XEL 10-K Fiscal year ended Dec. 31, 2010

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, 2010
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-3034

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
Rights to Purchase Common Stock, $2.50 par value per share		New York
Cumulative Preferred Stock, $100 par value:
Preferred Stock $3.60 Cumulative		New York
Preferred Stock $4.08 Cumulative		New York
Preferred Stock $4.10 Cumulative		New York
Preferred Stock $4.11 Cumulative		New York
Preferred Stock $4.16 Cumulative		New York
Preferred Stock $4.56 Cumulative		New York
$7.60 Junior Subordinated Notes, Series due 2068		New York
Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes 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 x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes 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). x 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.

x 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 x No

As of June 30, 2010, the aggregate market value of the voting common stock held by non-affiliates of the Registrants was $9,472,921,126 and there were 459,627,420 shares of common stock outstanding.

As of Feb. 17, 2011, there were 482,686,603 shares of common stock outstanding, $2.50 par value.

DOCUMENTS INCORPORATED BY REFERENCE

The Registrant’s Definitive Proxy Statement for its 2011 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

---

---

TABLE OF CONTENTS

Index

PART I

Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates (current and former)
Cheyenne	Cheyenne Light, Fuel and Power Company, a Wyoming corporation
Eloigne	Eloigne Company, a Minnesota corporation which invests in rental housing projects that qualify for low-income housing tax credits.
e prime	e prime, inc., a wholly owned subsidiary formerly in the business of natural gas trading
NCE	New Century Energies, Inc.
NRG	NRG Energy, Inc., a Delaware corporation and independent power producer
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado, a Colorado corporation
PSRI	P.S.R. Investments, Inc., a manager of corporate owned life insurance policies
Seren	Seren Innovations, Inc., a wholly owned subsidiary formerly a broadband communications network
SPS	Southwestern Public Service Co., a New Mexico corporation
UE	Utility Engineering Corporation, an engineering, construction and design company
utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
WGI	WestGas InterState, Inc., a Colorado corporation operating an interstate natural gas pipeline
WYCO	WYCO Development LLC, a joint venture formed with Colorado Interstate Gas Company to develop and lease natural gas pipeline, storage, and compression facilities
Xcel Energy	Xcel Energy Inc., a Minnesota corporation
Federal and State Regulatory Agencies
AQCC	Colorado Air Quality Control Commission
ASLB	Atomic Safety and Licensing Board
CAPCD	Colorado Air Pollution Control Division
CPUC	Colorado Public Utilities Commission.  The state agency that regulates the retail rates, services and other aspects of PSCo’s operations in Colorado.  The CPUC also has jurisdiction over the capital structure and issuance of securities by PSCo.
CSB	U.S. Chemical Safety Board
DOE	United States Department of Energy
DOT	United States Department of Transportation
EIB	New Mexico Environmental Improvement Board
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission.  The U.S. agency that regulates the rates and services for transportation of electricity and natural gas; the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates; hydroelectric generation licensing; and accounting requirements for utility holding companies, service companies, and public utilities.
IRS	Internal Revenue Service
MOAG	Minnesota Office of Attorney General
MPCA	Minnesota Pollution Control Agency
MPSC	Michigan Public Service Commission.  The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin’s operations in Michigan.
MPUC	Minnesota Public Utilities Commission.  The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota.  The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
NDPSC	North Dakota Public Service Commission.  The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in North Dakota.

NERC	North American Electric Reliability Corporation.  A self-regulatory organization, subject to oversight by the FERC and government authorities in Canada, to develop and enforce reliability standards.
NMED	New Mexico Environment Department

NMPRC	New Mexico Public Regulation Commission.  The state agency that regulates the retail rates and services and other aspects of SPS’ operations in New Mexico.  The NMPRC also has jurisdiction over the issuance of securities by SPS.
NRC	Nuclear Regulatory Commission.  The federal agency that regulates the operation of nuclear power plants.
OCC	Colorado Office of Consumer Counsel
OES	Office of Energy Security, Minnesota Department of Commerce.
OSHA	Occupational Safety and Health Administration
PSCW	Public Service Commission of Wisconsin.  The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin’s operations in Wisconsin.
PUCT	Public Utility Commission of Texas.  The state agency that regulates the retail rates, services and other aspects of SPS’ operations in Texas.
SDPUC	South Dakota Public Utilities Commission.  The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in South Dakota.
SEC	Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program.  Includes a comprehensive list of programs that benefits customers who conserve energy or use electricity at off-peak times of day.
DSM	Demand side management.  Energy conservation, weatherization and other programs to conserve or manage energy use by customers.
DSMCA	Demand side management cost adjustment.  A clause permitting PSCo to recover demand side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis.  Costs for the low-income energy assistance program are recovered through the DSMCA.
ECA	Retail electric commodity adjustment.  Allows PSCo to recover its actual fuel and purchased energy expense in a calendar year to a benchmark formula.  Short-term sales margins and margins from the sale of SO 2 allowances are shared with retail customers through the ECA.
EECRF	Energy efficiency cost recovery factor
EIR	Environmental improvement rider.  Recovers costs of improvements made to two Minnesota plants under the MERP program.
FCA	Fuel clause adjustment. A clause included in electric rate schedules that provides for monthly rate adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast.  The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent period.
FPPCAC	Fuel and purchased power cost adjustment clause. Allows SPS to use a monthly adjustment factor for fuel and purchased power.
GAP	Gas affordability program.  Recovers costs of offering co-payment program to low income customers.
GCA	Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.
MCR	Mercury cost recovery rider.  Recovers the cost related to reducing mercury emissions at two NSP-Minnesota fossil fuel power plants.
OATT	Open Access Transmission Tariff
PCCA	Purchased capacity cost adjustment. Allows PSCo to recover from retail customers for all purchased capacity payments to power suppliers.  Capacity charges are not included in PSCo’s electric rates or other recovery mechanisms.
PDRA	Partial Decoupling Rate Adjustment. A clause included in PSCo’s retail natural gas schedules that recovers revenue lost to decreasing use per customer beyond a threshold.
PGA	Purchased gas adjustment. A clause included in NSP-Minnesota’s and NSP-Wisconsin’s retail natural gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas and natural gas transportation.  The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent period.

QSP	Quality of service plan.  Provides for bill credits to retail customers if the utility does not achieve certain operational performance targets and/or specific capital investments for reliability.  The current QSP for the PSCo electric utility provides for bill credits to customers based on operational performance standards through Dec. 31, 2012.
RDF	Renewable development fund.  Supports the development of renewable energy projects.
RES	Renewable energy standard
RESA	Renewable energy standard adjustment
SCA	Steam cost adjustment.  Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates.  The SCA is revised annually to coincide with changes in fuel costs.
SEP	State Energy Policy
TCA	Transmission cost adjustment.  Provides for the recovery of transmission plant revenue requirements.
TCR	Transmission cost recovery adjustment.  Allows NSP-Minnesota to recover the cost of transmission facilities not included in the determination of NSP-Minnesota’s electric rates in retail electric rates in Minnesota.  The TCR will be revised annually as new transmission investments and costs are incurred.
TCRF	Transmission cost recovery factor

Other Terms and Abbreviations
ACRS	Advisory Committee for Reactor Safety
AFUDC	Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge.  A judge presiding over regulatory proceedings.
APBO	Accumulated Postretirement Benefit Obligation
ARC	Aggregator of Retail Customers
ARO	Asset retirement obligation.  Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
ASC	FASB Accounting Standards Codification
ASM	Ancillary Services Market
BAL	Balancing authority
BART	Best Available Retrofit Technology
BRIGO	Buffalo Ridge Incremental Generation Outlet
BTA	Best Technology Available
CAA	Clean Air Act
CACJA	Clean Air Clean Jobs Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CapX2020	An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
CATR	Clean Air Transport Rule
CCN	Certificate of Convenience and Necessity
CIPS	Critical Infrastructure Protection Standards
CO 2	Carbon dioxide
Codification	FASB Accounting Standards Codification
COLI	Corporate owned life insurance
CON	Certificate of Need
CPCN	Certificate of Public Convenience and Necessity
CWA	Clean Water Act
CWIP	Construction work in progress
decommissioning	The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license.  Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.

derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	●	An underlying and a notional amount or payment provision or both;
	●	Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors; and
	●	Terms require or permit a net settlement, can be readily settled net by means outside the contract, or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
DOI	Division of Investigation
DRIP	Dividend Reinvestment Program
EEI	Edison Electric Institute
EPS	Earnings per share of common stock outstanding
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
FTRs	Financial transmission rights.  Used to hedge the costs associated with transmission congestion.
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity.  Also, the amount of electric energy produced, expressed in MW (capacity) or MW hours (energy).
GHG	Greenhouse gas
IRP	Integrated Resource Plan
LIBOR	London Interbank Offered Rate
LLW	Low-level radioactive waste
LNG	Liquefied natural gas.  Natural gas that has been converted to a liquid.
MACT	Maximum Achievable Control Technology
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MERP	Metropolitan Emissions Reduction Project
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service
MRO	Midwest Reliability Organization
MVP	Multi-Value Project
native load	The customer demand of retail and wholesale customers that a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas	A naturally occurring mixture of gases found in porous geological formations beneath the earth’s surface, often in association with petroleum.  The principal constituent is methane.
NAV	Notice of alleged violation
NOL	Net operating loss
nonutility	All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
NOPR	Notice of proposed rulemaking
NOx	Nitrogen oxide
NEI	Nuclear Energy Institute
O&M	Operating and maintenance
OCI	Other comprehensive income
PBRP	Performance-based regulatory plan.  An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.
PCB	Polychlorinated biphenyl
PFS	Private Fuel Storage, LLC.  A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.
PIIC	Prairie Island Indian Community
PJM	PJM Interconnection, LLC
PPA	Purchased power agreement

Provident	Provident Life & Accident Insurance Company
PRP	Potentially responsible party
PSP	Performance share plan
PURPA	Public Utility Regulatory Policies Act of 1978
PV	Photovoltaic
rate base	The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
REC	Renewable energy credit
RECB	Regional Expansion Criteria Benefits
RFP	Request for proposal
ROE	Return on equity
ROFR	Right of first refusal
RPS	Renewable Portfolio Standard.  A regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.
RTO	Regional Transmission Organization.  An independent entity, which is established to have “functional control” over a utility’s electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SCR	Selective Catalytic Reduction
SIP	State implementation plan
SO 2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
TSR	Total shareholder return
unbilled revenues	Amount of service rendered but not billed at the end of an accounting period.  Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying	A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
WECC	Western Electricity Coordinating Council
wheeling or transmission	An electric service wherein high-voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
working capital	Funds necessary to meet operating expenses.
WTMPA	West Texas Municipal Power Agency
Measurements
Bcf	Billion cubic feet
Btu	British thermal unit.  A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
GWh	Gigawatt hours.  One gigawatt hour equals one billion watt hours.
KV	Kilovolts (one KV equals one thousand volts)
KW	Kilowatts (one KW equals one thousand watts)
KWh	Kilowatt hours
Mcf	Thousand cubic feet
MMBtu	One million Btus
MW	Megawatts (one MW equals one thousand KW)
Volt	The unit of measurement of electromotive force.  Equivalent to the force required to produce a current of one ampere through a resistance of one ohm.  The unit of measure for electrical potential.  Generally measured in kilovolts.
Watt	A measure of power production or usage.

COMPANY OVERVIEW

Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business.  In 2010, Xcel Energy’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.  These utilities 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 Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the continuing regulated utility operations.

Xcel Energy 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 focuses on growing through investments in electric and natural gas rate base to 1) meet growing customer demands, 2) comply with environmental and renewable energy initiatives and 3) maintain or increase reliability and quality of service to customers.  Xcel Energy files periodic rate cases and establishes formula rate 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 strategic priority for Xcel Energy.   Our environmental leadership strategy is designed to meet customer and policy maker expectations while creating shareholder value.

NSP-Minnesota

NSP-Minnesota is an operating 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 6 percent of its total sales in 2010.  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 89 percent of NSP-Minnesota’s retail electric operating revenues were derived from operations in Minnesota during 2010.  Generally, NSP-Minnesota’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.

The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System.  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.

NSP-Wisconsin

NSP-Wisconsin is an operating 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.  The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of its total sales in 2010.  NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory.  NSP-Wisconsin provides electric utility service to approximately 250,000 customers and natural gas utility service to approximately 106,000 customers.  The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota.  Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2010.  Generally, NSP-Wisconsin’s earnings contribute approximately 5 percent to 10 percent of Xcel Energy’s consolidated net income.

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 an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado.  The wholesale customers served by PSCo comprised approximately 20 percent of its total sales in 2010.  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 2010.  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.  Following settlement with the IRS during 2007, such policies were terminated.  PSCo also holds a controlling interest in several other relatively small ditch and water companies.

SPS

SPS is an operating 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 36 percent of its total sales in 2010.  SPS provides electric utility service to approximately 375,000 retail customers in Texas and New Mexico.  Approximately 74 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2010.  Generally, SPS’ earnings contribute approximately 5 percent to 10 percent of Xcel Energy’s consolidated net income.

In October 2010, SPS sold certain electric distribution assets in Lubbock, Texas to Lubbock Power and Light (LP&L) for $87 million.  This sale resulted in a pre-tax gain of approximately $20 million which will be shared with retail customers in Texas, and has been deferred as a regulatory liability pending the determination of the sharing by the PUCT.  SPS’ retail sales in Lubbock were approximately 3 percent of SPS’ total energy sales in both 2010 and 2009.  SPS anticipates it will sell the same amount of power to the city under existing wholesale power arrangements with WTMPA.

Other Subsidiaries

WGI was incorporated in 1990 under the laws of Colorado.  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.

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.  WYCO’s High Plains gas pipeline began operations in 2008 and its Totem gas storage facilities began operations in 2009.  The gas pipeline and storage facilities are leased under a FERC-approved agreement to CIG.

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

Xcel Energy’s nonregulated subsidiary in continuing operations 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 continuing operations and related financial information.

ELECTRIC UTILITY OPERATIONS

Electric Utility Trends

Overview

Environmental Regulations, Climate Change and Clean Energy — Electric utilities are subject to a significant array of environmental regulations.  Further, 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, climate change and clean energy continue to evolve, Xcel Energy has undertaken a number of initiatives to meet current 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 be granted the authority to recover the cost of these initiatives through rates.

Additional information regarding climate change and clean energy is presented in the Management’s Discussion and Analysis section.

Utility Competition — The FERC has continued its efforts to promote competitive wholesale markets through open access transmission and other means.  As a consequence, Xcel Energy’s utility subsidiaries and their wholesale customers can purchase generation resources from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries’ to serve their native load.

Transmission — In June 2010, the FERC issued a NOPR that would eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory, referred to as a ROFR.  The NOPR is pending FERC action.  Irrespective of the NOPR, the utility subsidiaries are pursuing several new transmission facility projects.

The FERC approved the open access transmission planning processes for the Xcel Energy operating companies and the RTOs serving the NSP-Minnesota, NSP-Wisconsin and SPS systems (MISO and SPP, respectively).

In addition to utility-sponsored transmission expansion, several large “overlay” transmission projects have been proposed to construct 765 KV transmission facilities through the service areas of the utility subsidiaries.  Xcel Energy is participating in certain overlay project evaluations to ensure that any projects proposed are the most cost effective options.  It is not certain if or when specific overlay projects may be constructed and placed in service.

Alternative Energy Options — 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.  While each of Xcel Energy’s utility subsidiaries faces these challenges, their rates are competitive with currently available alternatives.  In December 2010, NSP-Wisconsin’s two largest wholesale customers, the cities of Rice Lake, Wis. and Medford, Wis., each issued a notice canceling their wholesale power contracts with NSP-Wisconsin.  The two cities will begin purchasing power from an alternate supplier.  Medford will terminate service at the end of 2011, and Rice Lake will terminate service at the end of 2012.  In 2009, these two customers represented over half of NSP-Wisconsin’s wholesale load and revenue, and approximately 3 percent of NSP-Wisconsin’s total electric operating revenue.

