, the NSP System is anticipated to have approximately 2,600 MW of wind power.

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 274 MW of capacity.  For 2013, there were nine PPAs in place which provided approximately 37 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 Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy-related products.  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 with respect to its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce.  NSP-Wisconsin and NSP-Minnesota have been granted continued joint authorization from the FERC to make wholesale electric sales at market-based prices. NSP-Wisconsin is a transmission owning member of the MISO RTO.

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.

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-collection or over-collection 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 after an opportunity for a hearing. 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 for a calendar year may not be recovered if the utility earnings for that year exceed the authorized ROE.

NSP-Wisconsin’s wholesale electric rate schedules included a FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.  However, as of Jan. 1, 2013, NSP-Wisconsin no longer served any wholesale municipal electric customers. Rates for wholesale municipal services provided in 2012 were subject to a final true-up, which was completed in 2013.


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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-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

2013 Electric Fuel Cost Recovery NSP-Wisconsin’s electric fuel costs for 2013 exceeded the levels authorized in Wisconsin retail rates, and were outside the two percent annual tolerance band established by the PSCW pursuant to the Wisconsin fuel cost recovery rules. Extended outages at two base load generation plants and higher than forecast prices in the MISO market were the primary causes of higher electric fuel costs. Rate recovery of the deferred amount is contingent on review and approval by the PSCW after opportunity for a hearing, and the earnings test based on NSP-Wisconsin’s 2013 authorized ROE of 10.4 percent. NSP-Wisconsin has reviewed its 2013 fuel cost under-recovery, and has completed the earnings test, and has determined that it would be ineligible for rate recovery of any 2013 deferred fuel costs. Accordingly, NSP-Wisconsin has expensed all 2013 fuel costs.

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. In 2013, NSP-Wisconsin was allocated approximately $8.3 million of the statewide program costs. 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 CapX2020 CPCN — The PSCW issued a CPCN for the Wisconsin portion of the Hampton, Minn. to La Crosse, Wis. project in May 2012. The Wisconsin route is approximately 50 miles of new transmission line with an estimated cost of $211 million. Construction on the Wisconsin terminus of the line, the Briggs Road Substation, began in mid-2013 and construction on the Wisconsin portion of the line is anticipated to begin in mid-2014. The line is expected to go into service in 2015.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line  In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, also known as the Badger Coulee line, would run between 159 and 182 miles, and cost between $514 and $552 million, depending upon the route ultimately approved by the PSCW. NSP-Wisconsin’s share of the investment is estimated to be between $230 and $247 million. The cost estimates are based on a projected 2018 in-service year. In December 2011, MISO determined the line to be an MVP project, and as such, eligible for cost sharing under MISO’s MVP tariff.

In November 2013, the PSCW found the application to be incomplete. A finding of incompleteness is a typical step for large transmission projects before the PSCW. In February 2014, NSP-Wisconsin and ATC submitted additional information in response to the PSCW’s determination. The PSCW is expected to issue a decision on the CPCN application in the first half of 2015. If approved, NSP-Wisconsin and ATC anticipate beginning construction on the line in mid-2016, with completion by late-2018.

Fuel Supply and Costs

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See NSP-Minnesota Fuel 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 is regulated by the FERC with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.


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

ECA — The ECA recovers fuel and purchased power costs.  Short-term sales margins are shared with retail customers through the ECA.  The ECA is revised quarterly.
PCCA — The PCCA recovers purchased capacity payments.
SCA — The 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 annually in January, as well as on an interim basis to coincide with changes in fuel costs.
DSMCA — The DSMCA recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy savings goals.
RESA — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of two percent of the customer’s total bill.
Wind Energy Service — Wind Energy Service is a premium service for those customers who voluntarily choose to pay an additional charge to increase the level of renewable resource generation used to meet the customer’s load requirements.
TCA — The TCA recovers transmission plant revenue requirements and allows for a return on CWIP outside of rate cases.

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 have agreed to 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.

QSP Requirements The CPUC established an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service. PSCo regularly monitors and records, as necessary, an estimated customer refund obligation under the QSP. PSCo files its proposed rate adjustment annually under the QSP. The CPUC conducts proceedings to review and approve these rate adjustments annually. In 2013, the CPUC extended the terms of the current QSP through the end of 2015.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2014, assuming normal weather, is listed below.
 
System Peak Demand (in MW)
 
2011
 
2012
 
2013
 
2014 Forecast
PSCo
6,896

 
6,689

 
6,678

 
6,459


The peak demand for PSCo’s system typically occurs in the summer.  The 2013 uninterrupted system peak demand for PSCo occurred on June 27, 2013. Comanche Unit 3 was off line, which increased PSCo’s system load by approximately 260 MW for the backup power provided by PSCo to the joint owners.  The forecasted 2014 system peak is lower than the 2013 peak, primarily due to the assumption that Comanche Unit 3 will be on line at the time of the peak and excludes the demand for the backup power supplied in 2013.

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 independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased. PSCo 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 In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver power and energy to PSCo’s customers.


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Colorado 2011 ERP and 2013 All-Source Solicitation In March 2013, PSCo issued an All-Source RFP for 250 MW of generation by the end of 2018. PSCo also issued a separate wind RFP for PPAs only.

The CPUC provided final approval to PSCo's plan in December 2013, which includes the following:

The addition of 450 MW of wind generation PPAs. This additional wind would bring the installed capacity on PSCo’s system in Colorado to 2,650 MW;
The addition of 170 MW of utility-scale solar generation PPAs. PSCo currently has about 80 MW of utility-scale solar and approximately 188 MW of customer-sited solar generation;
The addition of 317 MW of natural gas fired generation PPAs, which would come from existing power plants that previously supplied PSCo, but at reduced prices;
Accelerated retirement of the 109 MW, coal-fired Unit 4 at the Arapahoe generating station, which occurred at the end of 2013;
Confirmation of the retirement of the 45 MW, coal-fired Unit 3 at the Arapahoe generating station, which occurred at the end of 2013; and
The continued operation of Cherokee generating station’s Unit 4 as a natural gas facility after 2017.

In addition, PSCo continues to execute on the remaining aspects of CACJA compliance including the construction of a new natural gas fired combined cycle unit at Cherokee generating station and the addition of emissions controls at the Pawnee and Hayden stations. PSCo also expects to retire the Cherokee Unit 3 and Valmont Unit 5 coal-fired power plants by the end of 2015 and 2017, respectively.

Boulder, Colo. Municipalization Exploration PSCo’s franchise agreement with the City of Boulder expired on Dec. 31, 2010. In November 2010, the citizens of Boulder voted to impose an occupational tax to replace franchise fee revenues that would terminate when the franchise agreement terminated. In November 2011, two ballot measures were passed by the citizens of Boulder.  The first measure increased the occupation tax to raise an additional $1.9 million annually for funding the exploration costs of forming a municipal utility and acquiring the PSCo electric distribution system in Boulder.  The second measure authorized the formation and operation of a municipal light and power utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage.

Boulder Staff have performed a feasibility study on municipalization and in July 2013, recommended that Boulder create its own electric utility. In August 2013, the Boulder City Council voted to authorize the acquisition of PSCo’s transmission and distribution system in and near Boulder. On Jan. 6, 2014, Boulder sent PSCo a Notice of Intent to Acquire (NOIA) for PSCo’s transmission, distribution and property assets within an area that includes Boulder and certain areas outside city limits. The NOIA is a legal prerequisite to the filing of an eminent domain proceeding in Colorado courts. However, sending the NOIA does not require Boulder to move forward with a condemnation case.

