Northern States Power 10-K 2009 FY Annual report

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, 2009

Or

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

Commission file number 001-31387

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

Minnesota	41-1967505
State or other jurisdiction of	(I.R.S. Employer
Incorporation or organization	Identification No.)

414 Nicollet Mall, Minneapolis, Minnesota  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:  None

Securities registered pursuant to section 12(g) of the Act:  Common Stock

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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  o 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.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o	Accelerated filer o
Non-accelerated filer x	Smaller Reporting Company o
(Do not check if a 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 March 1, 2010, 1,000,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2010 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

Northern States Power Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

INDEX

PART I
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	7
ELECTRIC UTILITY OPERATIONS	7
Overview	7
Public Utility Regulation	8
Capacity and Demand	9
Energy Sources and Related Transmission Initiatives	9
Fuel Supply and Costs	13
Fuel Sources	13
Wholesale Commodity Marketing Operations	14
Summary of Recent Federal Regulatory Developments	14
Electric Operating Statistics	16
NATURAL GAS UTILITY OPERATIONS	17
Public Utility Regulation	17
Capability and Demand	17
Natural Gas Supply and Costs	18
Natural Gas Operating Statistics	19
ENVIRONMENTAL MATTERS	19
EMPLOYEES	19
Item 1A — Risk Factors	20
Item 1B — Unresolved Staff Comments	27
Item 2 — Properties	28
Item 3 — Legal Proceedings	29
Item 4 — Reserved	29
PART II
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6 — Selected Financial Data	29
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	33
Item 8 — Financial Statements and Supplementary Data	36
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A — Controls and Procedures	86
Item 9B — Other Information	86
PART III
Item 10 — Directors, Executive Officers and Corporate Governance	87
Item 11 — Executive Compensation	87
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	87
Item 13 — Certain Relationships and Related Transactions, and Director Independence	87
Item 14 — Principal Accountant Fees and Services	87
PART IV
Item 15 — Exhibits and Financial Statement Schedules	87
SIGNATURES	92

This Form 10-K is filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota).  NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U. S. Securities and Exchange Commission (SEC).  This report should be read in its entirety.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates
NMC	Nuclear Management Company, LLC a wholly owned subsidiary of NSP Nuclear Corporation
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
SPS	Southwestern Public Service Company, a New Mexico corporation
utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy	Xcel Energy Inc., a Minnesota corporation
Federal and State Regulatory Agencies
ASLB	Atomic Safety and Licensing Board
DOE	United States Department of Energy
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
MPCA	Minnesota Pollution Control Agency
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.
NERC	North American Electric Reliability Corporation. A self-regulatory organization, subject to oversight by the U. S. FERC and government authorities in Canada, to develop and enforce reliability standards.
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.
NRC	Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
OES	Office of Energy Security, Minnesota Department of Commerce.
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.
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
DSM	Demand side management. Energy conservation, weatherization, and other programs to conserve or manage energy use by customers.
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.

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PGA	Purchased gas adjustment. A clause included in NSP-Minnesota’s retail gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. 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.
RES	Renewable energy standard
SEP	State Energy Policy
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 was approved by the MPUC in 2006 to be effective in 2007, and will be revised annually as new transmission investments and costs are incurred.
Other Terms and Abbreviations
ACES	American Clean Energy and Security Act
AEP	American Electric Power
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.
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
BACT	Best Available Control Technology
BART	Best Available Retrofit Technology
CO2	Carbon dioxide
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CapX 2020	An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
Codification	FASB Accounting Standards Codification
CON	Certificate of need
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.
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

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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
JOA	Joint operating agreement among the utility subsidiaries
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.
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
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.
NOx	Nitrogen oxide
nonutility	All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
O&M	Operating and maintenance
OCI	Other comprehensive income
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	Pennsylvania-New Jersey-Maryland Interconnection
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
RPS	Renewable Portfolio Standard, 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.
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services
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.
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.

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Measurements
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.
Bcf	Billion cubic feet
KV	Kilovolts (one KV equals on the thousand volts)
KW	Kilowatts (one KW equals one thousand watts)
Kwh	Kilowatt hours
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.

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COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota.  NSP-Minnesota is an operating utility 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 10 percent of its total sales in 2009.  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 2009.  Generally, NSP-Minnesota’s earnings range from approximately 40 percent to 50 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 Co., which holds real estate; and NSP Nuclear Corp., which owns NMC.