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 and transactions between NSP-Minnesota and its affiliates.  In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans 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 generating and transmission facilities, and 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 mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce.  NSP-Minnesota received authorization from the FERC to make wholesale electric sales at market-based prices (see Summary of Recent Federal Regulatory Developments — Market-Based Rate Rules discussion) and is a transmission-owner 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.  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 improvements to the A.S. King, High Bridge and Riverside plants, which were renovated under the MERP program.

●

GAP — The GAP is a surcharge billed to all non-interruptible customers to recover the costs of offering a low-income customer co-pay program designed to reduce natural gas service disconnections.

●

MCR — The MCR recovers costs related to reducing Mercury emissions at two NSP-Minnesota fossil fuel power plants.

●

RDF — The RDF allocates money collected from retail customers to support the development of emerging renewable energy projects research and development of renewable energy technologies.

●

RES — The RES is a rider that recovers the costs 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 the electric transmission.

NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred cost 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.  The FCAs allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers.  In general, capacity costs are not recovered through the FCA.  In addition, costs associated with MISO are generally recovered through either the FCA or through rate cases.

Minnesota state law requires electric utilities to invest 1.5 percent of their state revenues in CIP, except NSP-Minnesota, which is required by law to invest 2 percent of state revenues.  These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

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 2011, assuming normal weather, is listed below.

The peak demand for the NSP System typically occurs in the summer.  The 2010 uninterrupted system peak demand for the NSP System occurred on Aug. 9, 2010.

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.  Capacity is the measure of the rate at which a particular generating source produces electricity.  Energy is a measure of the amount of electricity produced from a particular generating source over a period of time.  Long-term purchase 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 comply with minimum availability requirements, to obtain energy at a lower cost and for various other operating requirements.

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.

2010 NSP System Resource Decisions and Plan — In May 2010, NSP-Minnesota signed new power purchase and exchange agreements with Manitoba Hydro that will extend purchases through 2025.  The existing agreements provided for the purchase of 850 MW, which would have started to expire in April 2015.  NSP-Minnesota filed for approval with the MPUC in June 2010.

NSP-Minnesota filed its 2011-2025 resource plan in August 2010.  In addition to the extension of contracts with Manitoba Hydro and previously approved life extensions and capacity increases at NSP-Minnesota’s nuclear generating plants,  the near term actions in the  plan include continued expansion of demand side management programs up to 1.5 percent of sales annually, the acquisition of up to 250 MW of additional wind power to be in service by 2012 if priced competitively, and the replacement of the remaining 270 MW of coal fired generation at the Black Dog generating plant with 680 MW combined-cycle unit by January 2016.

Through the Interchange Agreement, the Minnesota resource plan and decisions have a direct impact on the costs that are shared by NSP-Wisconsin.

Wind Generation — NSP-Minnesota invested approximately $500 million in wind generation through 2010 and expects to invest an additional $400 million in 2011.  The 201 MW Nobles Wind Project in southwestern Minnesota began commercial operations in 2010 and the 150 MW Merricourt Wind Project in southeastern North Dakota is expected to reach commercial operation in 2011.  The portion of the costs for the Nobles and Merricourt Wind Projects assigned to Minnesota electric retail customers are currently being collected through the RES rider.  NSP-Minnesota has included the costs for the Nobles Wind Project in its current pending rate case in Minnesota and if approved, the costs will be recovered in base rates when final rates are implemented.  The NDPSC granted advanced determinations of prudence for the Nobles and Merricourt Wind Projects and a CPCN for the Merricourt Wind Project.  This process provides greater assurance that NSP-Minnesota can recover the North Dakota portion of prudently incurred expenses for these projects.

NSP-Minnesota Transmission CONs — In May 2009, the MPUC granted a CON to construct three 345 KV electric transmission lines as part of the CapX2020 project.  The project to build the three lines includes construction of approximately 700 miles of new facilities at a cost of approximately $1.9 billion.  The portion of the project cost to be constructed by NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $1.0 billion.  The remainder of the costs will be born by other utilities in the upper Midwest.  These cost estimates will be revised after the regulatory process is completed.  The MPUC also included a condition assuring a portion of the capacity of the Brookings, S.D. to Hampton, Minn. line is used for renewable energy.  In May 2010, NSP-Minnesota and other CapX2020 utilities notified the MPUC that the in-service date for the Brookings, S.D. to Hampton, Minn. project is expected to be delayed to the second quarter of 2015, more than one year after the date provided in the MPUC CON decision.  The MPUC ordered NSP-Minnesota to provide a report in January 2011 to update the status of the project.  NSP-Minnesota filed the report, which described the numerous activities in progress to allow the project to be placed in service by second quarter 2015.

As part of the regulatory process for the CapX2020 345 KV projects, NSP-Minnesota and Great River Energy filed four route permit applications with the MPUC in addition to a facility permit application with the SDPUC, a certificate of corridor compatibility application with the NDPSC and a CPCN application with the PSCW.  Two filed route permit applications have completed the evidentiary hearing processes, and the MPUC issued route permits for the Monticello, Minn. to St. Cloud, Minn. project and five of the six segments of the Brookings, S.D. to Hampton, Minn. project.  One segment of the Brookings, S.D. to Hampton, Minn. line was referred back to the ALJ to develop more information concerning the appropriate location to cross the Minnesota River.  That process has been completed and the ALJ issued recommendations in December 2010.  In February 2011, the MPUC approved an aerial crossing of the Minnesota River.  The other two CapX2020 route applications are expected to be sent to an evidentiary hearing in 2011.

Bemidji to Grand Rapids

In July 2009, the MPUC approved the CON application for a 230 KV CapX2020 transmission line between Bemidji, Minn. and Grand Rapids, Minn.  Route permit hearings were concluded in May 2010, and a route permit was approved by the MPUC in November 2010.  This line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million.  Construction related activities began in January 2011 and are expected to be completed in 2012.  The estimated project cost to NSP-Minnesota is approximately $26 million.

Hiawatha Transmission Project

In November 2010, NSP-Minnesota submitted a CON application to the MPUC for two 115 KV lines in Minneapolis, Minn.  Hearings on the CON will be held mid-2011 with an expectation of an MPUC decision of the CON and route permit by the end of 2011.

Glencoe to Waconia

In November 2010, NSP-Minnesota submitted a CON to the MPUC for 115 KV transmission line upgrades to the Glencoe, Minn. to Waconia, Minn. 69 KV line.  This was followed by a route permit application filed in December 2010.  Hearings on both applications will be held in mid-2011 with an expectation of an MPUC decision regarding both applications by the end of 2011.

Regulatory Investigations

Sewer Conflict Mitigation Deferred Accounting — In response to a February 2010 natural gas-fueled house fire in St. Paul, Minn., NSP-Minnesota initiated a three-year plan to investigate its natural gas system for conflicts between sewer lines and its natural gas lines, and are estimating plan costs at approximately $3.5 million per year.  In December 2010, the MPUC approved deferred accounting of plan expenditures for recovery consideration in a future natural gas rate case.

ARCs — In 2009, the FERC adopted rules requiring MISO and other RTOs to allow ARCs to offer demand response aggregation services to end-use customers unless the relevant state regulatory agency prohibited the operation of ARCs.  Under MISO’s proposed tariff revisions, ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota.  MISO requested its tariff revisions be effective in June 2010; however the FERC has not issued an order on MISO’s ARC-related tariff revisions.  In May 2010, the MPUC and SDPUC issued orders prohibiting, or temporarily prohibiting, the operation of ARCs.  In August 2010, the NDPSC issued an order prohibiting the operation of ARCs.  In January 2011, the MPUC asked public utilities to explore the potential of programs with ARCs that compliment existing DSM and CIP initiatives.

FCA Investigation — In 2003, the MPUC opened an investigation to consider the continuing usefulness of the FCA for electric utilities in Minnesota.  Continued discussions among utilities, the OES, MOAG and business customers regarding appropriate FCA reporting detail and provision of additional information to customers is ongoing.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant, which has two units.  See Note 15 to the consolidated financial statements for further discussion regarding the nuclear generating plants.