Boulder’s municipalization plan assumes that Boulder will acquire through condemnation PSCo facilities (and customers currently served from these PSCo facilities) that are located outside Boulder’s incorporated limits. PSCo petitioned the CPUC for a declaratory ruling that Boulder cannot serve PSCo’s customers outside Boulder’s city limits without obtaining a CPCN from the CPUC. The CPUC declared that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine what facilities need to be constructed to ensure reliable service. The CPUC stated it believes that the cost of all new facilities must be paid by Boulder. The CPUC declared that it should make its determinations prior to any eminent domain actions. On Jan. 15, 2014, Boulder appealed this ruling to Boulder District Court.

If Boulder commences an eminent domain proceeding, PSCo will seek to obtain full compensation for the business and its associated property taken by Boulder, as well as for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the FERC.

RES Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales are supplied by renewable energy by 2020 and includes a distributed generation standard.  The CPUC has approved PSCo’s 2012 and 2013 RES compliance plan to acquire up to 30 MW of customer-sited solar projects each year and up to 9 MW of community solar garden projects, which PSCo met in both 2012 and 2013.  The CPUC also approved moving solely to a pay-for-performance basis under the Solar*Rewards distributed solar generation program, which PSCo implemented in 2012.  Based on CPUC approval, PSCo implemented a solar gardens program called Solar*Rewards Community, which will allow customers to join together to own interests in a common solar facility and receive a credit related to their share of the solar garden’s electric production on their electric bill.  See Renewable Energy Sources for further discussion.

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In July 2013, PSCo filed its 2014 RES compliance plan which included continuing both the Solar*Rewards and Solar*Rewards Community programs, maintaining approximately the same capacity expected to be installed in 2013. PSCo also proposed to show in aggregate the system costs that are not avoided by distributed solar generation, which PSCo has defined as a “net metering incentive.” In December 2013, parties including the OCC filed answer testimony supporting PSCo’s net metering proposal. However, rooftop solar advocates opposed it and also argued for higher solar installation levels and a slower reduction in incentives over time. Hearings are anticipated later in 2014 with a decision anticipated in the third quarter of 2014.

Steam System Package Boilers and Regulatory Plan In December 2012, PSCo filed for a CPCN to construct two packaged boilers for its steam utility.  The application also sought approval for PSCo’s regulatory plan affecting rates for natural gas and steam services effective after the boilers have been placed in service.  The proposed regulatory plan would combine the gas and steam revenue requirements for purposes of setting rates for retail gas and steam customers beginning January 2016.

In December 2013, the CPUC denied the application. The regulatory plan was designed to minimize customer attrition and the CPUC suggested that PSCo survey all steam customers in order to ensure that the boilers are appropriately sized before refiling.

Energy Source Statistics
 
Year Ended Dec. 31
 
2013
 
2012
 
2011
PSCo
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal
19,647

 
56
%
 
21,367

 
59
%
 
22,065

 
61
%
Natural Gas
7,565

 
22

 
7,930

 
22

 
8,896

 
24

Wind (a)
6,750

 
19

 
5,752

 
16

 
4,518

 
12

Hydroelectric
655

 
2

 
590

 
2

 
681

 
2

Other (b)
250

 
1

 
263

 
1

 
324

 
1

Total
34,867

 
100
%
 
35,902

 
100
%
 
36,484

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
22,873

 
66
%
 
23,766

 
66
%
 
23,743

 
65
%
Purchased generation
11,994

 
34

 
12,136

 
34

 
12,741

 
35

Total
34,867

 
100
%
 
35,902

 
100
%
 
36,484

 
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) 
Includes energy from other sources, including nuclear, solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, and was approximately 0.172, 0.133, and 0.137 net million KWh for 2013, 2012, and 2011, 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
PSCo Generating Plants
 
Cost
 
Percent
 
Cost
 
Percent
 
2013
 
$
1.84

 
80
%
 
$
4.86

 
20
%
 
$
2.45

2012
 
1.77

 
78

 
4.25

 
22

 
2.31

2011
 
1.77

 
76

 
4.98

 
24

 
2.54


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

Fuel Sources

Coal  PSCo normally maintains approximately 41 days of coal inventory.  Coal supply inventories at Dec. 31, 2013 and 2012 were approximately 41 and 46 days usage, respectively.  PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming.  During 2013 and 2012, PSCo’s coal requirements for existing plants were approximately 11.3 million tons.  The estimated coal requirements for 2014 are approximately 10.5 million tons.


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PSCo has contracted for coal supply to provide 100 percent of its estimated coal requirements in 2014, and a declining percentage of requirements in subsequent years.  PSCo’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years. 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 of its coal requirements in 2014 and 2015.  Coal delivery may be subject to short-term 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 and standby oil 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, the balance of natural gas supply contracts have 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.  These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  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, 2013, PSCo’s commitments related to gas supply contracts, which expire in various years from 2014 through 2023, were approximately $1.1 billion and commitments related to gas transportation and storage contracts, which expire in various years from 2014 through 2060, were approximately $723 million.  At Dec. 31, 2012, PSCo’s commitments related to gas supply contracts were approximately $1.1 billion and commitments related to gas transportation and storage contracts were approximately $754 million.

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

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, 2013, PSCo was in compliance with mandated RPS, which require generation from renewable resources of 12 percent of electric retail sales.  Renewable energy comprised 21.9 percent and 18.4 percent of PSCo’s total owned and purchased energy for 2013 and 2012, respectively.  Wind energy comprised 19.3 percent and 16.0 percent of PSCo’s total owned and purchased energy for 2013 and 2012, respectively.  Hydroelectric, biomass and solar power comprised approximately 2.6 percent and 2.4 percent of PSCo’s total owned and purchased energy for 2013 and 2012.

PSCo also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase a portion or all of their electricity from renewable sources.  In 2013, the number of customers increased to approximately 37,000 from 34,000 in 2012. Windsource MWh sales declined slightly, due in part to residential attrition, from approximately 201,000 MWh in 2012 to 197,000 MWh in 2013.  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 18,250 PV systems with approximately 188 MW of aggregate capacity and over 12,500 PV systems with approximately 138 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2013 and 2012, respectively.

Wind — PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Colorado.  PSCo currently has 19 of these agreements in place, with facilities ranging in size from two MW to over 300 MW.  In October 2013, the CPUC approved the addition of 450 MW of Colorado wind generation PPA’s. In addition to receiving purchased wind energy under these agreements, PSCo also 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 $45 and $47 for 2013 and 2012, respectively.  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 2013 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTC in 2013.

Additionally, PSCo owns and operates the 26 MW Ponnequin Wind Farm in northern Colorado, which has been in service since 1999. Collectively, PSCo had approximately 2,170 MW of wind energy on its system at the end of 2013 and 2012, respectively. With the new projects, PSCo is anticipated to have approximately 2,650 MW of wind power.


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Table of Contents

Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. See Item 7 for further discussion.

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.  Each municipality can deny SPS’ rate increases.  SPS can then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one hearing. The NMPRC also has jurisdiction over the issuance of securities.  SPS is regulated by the FERC with respect to 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. SPS has received authorization from the FERC 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 — The DCRF rider recovers distribution costs in Texas.
DRC — The DRC rider recovers deferred costs associated with renewable energy programs in New Mexico.
EECRF — The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.
EE rider — The EE rider recovers costs associated with providing energy efficiency programs in New Mexico.
FPPCAC — The FPPCAC adjusts monthly to recover the difference between the actual fuel and purchased power costs and the amount included in base rates of SPS’ New Mexico retail jurisdiction.
PCRF — The PCRF rider allows recovery of certain purchased power costs in Texas.
TCRF — The TCRF rider recovers transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas.

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.