Nuclear power plant operation produces 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 the plant.

LLW Disposal — Federal law places responsibility on each state for securing a site to be used for the disposal of LLW generated within its borders.  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.  In 2002, the U.S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository over the objections of the Governor of Nevada.  In 2008, the DOE submitted an application to construct a deep geologic repository at Yucca Mountain to the NRC.

In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC to approve the withdrawal of the application.  A number of parties have challenged the DOE’s authority to stop the project and withdraw the application.  The utility industry, including Xcel Energy, is represented in the challenges by the NEI.  In light of the DOE’s plan to stop the project and withdraw its application, Xcel Energy in a separate action has requested the Secretary of Energy to set the fee collection rate for the Nuclear Waste Fund to zero until a definitive program is in place.  In April 2010, the NEI, on behalf of its members, including Xcel Energy, filed a lawsuit against the DOE in federal court, requesting that the fee be suspended.  In parallel with the action to stop the Yucca Mountain project, the Secretary of Energy convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposing of used nuclear fuel.  The final report containing recommendations from the Blue Ribbon Commission is expected in early 2012.

In June 2010, the ASLB issued a ruling that the DOE could not withdraw the Yucca Mountain application.  The NRC Commissioners have made a decision to review the ASLB’s decision.  A decision from the NRC Commissioners could come in the first quarter 2011.

To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel.  NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.  As of Dec. 31, 2010, there were 29 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant.  See Item 3 and Note 14 to the consolidated financial statements for further discussion of the legal proceedings against the DOE related to the nuclear waste disposal matter.

PFS — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel.  In 2005, NSP-Minnesota indicated that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation’s spent nuclear fuel.  In 2006, the Department of the Interior issued two findings: (1) that it would not grant the leases for rail or intermodal sites and (2) that it was revoking its previous conditional approval of the site lease between PFS and the Skull Valley Indian tribe. In 2007, PFS and the Skull Valley Band filed a lawsuit challenging these actions.  The lawsuit remains pending.  A judicial appeal of the NRC licensing decision has been held in abeyance pending the outcome of the lawsuit challenging the Department of the Interior decisions.  The existence of PFS as a licensed out-of-state storage option remains a credible alternative if PFS and the Skull Valley Band can prevail in the pending litigation and if the federal government fails to make progress with their obligation to take title and remove spent nuclear fuel from all domestic reactor sites.

Nuclear Plant Power Uprates and Life Extension

Monticello Life Extension — In 2006, the NRC renewed Monticello’s operating license 20 years or until 2030.

Prairie Island Life Extension — In 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively.  The NRC staff is proceeding with the items necessary to process Prairie Island’s license renewal application and NSP-Minnesota anticipates receiving a final decision on the Prairie Island license renewal in the second quarter of 2011.

Monticello Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello facility.  The MPUC approved the extended power uprate in 2008.  The filing was placed on hold by the NRC staff to address concerns raised by the ACRS related to containment pressure associated with pump performance.  The industry submitted a white paper and the NRC staff recommended that the matter be addressed through specific filings to demonstrate any potential risk and mitigation measures.  In a letter to the NRC staff, the ACRS indicated that modifications to the plant should be evaluated and made where practical.  NSP-Minnesota is working with the NRC to determine whether an additional supplement to its filing will be necessary to address the issues and expects to complete the license proceeding in 2011.

Prairie Island Nuclear Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 164 MW for NSP-Minnesota’s Prairie Island Units 1 and 2.  The MPUC approved the extended power uprate in 2009.  NSP-Minnesota cannot file for NRC approval of the extended power uprate until after the NRC renews the plants’ current operating licenses.  A decision is expected in 2011.  The extended power uprates are scheduled to be implemented during the 2014 and 2015 refueling outages.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

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

Fuel Sources

Coal — The NSP System normally maintains approximately 40 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2010 and 2009 were approximately 39 and 43 days usage, respectively.  NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Wyoming and Montana.  Estimated coal requirements at NSP-Minnesota’s and NSP-Wisconsin’s major coal-fired generating plants were approximately 9.9 and 10.2 million tons per year at Dec. 31, 2010 and 2009, respectively.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 85 percent of their coal requirements in 2011, 75 percent of their coal requirements in 2012 and 31 percent of their coal requirements in 2013.  Any remaining requirements will be filled through a RFP process or through 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 through 2013.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

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, conversion and enrichment 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 2012, approximately 66 percent of the requirements for 2013 through 2017, and approximately 38 percent of the requirements for 2018 through 2025.  Contracts for additional uranium concentrate supplies are currently being negotiated that are expected to provide a portion of the remaining open requirements through 2025.

●

Current contracts for conversion services cover 100 percent of the requirements through 2011, approximately 78 percent of the requirements from 2012 through 2016, and approximately 30 percent of the requirements for 2017 through 2025.  Contracts for additional conversion services are being negotiated to provide a portion of remaining open requirements for 2012 and beyond.

●

Current enrichment services contracts cover 100 percent of 2011 through 2016 requirements, and approximately 54 percent of the requirements for 2017 through 2025.  Contracts for additional enrichment services are being negotiated to provide a portion of the remaining open requirements for 2017 and beyond.

Fabrication services for Monticello are covered through 2014.  A contract for fuel fabrication services for Monticello for 2015 and beyond is currently being negotiated.  Prairie Island’s fuel fabrication is 100 percent committed to 2015.

NSP-Minnesota expects sufficient uranium, conversion and enrichment 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 some of the supply contracts.

Natural gas — The NSP System uses both firm and interruptible natural gas 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.  The supply, transportation and storage contracts expire in various years from 2011 to 2028.  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 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, 2010, NSP-Minnesota’s commitments related to supply contracts were $14 million and commitments related to transportation and storage contracts were approximately $499 million.  The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

Wholesale Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products.  NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases.  See Item 7A 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 mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce.  NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules discussion) and 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.

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with costs included in retail base electric rates.  If the comparison results in a difference of 2 percent, the PSCW may hold hearings limited to fuel costs and revise rates upward or downward.  Any revised rates would remain in effect until the next rate change.  The adjustment approved is calculated on an annual basis, but applied prospectively.  NSP-Wisconsin’s wholesale electric rate schedules include a FCA to provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.  In 2011, the fuel and purchased energy cost recovery mechanism will be changed as discussed below.

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, reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Wisconsin Fuel Cost Recovery Legislation — In May 2010, Wisconsin adopted a law to modify its existing statutes and rules governing electric fuel cost recovery in utility rates.  The prohibition on an automatic adjustment clause remains, but the provision requiring an emergency or extraordinary increase in the cost of fuel before the PSCW can approve a fuel-related rate increase was repealed.

Under the final rules, an electric utility will submit a forward-looking annual fuel cost plan for approval by the PSCW.  Once a utility has an approved fuel cost plan, it can then defer any under-collection or over-collection of fuel costs for future rate recovery or refund, for the amount of any under/over-collection that exceeds a 2 percent symmetrical annual tolerance band.  Approval of a fuel cost plan and any rate adjustment for recovery or refund of deferred costs would be determined by the PSCW after 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.  The rule went into effect for calendar year 2011.

Wisconsin RPS and Energy Efficiency and Conservation Goals — The Wisconsin legislature passed an RPS that requires 10 percent of electric sales statewide to be supplied by renewable energy sources by the year 2015.  However, under the RPS, each individual utility must increase its renewable percentage by 6 percent over its baseline level.  For NSP-Wisconsin, the RPS is 12.89 percent.  NSP-Wisconsin anticipates it will meet the RPS requirements with its pro-rata share of existing and planned renewable generation on the NSP System.

In 2010, the Wisconsin legislature approved a recommendation by the PSCW to increase state energy efficiency and conservation funding.  NSP-Wisconsin will be allocated approximately $9.6 million of the statewide program costs for 2011.  Historically, NSP-Wisconsin has recovered these costs in rates it charges to Wisconsin retail customers and expects to recover the increased program costs in rates going forward.  The new statewide annual funding requirements are fixed as follows:

ARCs — In 2009, the FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers unless the applicable state regulatory authority prohibits ARCs from serving retail customers in their state.  ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Wisconsin.  MISO requested its tariff revisions be effective in June 2010; however the FERC has not issued an order on MISO’s ARC-related tariff revisions.  During 2009, the PSCW and MPSC issued orders temporarily prohibiting ARCs from operating in Wisconsin and Michigan, respectively, pending further regulatory proceedings.  No additional action has been taken by the PSCW or the MPSC since that time.

Capacity and Demand

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See a discussion of the system capacity and demand under NSP-Minnesota Capacity and Demand discussed previously.

Energy Sources and Related Initiatives

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See a discussion of the system energy sources under NSP-Minnesota Energy Sources and Related Initiatives discussed previously.

Fuel Supply and Costs

NSP-Wisconsin operates an integrated system with NSP-Minnesota.  See a discussion of the system energy sources under NSP-Minnesota Fuel Supply and Costs discussed previously.

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 mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce.  PSCo has received authorization from the FERC to make wholesale electricity sales at market-based prices (see Summary of Recent Federal Regulatory Developments — Market-Based Rate Rules discussion); however, PSCo withdrew its market-based rate authority with respect to sales in its own and affiliated operating company control areas.

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 purchase power costs.  Short-term sales margins and margins from the sale of SO 2 allowances are shared with retail customers through the ECA.  The ECA mechanism is revised quarterly.

●

PCCA — The PCCA allows for recovery of purchased capacity payments for power purchase agreements.  Effective January 2011, the PCCA recovers the revenue requirement associated with the purchase of two facilities formerly under power purchase agreement: Blue Spruce Energy Center and Rocky Mountain Energy Center.

●

SCA — The SCA allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates.  The SCA rate is revised annually on Jan. 1, as well as on an interim basis to coincide with changes in fuel costs.

●

DSMCA — The DSMCA clause permits PSCo to recover DSM and interruptible service option credit costs on a concurrent basis and performance initiatives based on achieving various energy savings goals.  Beginning 2010, the CPUC approved recovery of the full amount of DSM-related costs through the combination of base rates and a DSMCA tracker mechanism.

●

RESA — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of 2 percent of the customer’s total bill.

●

Wind Source Service — The Wind Source Service is a premium service for those customers who voluntarily choose to contribute funds for the acquisition of additional renewable resources beyond the level of PSCo’s resource plan.  Wind Energy Service customers pay a charge that is in addition to the rates paid by other customers.

●

TCA — The TCA provides for the recovery outside of rate cases of transmission plant revenue requirements and allows for a return on CWIP for transmission investments.

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 renewable energy purchase and generation costs through a fuel clause and in exchange receive renewable energy credits associated with those resources.

PBRP and QSP Requirements — PSCo currently operates under an electric PBRP.  This regulatory plan includes 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 through 2012.  PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP.  In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP.  The CPUC conducts proceedings to review and approve these rate adjustments annually.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2011, assuming normal weather, is listed below.

The peak demand for PSCo’s system typically occurs in the summer.  The 2010 uninterrupted system peak demand for PSCo occurred on July 14, 2010.

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 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.

Purchased Power — PSCo has contracts to purchase power from other utilities and independent power producers.  Long-term purchase 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 replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to comply with minimum availability requirements, to obtain energy at a lower cost and for various other operating requirements.

Resource Plan — In October 2009, the CPUC approved PSCo’s resource plan which includes 900 MW of additional intermittent renewable energy resources (wind and PV solar) and approximately 280 MW of “new technology” renewable energy sources.  The CPUC also approved the selection of approximately 900 MW of traditional gas-fired resources.

Gas-fired Resources

In October 2010, the CPUC approved the acquisition of approximately 900 MW of gas-fired generation from subsidiaries of Calpine Corporation and the cost recovery settlement.  In its approval, the CPUC required PSCo to file a rate case by April 30, 2012 to move the investment into rate base.  The revenue requirements associated with the asset acquisition will continue to be recovered through the PCCA until final rates are implemented.  The PCCA went into effect on Jan. 1, 2011.  Fuel costs will continue to flow through the ECA. The acquisition closed on Dec. 6, 2010, and the related PPAs for the Blue Spruce Energy Center and Rocky Mountain Energy Center were terminated effective that date.  See Note 19 to the consolidated financial statements for further discussion.

Solar and Wind Resources

In 2010, PSCo filed an amendment to the approved resource plan to reduce the amount of solar resources (combination of PV solar and new technology renewable energy resources) to 60 MW and to seek new bids for 200 MW of wind power due to the combination of a transmission line delay and changed market circumstances.  The matter has been referred to an ALJ with direction to resolve the matter by May 2011.

RES — In March 2010, Colorado enacted a law that increases the RES and now mandates that at least 30 percent of energy sales be supplied by renewable energy for PSCo and removes the solar standard and replaces it with a distributed generation standard.  Within the distributed generation standard, at least one-half of the distributed generation must be retail distributed generation, i.e., generation that is on customer premises behind the customer meter.  The law requires that PSCo generate or cause to be generated electricity from renewable resources equaling:

●

At least 12 percent of its retail sales for the years 2011 through 2014;

●

At least 20 percent of its retail sales for the years 2015 through 2019; and

●

At least 30 percent of its retail sales for the years 2020 and thereafter.

In addition, distributed generation must equal:

●

At least 1 percent of retail sales in the years 2011 and 2012 and 1.25 percent of retail sales in the years 2013 and 2014;

●

At least 1.75 percent of retail sales in the years 2015 and 2016 and 2 percent of retail sales in the years 2017, 2018 and 2019; and

●

At least 3 percent of retail sales in the years 2020 and thereafter.

The CPUC has discretion to review the reasonableness of the increase in the distributed generation percentage in 2014.  PSCo believes that its forecasted plan acquisitions of renewable resources only need minor modification to comply with the new standard.

CACJA — The CACJA was signed into law in April 2010.  The CACJA required PSCo to file a comprehensive plan to reduce annual emissions of NOx by at least 70 to 80 percent or greater from 2008 levels by 2017 from the coal-fired generation identified in the plan.  The plan was required to consider both current and reasonably foreseeable CAA requirements and allows PSCo to propose emission controls, plant refueling, or plant retirement of at least 900 MW of coal-fired generating units in Colorado by Dec. 31, 2017.  The legislation further encourages PSCo to submit long-term gas contracts to the CPUC for approval.  The CACJA permits the CPUC to consider interim rate increases after Jan. 1, 2012, while the rate filing is pending and allows for multi-year rate plans.

In December 2010, the CPUC approved the following:

●

Shutdown Cherokee Units 1 and 2 in 2011 and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee Station (569 MW);

●

Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017;

●

Shutdown Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (352 MW) in 2013 to natural gas;

●

Shutdown Valmont Unit 5 (186 MW) in 2017;

●

Install SCR for controlling NOx and a scrubber for controlling SO 2 on Pawnee Station in 2014;

●

Install SCR on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016; and

●

Convert Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.

The CPUC provided for recovery on CWIP in rate base in each rate case and deferred accounting of accelerated depreciation costs.  PSCo needs to make applications for detailed cost review before commencing each phase of the plan.  The CPUC also encouraged PSCo to hold stakeholder meetings to discuss issues around a multi-year rate plan.  In January 2011, the AQCC unanimously approved incorporation of the CACJA plan into Colorado’s regional haze SIP.  See Note 14 to the consolidated financial statements for discussion.  The Colorado state legislature must review the SIP, which will contain provisions of the CACJA approved by the CPUC.  Unless changed by the legislature during its review process, the SIP (including the CACJA plan) will be sent to the EPA for incorporation into federal CAA regulations.  The total investment associated with the adopted plan is approximately $1.0 billion over the next seven years.  The rate impact of the proposed plan is expected to increase future bills on average by 2 percent annually.