NMPRC regulations require SPS to request authority to continue collecting its fuel and purchased power costs through a fuel adjustment clause every four years.  The NMPRC has granted SPS authority to use a fuel adjustment clause through November 2014.

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.


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Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2014, assuming normal weather, is listed below.
 
System Peak Demand (in MW)
 
2011
 
2012
 
2013
 
2014 Forecast
SPS
5,210

 
5,265

 
5,056

 
5,119


The peak demand for the SPS system typically occurs in the summer.  The 2013 uninterrupted system peak demand for SPS occurred on Aug. 6, 2013. The 2013 peak demand is down slightly from the previous year, when peak weather conditions were hotter.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases, DSM and new generation options to meet its net dependable system capacity requirements.

Purchased Power SPS has contracts to purchase power from other utilities and independent power producers.  Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated 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.

In November 2013, the NMPRC approved SPS' request to enter into three PPAs for approximately 700 MW of additional wind power. These contracts were entered into by SPS for economic purposes, not to meet the state mandated renewable energy portfolios.

Purchased Transmission Services SPS has contractual arrangements with SPP and regional transmission service providers, including PSCo, to deliver power and energy to its native load customers, which are retail and wholesale load obligations with terms of more than one year.

SPP Integrated Market (IM) SPP has operated a regional energy imbalance market since 2007. SPS has recovered related charges and revenues in its retail and wholesale rates. In 2012 and 2013, the FERC approved proposed revisions to the SPP tariff to allow SPP to operate a day ahead/real time energy and ancillary services market similar to the regional market operated by MISO. The SPP IM is scheduled to start operations on March 1, 2014. SPS has submitted filings to the FERC to modify its wholesale power sales contracts to allow recovery of SPP IM charges and revenues through the SPP wholesale FCA. SPS has also requested FERC approval to make sales to the SPP IM at market-based rates. FERC approval of the tariff and market based rates filings are pending. SPS has also filed changes to its retail tariffs in Texas and New Mexico to allow retail FCA treatment of SPP IM charges and revenues.

SPS Transmission NTCs — As a member of SPP, SPS accepts NTCs for transmission projects. These are typically a portfolio of transmission lines and electric substation projects.  SPS has accepted NTCs for several hundred miles of transmission lines and substations at an estimated capital cost of approximately $1.4 billion and will continue to review new NTCs for acceptance as they are issued. These projects generally span several years to plan, site, procure and develop.  Typical SPS capital spending for SPP NTC transmission projects is approximately $200 to $300 million per year, but may vary.  The NMPRC and the PUCT must approve the siting and routing of all SPP identified transmission line NTC projects that require permitting approval.  Projects identified through SPP NTCs may have costs allocated to other SPP members in accordance with the SPP open access transmission tariff.  Costs allocated to SPS are permissible for recovery through the NMPRC, the PUCT and the FERC processes.

TUCO Inc. (TUCO) to Woodward, Okla. 345 KV transmission line
The TUCO to Woodward District extra high voltage interchange is a 345 KV transmission line.  SPS is constructing the line to just inside the Oklahoma state line, and Oklahoma Gas and Electric Company (OGE) is building from there to Woodward, Okla. SPS’ estimated investment in the TUCO to Woodward line and substation is $185 million and is expected to be recovered from SPP members, including SPS, in accordance with the SPP OATT and the ratemaking process.  The PUCT approved SPS’ CCN to build the line in 2012. It is anticipated to be complete in mid-2014.

Hitchland substation to Woodward, Okla. 345 KV transmission line
The Hitchland substation to Woodward line is a 345 KV double circuit transmission line and associated substation facilities in the Oklahoma and Texas Panhandle.  SPS is building the first 30 miles and OGE is completing the line from there to Woodward, Okla. SPS’ estimated investment for the Hitchland to Woodward line and substation is $63 million and is expected to be recovered from SPP members in accordance with the SPP OATT and the ratemaking process. The line is anticipated to be complete in mid-2014.

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Table of Contents

Jones CCN In August 2011, the PUCT approved SPS’ request for a CCN to build a gas-fired combustion turbine generating unit at SPS’ existing Jones Station in Lubbock, Texas (Jones Unit 4).  In February 2012, the NMPRC approved the CCN with a projected cost of $118 million, inclusive of AFUDC.  Jones Unit 4 achieved commercial operation in May 2013 and added 168 MW of capacity to the SPS service territory.

SPS Resource Plans — SPS is required to develop and implement a renewable portfolio plan in which 10 percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2011, increasing to 15 percent in 2015.  SPS primarily fulfills its renewable portfolio requirements through the purchase of wind energy. SPS was granted a variance from the NMPRC to extend the time to implement a portion of the diversity requirements to 2015.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the United States. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future. CSAPR is discussed further at Note 13 to the consolidated financial statements — Environmental Contingencies.

Energy Source Statistics
 
Year Ended Dec. 31
 
2013
 
2012
 
2011
SPS
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal
14,184

 
49
%
 
14,005

 
49
%
 
14,818

 
48
%
Natural Gas
11,235

 
38

 
12,088

 
43

 
13,167

 
43

Wind (a)
3,507

 
12

 
2,103

 
7

 
2,386

 
8

Other (b)
167

 
1

 
177

 
1

 
409

 
1

Total
29,093

 
100
%
 
28,373

 
100
%
 
30,780

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
18,814

 
65
%
 
19,940

 
70
%
 
19,310

 
63
%
Purchased generation
10,279

 
35

 
8,433

 
30

 
11,470

 
37

Total
29,093

 
100
%
 
28,373

 
100
%
 
30,780

 
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) 
Includes energy from other sources, including nuclear, hydroelectric, solar, biomass, oil and refuse.  Distributed generation from the Solar*Rewards program is not included, was approximately 0.011, 0.008, and 0.006 net million KWh for 2013, 2012, and 2011, 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
 
2013
 
$
2.14

 
71
%
 
$
3.97

 
29
%
 
$
2.68

2012
 
1.87

 
67

 
2.99

 
33

 
2.24

2011
 
1.89

 
67

 
4.37

 
33

 
2.71


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 in 2016 and 2017 for the Harrington station and Tolk station, respectively.  As of Dec. 31, 2013 and 2012, coal inventories at SPS were approximately 42 and 40 days supply, respectively.  TUCO has coal agreements to supply 93 percent of SPS’ estimated coal requirements in 2014, and a declining percentage of the requirements in subsequent years.  SPS’ general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years.

Natural gas  SPS uses both firm and interruptible natural gas supply and standby oil 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 in various years from 2014 to 2033.  All of the natural gas supply contracts have 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 $21 million and $57 million and commitments related to gas transportation and storage contracts were approximately $201 million and $229 million at Dec. 31, 2013 and 2012, 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 both owned generating facilities and PPAs.  As of Dec. 31, 2013, SPS is in compliance with mandated RPS, which require generation from renewable resources of approximately four percent and 10 percent of Texas and New Mexico electric retail sales, respectively.  Renewable energy comprised 12.7 percent and 8.0 percent of SPS’ total owned and purchased energy for 2013 and 2012, respectively.  Wind energy comprised 12.1 percent and 7.4 percent of SPS’ total owned and purchased energy for 2013 and 2012, respectively.  Solar power comprised approximately 0.4 percent and 0.5 percent of SPS’ total owned and purchased energy for 2013 and 2012, respectively.

SPS also offers customer-focused renewable energy initiatives.  Windsource allows customers in New Mexico to purchase a portion or all of their electricity from renewable sources.  The number of Windsource participants dropped from approximately 1,000 in 2012 to 900 in 2013 due to residential attrition, while Windsource MWh sales remained consistent from approximately 4,400 MWh in 2012 to 4,400 MWh in 2013.  Additionally, to encourage the growth of solar energy on the system in New Mexico, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program.  Over 115 PV systems with approximately 7.6 MW of aggregate capacity and over 80 PV systems with approximately 4.5 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2013 and 2012, respectively.

Wind — SPS acquires its wind energy from long-term PPAs with wind farm owners, primarily located in the Texas Panhandle area of Texas and New Mexico. SPS currently has six of these agreements in place, with facilities ranging in size from under two MW to 161 MW for a total capacity greater than 600 MW. In 2013, the NMPRC approved three PPAs for approximately 700 MW of wind power. In addition to receiving purchased wind energy under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource requirements. The average cost per MWh of wind energy under the PPA and QF contracts was approximately $26 for each of 2013 and 2012. 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 2013 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2013. At the end of each of 2013 and 2012, SPS had over 1,000 MW of wind energy on its system. With these projects, SPS is anticipated to have approximately 1,800 MW of wind power.

Wholesale Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy 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.


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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, 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.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — The FERC issued Order 1000 in July 2011 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. In Order 1000, the FERC required utilities, including RTO’s such as MISO and SPP, to file compliance tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region. In addition, Order 1000 required that regions coordinate to develop interregional plans for transmission planning and cost allocation. A key provision of Order 1000 is a requirement that FERC-jurisdictional wholesale transmission tariffs exclude provisions that would grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area. Various parties have appealed Order 1000 final rules to the D.C. Circuit. NSP-Minnesota and NSP-Wisconsin are participating in the appeals in coordination with other MISO transmission owners and utilities who oppose certain aspects of the rules, including the ROFR prohibition. Briefs have been filed by parties challenging the final rules, by the FERC and by parties supporting the final rules. Oral arguments are scheduled March 20, 2014. The date for a Court ruling is uncertain.

The removal of a federal ROFR would eliminate rights that NSP-Minnesota, NSP-Wisconsin and SPS currently have under the MISO and SPP tariffs to build certain transmission projects within their footprints. The FERC required that the opportunity to build such projects would extend to competitive transmission developers. Compliance with Order 1000 for NSP-Minnesota and NSP-Wisconsin will occur through changes to the MISO tariff while compliance for SPS will occur through the SPP tariff. PSCo is not in an RTO and therefore is responsible for making its own Order 1000 compliance filings. MISO, SPP and PSCo all made their initial compliance filings to incorporate new provisions into their tariffs regarding regional planning and cost allocation. The FERC ruled on the initial regional compliance filings for MISO, SPP and PSCo, and directed further changes to fully address the requirements of Order 1000. Additional regional compliance filings have been submitted by MISO, SPP, PSCo and FERC action on these supplemental compliance filings is pending. Several parties, including Xcel Energy, also sought rehearing of the FERC orders requiring changes to the initial compliance filings. The rehearing requests are also pending FERC action.

Filings to address Order 1000 interregional planning and cost allocation requirements with other regions were made by PSCo, MISO and SPP in 2013. The filings are pending action by the FERC.

NSP-System
In 2012, Minnesota enacted legislation that preserves ROFR rights for Minnesota utilities at the state level. This legislation is similar to legislation previously passed in North Dakota and South Dakota. Wisconsin has not developed such legislation. The FERC’s initial order to address the regional requirements of Order 1000 required MISO to remove proposed tariff provisions that would have recognized state ROFR rights and allowed state regulators to select the developer of a transmission project. NSP-Minnesota, NSP-Wisconsin and other MISO transmission owners requested rehearing of this issue. The rehearing request is pending the FERC’s action. The FERC has accepted changes to MISO’s transmission cost allocation procedures that will protect the ROFR for projects needed for system reliability.

PSCo
Colorado does not have legislation protecting ROFR rights for incumbent utilities. PSCo submitted its compliance filing to address the regional planning and cost allocation requirements of Order 1000, proposing that PSCo would join the WestConnect region, a consortium of utilities in the Western Interconnection. In March 2013, the FERC issued its order on PSCo’s initial compliance filing and required a further compliance filing with additional tariff changes. In April 2013, PSCo and other WestConnect members requested rehearing on various aspects of the March 2013 order. PSCo and other WestConnect jurisdictional utilities made their additional compliance filings to address directives in the March 2013 order. The FERC is expected to rule in 2014 on the regional compliance filing and the requests for rehearing. WestConnect members, including PSCo, filed their Order 1000 interregional compliance filings in May 2013 and the filings are pending FERC action.


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SPS
In July 2013, the FERC issued its initial order on SPP’s Order 1000 regional compliance filing identifying several issues and requiring a further compliance filing by SPP. The FERC rejected SPP’s proposal to retain a ROFR for new transmission projects with operational voltages between 100 KV and 300 KV. Requests for rehearing of the FERC’s July 2013 order were filed and are pending FERC action. The SPP regional compliance filing to the July 2013 order was filed and is pending FERC action. The SPP interregional compliance filing was submitted and is also pending the FERC’s action. SPS believes that Texas statutes protect the ROFR of incumbent utilities operating outside of the Electric Reliability Council of Texas (ERCOT) to construct and own transmission interconnected to their systems, though this view is disputed by some parties. The State of New Mexico does not have legislation protecting ROFR rights for incumbent utilities.

Xcel Energy Services Inc. and NSP-Wisconsin vs. ATC (La Crosse, Wis. to Madison, Wis. Transmission Line) In February 2012, Xcel Energy Services Inc. and NSP-Wisconsin filed a complaint with the FERC concerning ownership of the proposed La Crosse, Wis. to Madison, Wis. 345 KV transmission line.  In July 2012, the FERC ruled favorably on Xcel Energy Services Inc.’s and NSP-Wisconsin’s complaint, ruling that the responsibilities to construct the La Crosse, Wis. to Madison, Wis. transmission line, also known as the Badger Coulee line, belong equally to NSP-Wisconsin and ATC.  In August 2012, ATC requested rehearing and requested that the FERC grant a stay of the ruling.  In September 2012, the FERC granted rehearing for purposes of further consideration but did not grant a stay. Thus, the July ruling remains in effect pending the FERC’s further ruling on rehearing.  In order to proceed with development of the project, the two companies are working together on routing and regulatory state issues pending FERC action on ATC’s request for rehearing. A joint CPCN application was filed with the PSCW in October 2013.

ATC vs. Xcel Energy Services Inc. and MISO (Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. Transmission Line)  In October 2012, ATC filed a complaint against MISO, Xcel Energy Services Inc., NSP-Minnesota and NSP-Wisconsin, alleging that, under the legal principles set forth in the July 2012 FERC ruling in the La Crosse, Wis. to Madison, Wis. transmission line complaint filed by Xcel Energy Services Inc. and NSP-Wisconsin against ATC, that the FERC should determine that MISO should have designated the Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. CapX2020 line and the La Crosse, Wis. to Madison, Wis. line as a single facility under the MISO Transmission Owners Agreement and Tariff.  Thus, ATC should have been designated as the owner of the La Crosse, Wis. to Madison, Wis. line portion of the purported single facility.  Xcel Energy filed an answer seeking dismissal of the ATC complaint in October 2012.  On Feb. 4, 2013, the FERC issued an order denying the ATC complaint.  The FERC found that MISO properly applied its planning process and that Hampton, Minn. to La Crosse, Wis. and the La Crosse, Wis. to Madison, Wis. lines are separate. ATC did not seek rehearing and therefore the FERC order is final and MISO’s prior ownership decisions stand, which brings this matter to a close.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature.  If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region.  MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to serve multiple purposes such as improved reliability, reduced congestion, transmission for renewable energy and load serving. Certain parties appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit). In June 2013, the Seventh Circuit upheld the FERC MVP tariff orders allocating MVP project costs regionally, but remanded the FERC decision to not apply the regional charge to transmission service transactions crossing into the PJM RTO. U.S. Supreme Court review of the Seventh Circuit decision has been requested and the response is pending. The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery.  Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities.  The transmission revenues received by the NSP System from MISO and the transmission charges paid to MISO associated with projects subject to regional cost allocation could be significant in future periods.