San Luis Valley-Calumet-Comanche Unit 3 Transmission Project — In May 2009, PSCo and Tri-State Generation and Transmission Association filed a joint application with the CPUC for a project for 230 KV and 345 KV line and substation construction.  The line is intended to assist in bringing solar power in the San Luis Valley to load.  The line was originally expected to be placed in-service in 2013; however, that appears unlikely now due to delays in the siting and permitting of the line.  Several landowners oppose this transmission line, including two large ranches.  In November 2010, the ALJ issued a recommended decision granting the CPCN but proposing a significant refund obligation if the line was not heavily utilized ten years after it was in service.  Several parties, including PSCo, filed exceptions to the recommended decision.  The CPUC deliberated on the exceptions to the recommended decision and granted the CPCN without the refund obligation recommended by the ALJ.  A written decision will follow.

SmartGridCity™ CPCN — As part of the PSCo electric rate case, the CPUC included recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred by PSCo to develop and operate SmartGridCity™, subject to refund, and ordered PSCo to file for a CPCN for that project.

In February 2011, the CPUC approved the CPCN and allowed recovery of approximately $28 million of the capital cost and 100 percent of the O&M costs and ordered PSCo to file for a rate reduction in April 2011 to reflect the lower level of capital in rate base.  The CPUC seeks additional information regarding the future plans to utilize SmartGridCity™ in an application to recover the additional capital.  PSCo believes that it will be able to satisfy that requirement.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

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

Fuel Sources

Coal — Coal inventory levels may vary widely among plants.  However, PSCo normally maintains approximately 41 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2010 and 2009 were approximately 34 and 68 days usage, respectively, based on the maximum burn rate for all of PSCo’s coal-fired plants.  PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming.  During 2010 and 2009, PSCo’s coal requirements for existing plants were approximately 11.2 million and 9.2 million tons, respectively.

PSCo has contracted for coal suppliers to supply 84 percent of its coal requirements in 2011, 53 percent of its coal requirements in 2012 and 22 percent of its coal requirements in 2013.  Any remaining requirements will be filled through an RFP process or through over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 100 percent of its coal requirements in 2011, 67 percent of its coal requirements in 2012 and 66 percent of its coal requirements in 2013.  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 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.  The supply contracts expire in various years from 2011 through 2021.  The transportation and storage contracts expire in various years from 2011 to 2040.  The majority 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, 2010, PSCo’s commitments related to supply contracts were approximately $817 million and transportation and storage contracts were approximately $1.0 billion.

Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products.  PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases.  See Item 7A 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 increase.  SPS can and does 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 mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce.  SPS has received authorization from the FERC to make wholesale electric sales at market-based prices (see Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules discussion).

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — 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.  The regulations allow retail fuel factors to change up to three times per year.

There is an accounting of over- or under-recovery of fuel and purchased energy expenses under the fixed factor.  Regulations also require refunding or surcharging over- or under-recovery amounts, including interest, when they exceed 4 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 efficiency of the 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.

The NMPRC has authorized SPS to use a monthly adjustment factor for a FPPCAC for SPS’ New Mexico retail jurisdiction.  NMPRC regulations require SPS to periodically request authority to continue using its FPPCAC.  The NMPRC reviews SPS’ use of its FPPCAC since the filing of its previous fuel clause continuation filing.  As a follow-up to SPS’ last rate case, the NMPRC conducted an audit of SPS’ fuel and purchased power costs for a 12 month period from July 2009 through July 2010 and the tracking mechanism to capture costs and revenues associated with SPS’ RECs from assorted wind projects for the 12-month period from July 2009 through July 2010.  Audit results are expected in the first quarter of 2011.

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.

Texas EECRF Rider — PUCT regulations established an EECRF rider under which electric utilities may recover costs associated with providing energy efficiency programs.  The EECRF rider must be included in a utility’s tariff and may be established in a utility’s base rate case or through a separate request seeking to establish an EECRF.  Previously, the PUCT concluded that the rule did not apply to SPS and that energy efficiency costs should be recovered in base rates.  As part of the settlement in SPS’ last base rate case, SPS reached a negotiated settlement with the parties and included base rate recovery amounts explicitly designated for energy efficiency.  In August 2010, the PUCT adopted a new rule that increases the energy efficiency goals and makes SPS subject to the same requirements with respect to the EECRF as other utilities in the state . Parties can appeal the application of the rule to SPS when SPS files for the rider in the spring of 2011.

Jones CCN — In August 2010, 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.  The NMPRC approved a similar CON in December 2010.

New Mexico Energy Efficiency Disincentive Rulemaking — During the 2008 New Mexico legislative session, increased energy efficiency goals and removal of disincentives were adopted.  In 2010, the NMPRC adopted an amended rule incorporating the legislative changes.  The rule had an interim mechanism that provides for recovery of disincentives and required utilities to file permanent rate design or other means of removing disincentives.

In July 2010, SPS filed its application to remove disincentives and requested direct lost margin recovery.  A final approval order was received in December 2010 totaling $3.3 million for 2010 and 2011.  A hearing in this case that focuses on the appropriate long-term mechanism is scheduled for March 2011.

Solar Contract Approval — In December 2009, SPS entered into five solar energy PPAs with SunEdision, LLC (SunE), for the procurement of solar energy and associated RECs to meet its solar diversity requirements.  The SunE PPAs involve five facilities, each consisting of 10 MW of capacity for a term of 20 years.  In September 2010, the NMPRC approved the SunE PPAs and SPS’ proposed cost recovery.

New Mexico GHG Regulations — In 2010, the New Mexico EIB adopted regulations to limit and reduce GHGs, including CO 2 emissions from power plants and other industrial sources. SPS and several other utilities and industry groups have filed separate appeals with the New Mexico Court of Appeals challenging the validity of these GHG regulations. Compliance costs for these reductions or offsets may increase electricity rates to New Mexico customers.  While regulated utilities generally recover costs resulting from regulatory requirements, SPS may not recover all costs related to complying with the regulatory requirements imposed on SPS under the existing EIB regulations.  The effect of these regulations on the financial condition of SPS is uncertain, due to the lack of certainty about the validity of these challenged regulations, and also due to the relatively small proportion of SPS total greenhouse gases that are emitted in New Mexico.

TUCO Inc. (TUCO) to Woodward District Extra High Voltage (EHV) Interchange — In June 2009, SPP directed SPS to construct a 178 mile 345 KV transmission line between Lubbock, Texas and Woodward, Okla.  The estimated investment in the new line is $149 million and will be recovered from SPP members, including SPS, in accordance with the SPP OATT and the retail ratemaking process.  Preliminary work has begun for construction from the TUCO substation to the Oklahoma border.  TRC was contracted to do the routing and environmental impact studies.  SPS is expected to file an application requesting approval to build the line in March 2011.

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2011, assuming normal weather, is listed below.

The peak demand for the SPS system typically occurs in the summer.  The 2010 uninterrupted system peak demand for SPS occurred on Aug. 4, 2010.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases and DSM 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 purchase power contracts typically require a periodic payment to secure the capacity from and a charge for the associated energy actually purchased.  SPS also makes short-term purchases to comply with minimum availability requirements, and to obtain energy at a lower cost.

SPS Resource Planning

Integrated Resource Planning (IRP) — SPS is soliciting public participation throughout 2011 in its New Mexico 2012 IRP filing through public and webcast meetings.  SPS anticipates filing the IRP with the NMPRC in July 2012.

Renewable Energy Portfolio Plan — SPS is required to develop and implement a renewable portfolio plan in which ten 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.  In 2009, the NMPRC granted SPS a variance to allow SPS to delay meeting its solar energy requirement until 2012 provided that SPS compensates for any shortfall of the solar energy requirement for 2011 during 2012 through 2014.  SPS executed and received NMPRC approval for a total of 50 MW of PV solar energy PPAs.  SPS requested a variance from the NMPRC to extend the time to implement its other resource diversity requirements to January 2012.

Approved Resource Additions — SPS plans to add a new third gas turbine to its Jones Plant site in Lubbock, Texas.  SPS received CCN approvals from the PUCT and NMPRC for the turbine which will become operational in June 2011.  This generating unit will add 168 MW of capacity to the SPS service territory.  SPS also executed a purchase power agreement with Calpine Energy Services, LP for 200 MW from 2012 through 2018 that was approved by the NMPRC on Dec. 30, 2010.