RSG Charges — The MISO tariff charges certain market participants a real-time RSG charge, designed to ensure that any generator scheduled or dispatched by MISO receives no less than its offer price for start-up, no-load and incremental energy. In August 2010, the FERC issued two orders relating to RSG charge exemptions and the allocation of the RSG costs among MISO participants. The FERC has allowed allocating a greater portion of the RSG costs related to resources committed for voltage and local reliability requirements to the market participants serving the loads that benefit from such commitments. Certain of the FERC’s orders remain pending on rehearing. An appeal to the D.C. Circuit has been held in abeyance, pending the FERC’s disposition of rehearing requests. If the FERC were to reverse or modify the prior orders on rehearing, the NSP system could be subject to additional RSG charges for prior periods. NSP-Minnesota is permitted to recover the RSG costs through FCA mechanisms. NSP-Wisconsin recovers RSG costs in its fuel and purchased energy recovery mechanism in Wisconsin and through its power supply cost recovery mechanism in Michigan.


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MISO ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against all FERC jurisdictional MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for RTO membership and being an independent transmission company), effective Nov. 12, 2013. In January 2014, Xcel Energy Services, Inc. filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO Transmission Owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO Transmission Owners’ motion to dismiss. The complaint is pending FERC action. The estimated impact of FERC granting the complaint could amount to a reduction of revenue of $11.7 million annually for NSP-Minnesota and NSP-Wisconsin. NSP-Minnesota and NSP-Wisconsin would seek to offset any reduction in wholesale revenues through increases in retail rates.

Electric Operating Statistics

Electric Sales Statistics
 
Year Ended Dec. 31
 
2013
 
2012
 
2011
Electric sales (Millions of KWh)
 
 
 
 
 
Residential
25,306

 
25,033

 
25,278

Large commercial and industrial
27,206

 
27,396

 
27,419

Small commercial and industrial
35,873

 
35,660

 
35,597

Public authorities and other
1,098

 
1,109

 
1,135

Total retail
89,483

 
89,198

 
89,429

Sales for resale
15,065

 
15,781

 
20,177

Total energy sold
104,548

 
104,979

 
109,606

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
2,965,717

 
2,940,024

 
2,919,660

Large commercial and industrial
1,132

 
1,147

 
1,129

Small commercial and industrial
422,553

 
419,618

 
415,755

Public authorities and other
67,998

 
68,510

 
69,350

Total retail
3,457,400

 
3,429,299

 
3,405,894

Wholesale
65

 
75

 
78

Total customers
3,457,465

 
3,429,374

 
3,405,972

 
 
 
 
 
 
Electric revenues (Thousands of Dollars)
 
 
 
 
 
Residential
$
2,906,208

 
$
2,713,575

 
$
2,712,340

Large commercial and industrial
1,694,720

 
1,534,728

 
1,616,596

Small commercial and industrial
3,248,586

 
3,023,154

 
3,025,416

Public authorities and other
138,126

 
130,538

 
129,826

Total retail
7,987,640

 
7,401,995

 
7,484,178

Wholesale
693,728

 
687,912

 
936,875

Other electric revenues
352,677

 
427,389

 
345,540

Total electric revenues
$
9,034,045

 
$
8,517,296

 
$
8,766,593

 
 
 
 
 
 
KWh sales per retail customer
25,882

 
26,011

 
26,257

Revenue per retail customer
$
2,310

 
$
2,158

 
$
2,197

Residential revenue per KWh

11.48
¢
 

10.84
¢
 

10.73
¢
Large commercial and industrial revenue per KWh
6.23

 
5.60

 
5.90

Small commercial and industrial revenue per KWh
9.06

 
8.48

 
8.50

Total retail revenue per KWh
8.93

 
8.30

 
8.37

Wholesale revenue per KWh
4.60

 
4.36

 
4.64


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Energy Source Statistics
 
Year Ended Dec. 31
 
2013
 
2012
 
2011
Xcel Energy
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
 
Millions of
KWh
 
Percent of
Generation
Coal
49,675

 
46
%
 
51,395

 
47
%
 
57,014

 
50
%
Natural Gas
24,350

 
23

 
26,218

 
24

 
25,080

 
22

Wind (a)
15,738

 
14

 
13,298

 
12

 
11,216

 
10

Nuclear
12,177

 
11

 
13,249

 
12

 
13,781

 
12

Hydroelectric
3,900

 
4

 
3,800

 
3

 
4,203

 
4

Other (b)
1,704

 
2

 
2,022

 
2

 
1,659

 
2

Total
107,544

 
100
%
 
109,982

 
100
%
 
112,953

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
Owned generation
70,936

 
66
%
 
75,071

 
68
%
 
74,722

 
66
%
Purchased generation
36,608

 
34

 
34,911

 
32

 
38,231

 
34

Total
107,544

 
100
%
 
109,982

 
100
%
 
112,953

 
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 0.198, 0.152, and 0.146 net million KWh for 2013, 2012 and 2011, respectively.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of the utility subsidiaries are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 2000 to 2013, average annual sales to the typical residential customer declined 17 percent and the typical small commercial and industrial customer declined 11 percent 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 Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (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. The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure if records are inadequate. This process could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations including: requiring use of automatic or remote-controlled shut-off valves; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $2 million per day for related violations. While Xcel Energy cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA rider.


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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.  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 767,636 MMBtu, which occurred on Jan. 21, 2013 and 732,135 MMBtu, which occurred on Jan. 19, 2012.

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 596,411 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 31 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 31 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.  Contract demand levels for the past five years are being reviewed by the MPUC.

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.

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:
2013
$
4.53

2012
4.41

2011
5.25



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NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2014 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, 2013, NSP-Minnesota was committed to approximately $356 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 28 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.

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 155,087 MMBtu, which occurred on Jan. 21, 2013, and 143,134 MMBtu, which occurred on Jan. 19, 2012.

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 132,591 MMBtu per day.  In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services.  These agreements provide storage for approximately 26 percent of winter natural gas requirements and 39 percent of peak day firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements.  These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 13 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-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 2013-2014 supply plan was approved by the PSCW in November 2013.

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.


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Table of Contents

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:
2013
$
4.51

2012
4.36

2011
5.18


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 2014 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, 2013, NSP-Wisconsin was committed to approximately $82 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 13 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 — The 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 — The DSMCA is a low-income energy assistance program.  The costs of this energy conservation and weatherization program are recovered through the gas DSMCA.
PSIA — Effective Jan. 1, 2012, the PSIA began to recover costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. Although PSCo had proposed to include the PSIA in base rates, instead the rider was extended through Dec. 31, 2015.

QSP Requirements — The CPUC established a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service. The CPUC conducts proceedings to review and approve the rate adjustment annually. In 2013, the CPUC extended the terms of the current QSP through the end of 2015.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation to be 1,952,939 MMBtu.  In addition, firm transportation customers hold 797,329 MMBtu of capacity for PSCo without supply backup.  Total firm delivery obligation for PSCo is 2,750,268 MMBtu per day.  The maximum daily deliveries for PSCo for firm and interruptible services were 1,865,207 MMBtu on Dec. 5, 2013 and 1,539,864 MMBtu on Dec. 19, 2012.


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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 1,822,939 MMBtu per day, which includes 859,514 MMBtu of natural gas held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 22,400 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:
2013
$
4.20

2012
4.28

2011
4.99


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, 2013, PSCo was committed to approximately $2.0 billion in such obligations under these contracts, which expire in various years from 2014 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 2013, PSCo purchased natural gas from approximately 40 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 DOT 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
 
2013
 
2012
 
2011
Natural gas deliveries (Thousands of MMBtu)
 
 
 
 
 
Residential
150,280

 
123,835

 
139,200

Commercial and industrial
92,849

 
77,848

 
86,788

Total retail
243,129

 
201,683

 
225,988

Transportation and other
125,057

 
116,611

 
117,654

Total deliveries
368,186

 
318,294

 
343,642

 
 
 
 
 
 
Number of customers at end of period
 
 
 
 
 
Residential
1,776,849

 
1,760,364

 
1,747,153

Commercial and industrial
154,646

 
154,158

 
153,911

Total retail
1,931,495

 
1,914,522

 
1,901,064

Transportation and other
6,320

 
5,789

 
5,395

Total customers
1,937,815

 
1,920,311

 
1,906,459

 
 
 
 
 
 
Natural gas revenues (Thousands of Dollars)
 
 
 
 
 
Residential
$
1,126,859

 
$
964,642

 
$
1,133,888

Commercial and industrial
586,548

 
488,644

 
601,298

Total retail
1,713,407

 
1,453,286

 
1,735,186

Transportation and other
91,272

 
84,088

 
76,740

Total natural gas revenues
$
1,804,679

 
$
1,537,374

 
$
1,811,926

 
 
 
 
 
 
MMBtu sales per retail customer
125.88

 
105.34

 
118.87

Revenue per retail customer
$
887

 
$
759

 
$
913

Residential revenue per MMBtu
7.50

 
7.79

 
8.15

Commercial and industrial revenue per MMBtu
6.32

 
6.28

 
6.93

Transportation and other revenue per MMBtu
0.73

 
0.72

 
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 and winter 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 remains a vertically integrated utility in all of its jurisdictions subject to traditional cost-of-service regulation by state public utilities commissions. Within this construct, 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 on-site solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them.


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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. 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. In addition, FERC Order 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. 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. 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. These competitive challenges continue to evolve over time. 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. Xcel Energy continues to evaluate policies, products and strategies to enable it to compete in the changing energy marketplace.

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. Xcel Energy strives to comply with all environmental regulations applicable to its operations. 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 future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. While environmental regulations related to climate change and clean energy continue to evolve, 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. Although the impact of these policies on Xcel Energy will depend on the specifics of state and federal policies, legislation, and regulation, we believe that, based on prior state commission practice, we 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. Xcel Energy adopted a methodology for calculating CO2 emissions based on the reporting protocols of The Climate Registry, a nonprofit organization that provides and compiles GHG emissions data from reporting entities. Starting in 2011, Xcel Energy began reporting GHG emissions to the EPA under the EPA’s mandatory GHG Reporting Program. Currently, EPA reporting rules do not address REC transactions. It is not clear whether future GHG reporting regulations could require reporting of CO2 emissions for REC transactions.

Based on The Climate Registry’s current reporting protocol, Xcel Energy estimated that its current electric generating portfolio, which includes owned coal- and gas-fired plants, emitted approximately 57.1 million and 59.2 million tons of CO2 in 2013 and 2012, respectively. Xcel Energy also estimated emissions associated with electricity purchased for resale to Xcel Energy customers from generation facilities owned by third parties. Xcel Energy estimates these non-owned facilities emitted approximately 14.1 million and 14.5 million tons of CO2 in 2013 and 2012, respectively. Estimated total CO2 emissions associated with service to Xcel Energy electric customers decreased by 2.5 million tons in 2013 compared to 2012. The decrease in emissions was associated with a decrease of 5.4 million MWh of generation since 2011. The average annual decrease in CO2 emissions since 2011 is approximately 3.6 million tons of CO2 per year.

CAPITAL SPENDING AND FINANCING

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


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EMPLOYEES

As of Dec. 31, 2013, Xcel Energy had 11,457 full-time employees and 124 part-time employees, of which 5,587 were covered under collective-bargaining agreements.  See Note 9 to the consolidated financial statements for further discussion.

EXECUTIVE OFFICERS

Benjamin G.S. Fowke III, 55, Chairman of the Board, President and Chief Executive Officer, Xcel Energy Inc., August 2011 to present. Previously, President and Chief Operating Officer, Xcel Energy Inc., August 2009 to August 2011; Executive Vice President and Chief Financial Officer, Xcel Energy Inc., December 2008 to August 2009; Vice President and Chief Financial Officer, Xcel Energy Inc., May 2004 to December 2008; Vice President, Chief Financial Officer and Treasurer, Xcel Energy Inc., October 2003 to May 2004; Vice President and Treasurer, Xcel Energy Inc., November 2002 to October 2003; and Vice President and Chief Financial Officer, Energy Markets Business Unit, Xcel Energy Services Inc., August 2000 to November 2002.

David L. Eves, 55, President, Director and Chief Executive Officer, PSCo, December 2009 to present.  Previously, President, Director and Chief Operating Officer, PSCo, November 2009 to December 2009; President and Director, SPS, December 2006 to November 2009; Chief Executive Officer, SPS, August 2006 to November 2009; Vice President of Resource Planning and Acquisition, Xcel Energy Services Inc., November 2002 to July 2006; and Managing Director, Resource Planning and Acquisition, Xcel Energy Services Inc., August 2000 to November 2002.

David T. Hudson, 53, President, Director and Chief Executive Officer, SPS, January 1, 2014 to present.  Previously, Director, Community Service & Economic Development, SPS, April 2011 to January 2014; Director, Strategic Planning, SPS, May 2008 to April 2011; and Director, Regulatory Administration, SPS, August 2000 to May 2008; Director, Electric Retail/Wholesale Services, SPS, May 1997 to August 2000.

Kent T. Larson, 54, Senior Vice President, Operations, Xcel Energy Services Inc., September 2011 to present.  Previously, Chief Energy Supply Officer, Xcel Energy Services Inc., March 2010 to September 2011; Vice President, Transmission, Xcel Energy Services Inc., August 2008 to March 2010; Regional Vice President, Xcel Energy Services Inc., February 2006 to August 2008; Vice President, Jurisdictional Relations, Xcel Energy Services Inc., April 2004 to February 2006; and State Vice President, NSP-Minnesota, September 2000 to April 2004.

Teresa S. Madden, 58, Senior Vice President, Chief Financial Officer, Xcel Energy Inc., September 2011 to present.  Previously, Vice President and Controller, Xcel Energy Inc., January 2004 to September 2011; Vice President of Finance, Customer and Field Operations Business Unit, Xcel Energy Inc., August 2003 to January 2004; Interim Chief Financial Officer, Rogue Wave Software, Inc., February 2003 to July 2003; and Corporate Controller, Rogue Wave Software, Inc., October 2000 to February 2003.

Marvin E. McDaniel, Jr., 54, Senior Vice President, Chief Administrative Officer, Xcel Energy Inc., August 2012 to present. Previously, 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; Vice President, Human Resources, Xcel Energy Services Inc., July 2007 to August 2009; Vice President and Assistant Controller, Xcel Energy Services Inc., March 2005 to June 2007; and Vice President and Controller Energy Markets Business Unit, Xcel Energy Services Inc., February 2004 to February 2005.