Pending Resource Solicitations — SPS finalized a power purchase agreement for 161 MW of wind resources and requested approval from the NMPRC in December 2010.  SPS released a request for proposal in 2009 for approximately 43,000 MWh annually of biomass generation or an equivalent amount of biogas of approximately 326,000 MMBtu annually to meet its other resource diversity requirements in New Mexico.  SPS is continuing its efforts to acquire viable biomass generation or a biogas purchase to meet its renewable energy portfolio plan in New Mexico.

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

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

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

Fuel Sources

Coal — SPS purchases all of its 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.  For the Harrington station, the coal supply contract with TUCO expires in 2016.  For the Tolk station, the coal supply contract with TUCO expires in 2017.  As of Dec. 31, 2010 and 2009, coal inventories at the Harrington site were approximately 38 and 46 days supply, respectively.  As of Dec. 31, 2010 and 2009, coal inventories at the Tolk site were approximately 45 and 54 days supply, respectively.  TUCO has coal agreements to supply 90 percent of SPS’ coal requirements in 2011, 57 percent of SPS’ coal requirements in 2012, and 44 percent of SPS’ coal requirements in 2013, which are sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

Natural gas — SPS uses both firm and interruptible natural gas 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 2011 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. These transportation rates are subject to revision based upon FERC or Railroad Commission of Texas 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, 2010, SPS’ commitments related to supply contracts were approximately $28 million and transportation and storage contracts were approximately $233 million.

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 supplies and purchases.  See Item 7A for further discussion.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of Xcel Energy’s utility subsidiaries, and enforcement of NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of Xcel Energy’s utility activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 13 to the consolidated financial statements for further discussion of other regulatory matters.

FERC Penalty Guidelines Issued — The Energy Act required the FERC to adopt new regulations to implement various aspects of the Energy Act.  Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

In September 2010, the FERC issued a policy statement establishing guidelines to determine the financial penalties that would be applied for violations of FERC statutes, rules and orders, including violations of NERC mandatory reliability standard violations investigated by the FERC.  The guidelines establish a base violation level for various types of violations, plus mitigating or aggravating factor adders and multipliers, depending on the nature and severity of the violation.  Penalties range between a minimal amount and $72.5 million based on an application of a multiplier.  The guidelines indicate that the FERC can deviate from the guidelines in its discretion.  The guidelines can apply to any investigation where the FERC staff has not begun settlement negotiations regarding an alleged violation.

While Xcel Energy cannot predict the ultimate impact new FERC regulations will have on its operations or financial results, Xcel Energy is taking actions that are intended to comply with and implement new FERC rules and regulations as they become effective.

NERC Electric Reliability Standards Compliance

Compliance Audits and Self Reports

In October 2008, the WECC auditors issued their final audit report on PSCo’s compliance with certain NERC mandatory electric reliability standards.  The report found a possible violation of one reliability standard related to relay maintenance.

In 2008, the NSP System, PSCo and SPS filed self-reports with the MRO, WECC and SPP regional entities, respectively, relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain CIPS.  In 2009, the NSP System, PSCo, and SPS each reached agreement with the relevant regional entity that would resolve the PSCo open 2008 audit finding and the 2008 self reports by payment of a non-material penalty.  These settlement agreements have been approved by the NERC and were filed for FERC approval in December 2010.  In January 2011, the FERC issued an order accepting the NERC approval with no further action.

In March 2010, the MRO, SPP and WECC conducted a joint compliance spot check to evaluate compliance with the NERC CIPS.  The regional entity issued a non-public final report in August 2010 alleging violations of certain CIPS requirements, including certain violations common to all Xcel Energy utility subsidiaries.  Xcel Energy disputes the alleged violations and is working to resolve the issues.  To what extent the regional entities or NERC may seek to impose penalties for violations of CIPS is unknown at this time.

In July 2010, the WECC issued a non-public NAV related to (1) two alleged non-common CIPS violations identified in the joint CIPS spot-check, and (2) two violations self-reported by PSCo related to certain BAL standards.  The WECC NAV proposed a non-material penalty.  PSCo requested that the proceedings be deferred to allow settlement negotiations to resolve the NAV.  The matter is now in settlement discussions.  Based on these discussions, a second self-report similar to one of the previously filed BAL self-reports was filed and this report will be resolved along with the other matters pending with WECC.  None of the alleged or self-reported violations is expected to result in a material penalty.

In 2010, SPP conducted its triennial audit of SPS compliance with certain NERC mandatory electric reliability standards.  The audit did not include an evaluation of SPS compliance with NERC CIPS.  The auditors found no standards violations.  The written SPP audit report is now being completed.

In November 2010, the NSP System, PSCo and SPS filed self-reports with the MRO, WECC and SPP, respectively, regarding potential violations of certain NERC CIPS.  Additional self-reports of potential violations of CIPS standards were filed in January 2011.  Based on the issues identified with CIPS compliance, the utility subsidiaries submitted a mitigation plan that provides for a comprehensive review of their CIPS compliance programs.  Whether and to what extent penalties may be assessed against the utility subsidiaries for the issues identified and self-reported to date is unclear.

In February 2011, the NSP System will be subject to a comprehensive triennial audit by the MRO regarding compliance with various NERC mandatory reliability standards, including CIPS.

NERC Compliance Investigations

In September 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection as a result of a series of transmission line outages.  In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada.  The initial transmission line outages occurred on the NSP System.  In March 2008, NSP-Minnesota received notice that the MRO was commencing a compliance investigation of the event.  Because the event affected more than one region, the NERC took over the investigation.  In January 2010, the NERC issued a preliminary non-public report alleging the NSP System violated certain NERC reliability standards.  The report represents the preliminary conclusions of the NERC and is subject to additional procedures at NERC, and ultimately FERC review.  In late 2010, NERC transferred responsibility for completing the compliance investigation to the MRO.  The final outcome of the compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC.  NSP-Minnesota is fully cooperating with the investigation.  The final outcome of the NERC compliance investigation, and whether and to what extent NERC may seek to impose penalties for violations, is unknown at this time.

NERC Advisory Regarding Impact of Transmission Field Conditions on Facility Ratings — In October 2010, the NERC issued an advisory requiring utilities to perform an assessment of field versus assumed “as built” transmission infrastructure conditions.  In December 2010, the NERC issued a revised advisory extending the period for affected entities to complete their initial assessment and corrective actions until 2013 and 2014, respectively.  The advisory compliance cost for the utility subsidiaries is estimated at $25 million to $30 million.  Xcel Energy will seek recovery through applicable rate-making mechanisms.

Electric Transmission Rate Regulation — The FERC regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO.  NSP-Minnesota and NSP-Wisconsin are members of the MISO RTO.  SPS is a member of the SPP RTO.  Each RTO separately files regional transmission tariff rates for approval by the FERC.  All members within that RTO are then subjected to those rates.  In 2009, PSCo filed a tariff to participate with other utilities in WestConnect, a consortium of utilities offering regionalized non-firm transmission services.  The WestConnect tariff was effective in the first quarter of 2009.  The WestConnect tariff has not had a material impact on PSCo transmission usage or revenues.  WestConnect may provide wholesale energy market functions in the future, but would not be an RTO.

Proposed Rulemaking on Transmission Planning and Cost Allocation — In June 2010, the FERC issued a NOPR regarding transmission planning and cost allocation.  The NOPR would (1) require that local and regional transmission planning processes address public policy requirements established by state or federal laws or regulations; (2) improve coordination between neighboring transmission planning regions of interregional facilities; (3) eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory, referred to as a ROFR; and (4) require cost allocation methods for transmission facilities to satisfy newly established cost allocation principles.  The FERC will consider the written comments provided on the NOPR prior to adopting a final rule.  The content of the final rule cannot be predicted at this time; however, limiting an incumbent utility’s preferential ROFR to build transmission in its service territory states may have a negative impact on longer-term growth opportunities for the Xcel Energy utility subsidiaries.

MISO Transmission Pricing — Certain new higher voltage transmission facilities determined by MISO to meet RECB eligibility criteria in the MISO tariff are subject to an allocation of 20 percent of the facility costs to all loads in the 15 state MISO region.