Timothy O’Connor, 54, 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 in May 2007 to July 2012; Site Vice President and plant manager, Nine Mile Point Station, Constellation Energy, 2004 to May 2007; and corporate and site responsibilities at Public Service Enterprise Group, Hope and Salem plants, between the years of 1999 to 2004.

R. Roy Palmer, 55, Senior Vice President, External Affairs, Xcel Energy Services Inc., September 2011 to present.  Previously, Vice President, Federal and State Government Affairs, Xcel Energy Services Inc., January 2009 to September 2011; Managing Director, Government and Regulatory Affairs, Xcel Energy Services, Inc., November 2007 to January 2009; Executive Director, State Public Affairs, Xcel Energy Services Inc., April 2005 to November 2007; and Director, Regional Government Affairs, Xcel Energy Services Inc., March 2004 to April 2005.


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Judy M. Poferl, 54, Vice President, Corporate Secretary, Xcel Energy Inc., May 2013 to present. Previously, President, Director and Chief Executive Officer, NSP-Minnesota, August 2009 to May 2013; Regional Vice President, NSP-Minnesota, September 2008 to August 2009; Managing Director, Government and Regulatory Affairs, Xcel Energy Services Inc., November 2007 to September 2008; and Director, Regulatory Administration, Xcel Energy Services Inc., August 2000 to November 2007.

Jeffrey S. Savage, 42, Vice President, Controller, Xcel Energy Inc., September 2011 to present.  Previously, Senior Director, Financial Reporting, Corporate and Technical Accounting, Xcel Energy Services Inc., December 2009 to September 2011; Director, Financial Reporting and Technical Accounting, Xcel Energy Services Inc., March 2007 to December 2009;  and Director, Financial Reporting and Technical Accounting, The Mosaic Company, January 2006 to March 2007.

David M. Sparby, 59, Senior Vice President, Group President, Xcel Energy Services Inc. and President, Director and Chief Executive Officer, NSP-Minnesota, May 2013 to present. Previously, Senior Vice President, Group President, Xcel Energy Services Inc, September 2011 to May 2013; Vice President and Chief Financial Officer, Xcel Energy Inc., August 2009 to September 2011; President, Director and Chief Executive Officer, NSP-Minnesota, August 2008 to August 2009; Executive Vice President and Director, Acting President and Chief Executive Officer, NSP-Minnesota, January 2007 to August 2008; and Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., September 2000 to January 2007.

Mark E. Stoering, 53, President, Director and Chief Executive Officer, NSP-Wisconsin, January 2012 to present.  Previously, Vice President, Portfolio Strategy and Business Development, Xcel Energy Services Inc., August 2000 to December 2011.

George E. Tyson, II, 48, Vice President, Treasurer, Xcel Energy Inc., May 2004 to present.  Previously, Managing Director and Assistant Treasurer, Xcel Energy Inc., July 2003 to May 2004; Director of Origination, Energy Markets Business Unit, Xcel Energy Services Inc., May 2002 to July 2003; and Associate and Vice President, Deutsche Bank Securities, December 1996 to April 2002.

Scott M. Wilensky, 57, Senior Vice President, General Counsel, Xcel Energy Inc., September 2011 to present.  Previously, Vice President, Regulatory and Resource Planning, Xcel Energy Services Inc., September 2009 to September 2011; Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., August 2008 to September 2009; Executive Director, Revenue, Xcel Energy Services Inc., March 2006 to August 2008; Director, State Public Affairs, Xcel Energy Services Inc., November 2001 to March 2006; Assistant General Counsel, Xcel Energy Services Inc., August 2001 to November 2001; and Senior Attorney, Xcel Energy Services Inc., December 1998 to August 2001.

No family relationships exist between any of the executive officers or directors.

Item 1A — Risk Factors

Like other companies in our industry, 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.

There may be further risks and uncertainties that are not presently known or are not currently believed to be material that may adversely affect our performance or financial condition in the future.

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process is to understand, manage and, when possible, mitigate material risk.  Management is responsible for identifying and managing risks, while the Board of Directors oversees and holds management accountable.  Xcel Energy is faced with a number of different types of risk.  Many of these risks are cross-cutting risks such that these risks are discussed and managed across business areas and coordinated by Xcel Energy’s senior management.  Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.


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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 economy and the environment to identify risks. 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. At the same time, the business planning process 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.

Management seeks to mitigate the risks inherent in the implementation of Xcel Energy’s strategy.  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.  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.  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 corporate areas such as internal audit, the corporate controller and legal services.  While Xcel Energy has developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

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

The guidelines on corporate governance and Board committee charters define the scope of review and inquiry for the Board and its committees. Each Board committee has responsibility for overseeing aspects of risk and Xcel Energy’s management and mitigation of the risk. The Board of Directors has overall responsibility for risk oversight and with the committees periodically undertakes the review of the charters to ensure that oversight of key risks are appropriately considered by the various Board committees. The Board also reviews risks at an enterprise level and annually conducts a full day strategy session where it considers risks and confirms that Xcel Energy’s strategy appropriately addresses risk management and mitigation and reviews the performance and annual goals of each business area.

As described above, the Board reviews senior management’s key risk assessment that analyzes the most likely areas of future risk to Xcel Energy. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.


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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 and 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), licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, 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 no longer makes operation of the units economic. 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., cleanup) sites where our past activities, or the activities of certain other parties, caused environmental contamination.  At Dec. 31, 2013, these sites included:

Sites of former MGPs operated by our subsidiaries, predecessors, or other entities; and
Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings.  These mandates are designed in part to mitigate the potential environmental impacts of utility operations.  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, 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 seeking to protect the environment may be adopted or become applicable to us, including but not limited to, regulation of mercury, NOx, SO2, CO2 and other GHGs particulates, coal ash and cooling water intake systems.  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.

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events.  We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.

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 depending on the duration and magnitude of the changes. 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 affect our financial condition, through 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 outside of our service territory 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 on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes 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 could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought 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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To the extent climate change impacts a region’s economic health, it may also impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as a tax on GHGs 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 in our utility operations.  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 or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of such costs. Judgments may arise as a result of prudence investigations (e.g., Monticello LCM/EPU project).  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.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, adverse regulatory rulings or the imposition of additional regulations, including additional environmental or climate change regulation, 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.  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.  For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchased power contracts.  An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology.  Therefore, Xcel Energy Inc. and its subsidiaries credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how our imputed debt is determined.  Any downgrade could lead to higher borrowing costs.  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 in property, plant and equipment; consequently, we are an active participant in debt and equity 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 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 or on incremental commercial paper issuances 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 retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.  Retail 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 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.

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity: however, we have taken advantage of an exception to mandatory clearing afforded to commercial end-users who are not classified as a major swap participant.  The Board of Directors has authorized Xcel Energy and its subsidiaries to take advantage of this end-user exception. In addition, the CFTC has granted an increase in the de minimis level for swap transactions with defined utility special entities, generally entities owning or operating electric or natural gas facilities, from $25 million to $800 million.  Our current level of financial swap activity with special entities is significantly below this new threshold; therefore, we will not be classified as a swap dealer in our special entity activity.  Swap transactions with non special entities have a much higher level of activity considered to be de minimis, currently $8 billion, and our level of activity is well under this limit; therefore, we will not be classified as a swap dealer under the Dodd-Frank Act.  We are currently reporting all of our swap transactions as part of the Dodd-Frank Act.

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


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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 substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions 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 to these funding requirements 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 the company would trigger settlement accounting and could require the company 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 and costs for retiree health care plans have increased substantially 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.  Legislation related to health care could also significantly change our benefit programs and costs.

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 funds by them to us in the form of dividends.  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 that purpose or for dividends on our common stock, whether by dividends or otherwise.  In addition, each subsidiary’s ability to pay dividends to us depends on any statutory and/or contractual restrictions that may be applicable to such subsidiary, 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 generally 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.

Operational Risks

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. 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), which may cause earnings volatility.  Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant 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 authorized or anticipated costs.  Any such disruption, if significant, would 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 would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions 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, electric generation capacity, transmission, natural gas pipeline capacity, etc.


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

NSP-Minnesota’s two nuclear stations, Prairie Island 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 of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;
Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

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 or shut down a unit, or both, until compliance is achieved. Revised NRC safety requirements could necessitate substantial capital expenditures or a substantial increase in operating expenses at NSP-Minnesota’s nuclear plants.  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 with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.

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.

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

Our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptions over the planning horizon such as: sales growth, customer usage patterns, economic activity, costs, regulatory mechanisms, impact of technology, the installation of distributed energy generation, customer behavioral response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide.  This is particularly true in PSCo where the addition of customer-site solar PV installations, which are spurred by the RES, introduces additional downward pressure on load growth. This could lead to under recovery of costs and excess resources to meet customer demand. Xcel Energy’s aging infrastructure may pose a risk to system reliability and expose us to premature financial obligations. Xcel Energy is engaged in significant and ongoing infrastructure investment programs.

In some of our state jurisdictions, large industrial customers may leave our system and invest in their own on-site distributed generation or seek law changes to give them the authority to purchase directly from other suppliers or organized markets.  The recent low natural gas price environment has caused some customers to consider their options in this area, particularly customers with industrial processes using steam.  Wholesale customers may purchase directly from other suppliers and procure only transmission service from our utility subsidiaries.  These circumstances provide for greater long-term planning uncertainty related to future load growth. Similarly, distributed solar generation may become an economic competitive threat to our load growth in the future; however we believe the economics, absent significant subsidies, do not support such a trend in the near term unless a state mandates the purchase of such generation.  Some states have considered such legislation.

Our natural gas 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.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.


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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, 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 additional verification of pipeline infrastructure records by intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. A significant incident could increase regulatory scrutiny and result in penalties and higher costs of operations.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  The U.S. continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change.  Such 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 regulation under climate change laws at either the state or federal level in the future. The EPA is regulating GHGs under the CAA. The EPA has regulated GHG emissions from motor vehicles and adopted new permitting requirements for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has proposed regulations that would establish NSPS for any new fossil fuel-fired power plants that may be built. If adopted, these regulations could significantly increase the cost of building new generating plants. By 2016, the EPA plans to develop and implement GHG regulations applicable to emissions from existing power plants. Such regulations could impose substantial costs on our system.

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.

There are many uncertainties regarding when and in what form climate change legislation or regulations may be enacted.  The impact of legislation and regulations will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are recognized as compliance options, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations.  Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.  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.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities. These include rules associated with emissions of SO2 and NOx, mercury, regional haze, ozone, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

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 $1 million per violation per day.  In addition, NERC electric reliability standards are now mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations.  If a serious reliability incident did occur, it could have a material effect on our operations or financial results.


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The FERC issued NOVs of its market manipulation rules to several market participants during 2013.  The potential penalties in one pending case exceed $400 million.  We attempt to mitigate this risk through formal training on such prohibited practices and a compliance function that reviews our interaction with the markets under FERC and CFTC jurisdictions. However, there is no guarantee our compliance program will be sufficient to ensure against violations.

Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged economic recession and uncertainty of recovery has lowered the correlation between sales and economic growth. Sales growth has been relatively flat due to lower level of economic activity, increased focus on energy efficiency and distributed generation. Instability in the financial markets also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk 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.  Additionally, the cost of those commodities may be higher than expected.

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 systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could 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, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and 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.  Because our generation, 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 (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu or other epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material impact on our financial condition and results.

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


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

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. In addition, in the ordinary course of business, 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 (e.g., information about our customers, employees, operations, infrastructure and assets) could be directly or indirectly affected by unintentional or deliberate 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.  In addition, we also anticipate that such an event would receive regulatory scrutiny at both the Federal and State level.  We are unable to quantify the potential impact of such 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 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.

Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful.  In addition, higher fuel costs could reduce customer demand and/or increase bad debt expense, which could also have a material impact on our results of operations. 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.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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

Our electric 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 for this product 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.

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 2013
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
 
507

 (a)
Monticello-Monticello, Minn., 1 Unit
 
Nuclear
 
1971
 
554

 
Prairie Island-Welch, Minn.
 
 
 
 
 
 

 
Unit 1
 
Nuclear
 
1973
 
521

 
Unit 2
 
Nuclear
 
1974
 
519

 
Black Dog-Burnsville, Minn., 2 Units
 
Coal/Natural Gas
 
1955-1960
 
232

 
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
 
271

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

 
High Bridge-St. Paul, Minn., 3 Units
 
Natural Gas
 
2008
 
534

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

 
Riverside-Minneapolis, Minn., 3 Units
 
Natural Gas
 
2009
 
470

 
Various locations, 17 Units
 
Natural Gas
 
Various
 
101

 
Wind:
 
 
 
 
 
 

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

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

 (c)
 
 
 
 
Total
 
6,982

 
(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.
NSP-Wisconsin

Station, Location and Unit
 
Fuel
 
Installed
 
Summer 2013
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
 
12

 
French Island-La Crosse, Wis., 2 Units
 
Natural Gas
 
1974
 
122

 
Wheaton-Eau Claire, Wis., 6 Units
 
Natural Gas
 
1973
 
290

 
Hydro:
 
 
 
 
 
 

 
Various locations, 63 Units
 
Hydro
 
Various
 
135

 
 
 
 
 
Total
 
631

 
(a) 
Refuse-derived fuel is made from municipal solid waste.

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PSCo

Station, Location and Unit
 
Fuel
 
Installed
 
Summer 2013
Net Dependable
Capability (MW)
 
Steam:
 
 
 
 
 
 

 
Cherokee-Denver, Colo., 2 Units
 
Coal
 
1957-1968
 
504

 (a)
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
 
237

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

 
Valmont-Boulder, Colo., 1 Unit
 
Coal
 
1964
 
184

 
Zuni-Denver, Colo., 1 Unit
 
Coal
 
1948-1954
 
59

 
Combustion Turbine:
 
 
 
 
 
 

 
Blue Spruce-Aurora, Colo., 2 Units
 
Natural Gas
 
2003
 
264

 
Fort St. Vrain-Platteville, Colo., 6 Units
 
Natural Gas
 
1972-2009
 
969

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

 
Various locations, 6 Units
 
Natural Gas
 
Various
 
172

 
Hydro:
 
 
 
 
 
 

 
Cabin Creek-Georgetown, Colo.
 
 
 
 
 
 

 
Pumped Storage, 2 Units
 
Hydro
 
1967
 
210

 
Various locations, 9 Units
 
Hydro
 
Various
 
26

 
Wind:
 
 
 
 
 
 

 
Ponnequin-Weld County, Colo., 37 Units
 
Wind
 
1999-2001
 
25

 (e)
 
 
 
 
Total
 
4,978

 
(a) 
Cherokee Unit 2 was taken out of service in October 2011.  Cherokee Unit 1 was taken out of service in May 2012.
(b) 
Based on PSCo’s ownership interest of 67 percent of Unit 3.
(c) 
Based on PSCo’s ownership interest of 10 percent.
(d) 
Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2.
(e) 
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.
SPS

Station, Location and Unit
 
Fuel
 
Installed
 
Summer 2013
Net Dependable
Capability (MW)
 
Steam:
 
 
 
 
 
 

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

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

 
Cunningham-Hobbs, N.M., 2 Units
 
Natural Gas