In July 2010, MISO and certain member transmission owners, including NSP-Minnesota and NSP-Wisconsin, filed proposed changes to the MISO tariff that would provide for regional cost allocation for 100 percent of the costs associated with transmission projects identified by MISO as MVPs.  In December 2010, the FERC approved the tariff revisions, with conditions, to be effective in July 2010.  The MVP tariff provisions are pending final FERC action.  The MISO independent board of directors must approve MVP eligibility before the costs of a specific project are eligible for regional rate recovery under the MISO Tariff.

The MISO regional cost allocation methods require other customers in MISO to contribute to cost recovery for certain new transmission facilities constructed by NSP-Minnesota and NSP-Wisconsin.  MISO approved the eligibility of the CapX2020 Fargo, N.D. and La Crosse, Wis. transmission expansion projects for 20 percent regional allocation; and NSP-Minnesota anticipates the Brookings, S.D. CapX2020 project will be recommended for eligibility as an MVP, and thus 100 percent regional cost allocation, during 2011.  The CapX2020 Bemidji, Minn. transmission expansion project is not eligible for regional cost allocation.  However, NSP-Minnesota and NSP-Wisconsin also pay a share of the costs of projects constructed by other transmission-owning entities in the MISO region found to be eligible for regional cost allocation.  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 are expected to be material in future periods.

Market-Based Rate Rules — Each of the Xcel Energy utility subsidiaries was granted market-based rate authority.  Under market-based rate rules, the NSP System was reauthorized to sell wholesale power at market-based rates in June 2009.  SPS was reauthorized to sell at market-based rate rules outside its service territory by the FERC in July 2010.  PSCo filed a request for market-based rate reauthorization outside its service territory in June 2010.  The request is pending FERC action.  Presently, the Xcel Energy utility subsidiaries may not sell power at market-based rates within the PSCo and SPS balancing authorities, where they have been found to have market power under the FERC’s applicable analysis.  Both PSCo and SPS have cost-based coordination tariffs that they may use to make sales in their balancing authorities.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, DOI, commenced a non-public investigation of the transmission service arrangements across the Lamar Tie Line, a transmission facility that connects PSCo and SPS.  In July 2008, the DOI issued a preliminary report alleging Xcel Energy violated certain FERC policies, rules and approved tariffs, that could result in material penalties under the FERC penalty guidelines.  The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions set forth in the report.  Xcel Energy provided a response that disagreed with the preliminary report and demonstrated compliance with applicable standards.  In December 2010, the DOI initiated settlement negotiation with Xcel Energy regarding possible resolution of the non-public investigation.  The final outcome of the FERC DOI investigation and to what extent FERC may seek to impose penalties for violations is unknown at this time.

MISO vs. PJM Complaint Proceedings — In March 2010, MISO filed two complaints against PJM at the FERC alleging that PJM violated generation redispatch requirements under the joint operating agreement between the two RTOs, and alleging that incorrect modeling of certain generators by PJM resulted in underpayments by PJM of up to $135 million to generators in MISO (including NSP-Minnesota and NSP-Wisconsin) for redispatch provided from 2002 to 2009.  MISO asked the FERC to direct PJM to pay the underpaid amount, plus interest.  In April 2010, PJM filed a complaint against MISO, alleging that MISO dispatched generation in the MISO region improperly under the RTO joint operating agreement, and requested that the FERC order MISO to pay PJM up to $25 million.  In January 2011, MISO and PJM filed a settlement agreement with the FERC that would provide for no payments between the RTOs for prior period errors, but establishes a process to validate and periodically update the operational modeling to prevent future similar errors.  The settlement is pending FERC approval.

Revenue Sufficiency Guarantee (RSG) Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy.

In August 2010, the FERC issued two RSG-related orders, one in which, among other items, it affirmed its initial decision to not require refunds for MISO’s failure to include virtual supply offers in its RSG calculations.  The second order rejected various provisions of MISO’s redesign proposal, which was intended to replace the current RSG methodology.  In December 2010, MISO filed a revised RSG tariff reflecting the 2009 “indicative” tariff proposal and subsequent FERC orders, to be effective March 2011.

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001.  PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings.  In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices.  Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered.  Subsequent to the ruling, the FERC has allowed the parties to request additional evidence.  Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million.  In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings.  Certain purchasers filed appeals of the FERC’s orders in this proceeding with the U.S. Court of Appeals for the Ninth Circuit.

In an order issued in August 2007, the Court of Appeals remanded the proceeding back to the FERC.  The Court of Appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.  The Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued.  The FERC has yet to act on this order on remand; currently, certain motions concerning procedures on remand are pending before the FERC.

FERC Audit of Wholesale FCA — In October 2009, the FERC notified NSP-Minnesota and NSP-Wisconsin that the FERC audit division began an audit of compliance with the FERC’s accounting and reporting regulations related to the calculation of the NSP-Minnesota and NSP-Wisconsin wholesale FCA for the period commencing Jan. 1, 2008.

FERC Audit of Transmission Incentives Compliance — In December 2007, the FERC granted NSP-Minnesota and NSP-Wisconsin approval to recover a return on CWIP on their investments in the BRIGO, Chisago, Minn. to Apple River, Wis. and CapX2020 transmission projects.  The incentives are recovered through MISO transmission rates.  In December 2010, the FERC notified NSP-Minnesota and NSP-Wisconsin that the FERC audit division is beginning an audit of their compliance with the FERC’s rules and orders related to collection of wholesale transmission investment incentives commencing December 2007.

Electric Operating Statistics

NATURAL GAS UTILITY OPERATIONS

Natural Gas Utility Trends

The most significant developments in the natural gas operations of the utility subsidiaries are continued volatility in natural gas market prices, safety requirements for natural gas pipelines and the continued trend of declining use per residential customer, as well as small commercial and industrial customers (C&I), as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 2000 to 2010, average annual sales to the typical residential customer declined from 96 MMBtu per year to 82 MMBtu per year and to a typical small C&I customer declined from 441 MMBtu per year to 394 MMBtu per year, 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.

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 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.

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.  The annual difference between the natural gas cost revenues collected through PGA rates and the actual natural gas costs are 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.

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5 percent of Minnesota natural gas revenue on conservation improvement programs in the state of Minnesota.  These costs were recovered from Minnesota customers through an annual cost-recovery mechanism for natural gas conservation and energy management program expenditures.  In 2010, this law changed to an energy savings-based requirement, and the costs of conservation improvement programs will continue to be recoverable in Minnesota through a rate adjustment mechanism.

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 689,223 MMBtu for 2010, which occurred on Dec. 13, 2010.

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 585,598 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 32 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.  The 2009-2010 and 2010-2011 entitlement levels are pending MPUC action.

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.  This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

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:

The cost of natural gas supply, transportation service and storage service is recovered through the PGA cost-recovery mechanism.

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2011 through 2029.

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, 2010, NSP-Minnesota was committed to approximately $524 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 29 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

See Item 7 for further discussion of natural gas 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 changes in the actual cost of natural gas and transportation and storage services.  The PSCW has the authority to disallow certain costs if it finds the utility 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 146,018 MMBtu for 2010, which occurred on Dec. 14, 2010.

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 134,736 MMBtu per day.  In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services.  These storage agreements provide storage for approximately 27 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 2010-2011 supply plan was approved by the PSCW in October 2010.

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.  This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

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:

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 2011 through 2032.

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, 2010, NSP-Wisconsin was committed to approximately $114 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 12 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

See Item 7 for further discussion of natural gas 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 also subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.  PSCo is subject to the DOT and CPUC with regards to pipeline safety compliance.

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

●

GCA — The GCA mechanism allows PSCo to recover its actual costs of purchased gas and transportation to meet the requirements of its customers.  The GCA is revised quarterly to allow for changes in gas rates.

●

DSMCA — PSCo has a low-income energy assistance program.  The costs of this energy conservation and weatherization program are recovered through the gas DSMCA.

●

PDRA — The PDRA recovers revenue lost to decreasing use per customer beyond a threshold.  No revenue is currently recovered through this clause.

PBRP and QSP Requirements — The CPUC established a natural gas QSP.  This regulatory plan includes 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 through 2012.  PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP.  In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP.  The CPUC conducts proceedings to review and approve these rate adjustments annually.