NSP-Minnesota conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other.  Comparative segment revenues and related financial information for fiscal 2009, 2008 and 2007 are set forth in Note 17 to the accompanying consolidated financial statements.

NSP-Minnesota focuses on growing through investments in electric and natural gas rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers.  NSP-Minnesota files periodic rate cases, 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.

ELECTRIC UTILITY OPERATIONS

Overview

Climate Change and Clean Energy — Like most other utilities, NSP-Minnesota is 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.  NSP-Minnesota is subject to state RPS requirements which we believe they will be in a position to achieve by the applicable state deadlines. Although the exact form and design of any federal RPS policy is uncertain at this time, we believe that we will be well-positioned to meet a federal standard as well, although the ultimate design of any federal policy could have a varied impact on NSP-Minnesota depending upon the energy efficiency and other standards imposed.  In addition, NSP-Minnesota’s electric generating facilities have been and are likely to be further subject to climate change legislation introduced at either the state or federal level within the next few years.  In 2009, the EPA took a number of steps toward the regulation of GHGs under the CAA.  By spring 2010, the EPA expects to promulgate regulations to control GHGs from mobile sources.   Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.

While NSP-Minnesota is not currently subject to state or federal limits on its GHG emissions, NSP-Minnesota has undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions.  These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects.  Although the impact of climate change policy on NSP-Minnesota will depend on the specifics of state and federal policies, legislation and regulation, NSP-Minnesota believes that, based on prior state commission practice, NSP-Minnesota would be granted the authority to recover the cost of these initiatives through rates.

Utility Restructuring and Retail Competition — The FERC has continued with its efforts to promote more competitive wholesale markets through open-access transmission and other means.  As a consequence, NSP-Minnesota can purchase 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.  In 2008, the FERC approved a MISO proposal to begin operation of a regional ASM in January 2009.

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The FERC has approved the open access transmission planning processes for the MISO, the RTO serving the NSP System.  NSP-Minnesota received MPUC approval in 2008 to construct three new 115 KV transmission lines in 2009 to deliver additional wind generation even if NSP-Minnesota does not purchase the generation.  Several additional transmission expansion projects are pending final MPUC action, including the CapX 2020 expansion.

The retail electric business faces competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electricity.  In 2009, FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota unless the applicable state regulatory authority prohibits ARCs from serving retail customers in its state.  See further discussion in Public Utility Regulation below.  In addition, customers may have the option of substituting other fuels, such as natural gas or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  While NSP-Minnesota faces these challenges, it believes its rates are competitive with currently available alternatives.

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 has regulatory authority over aspects of NSP-Minnesota’s financial activities, including 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.

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 and certain natural gas transactions in interstate commerce.  NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see 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 invests in 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 to support development of renewable energy projects research and development of renewable energy technologies.

·RES — In 2007, the Minnesota legislature passed new requirements mandating that a certain percent of energy produced by utilities like NSP-Minnesota come from renewable resources.  In order to ensure these mandates can be met, the legislature allows utilities to recover the costs of new renewable generation projects to meet the RES in a rider.

·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 system necessary to deliver electric energy to customers.

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.

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NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue on conservation improvement programs.  These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.  NSP-Minnesota is required to request a new cost-recovery level annually.  While this law changed to a savings-based requirement beginning in 2010, the costs of providing qualified conservation improvement programs will continue to be recoverable through a rate adjustment mechanism.

MERP Rider Regulation — The MPUC approved a rate rider to recover prudent costs to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant beginning Jan. 1, 2006.  A. S. King, High Bridge and Riverside went into service in July 2007, May 2008 and March 2009, respectively.  In December 2009, the MPUC authorized the recovery of approximately $116.7 million in 2010 rates.  The ROE for the A. S. King plant, the High Bridge plant and the Riverside plant, is 10.55 percent, 11.22 percent and 10.55 percent, respectively.  The MERP projects will be included in rate base in the next general rate case and the projects removed from the rider.

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 2010, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2007	2008	2009	2010 Forecast
NSP System	9,427	8,697	8,615	9,280

The peak demand for the NSP System typically occurs in the summer.  The 2009 uninterrupted system peak demand for the NSP System occurred on June 23, 2009.

Energy Sources and Related Transmission Initiatives

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

Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and 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 from a particular generating source and a charge for the associated energy actually purchased from such generating source.

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 contractual arrangements with MISO and regional transmission service providers to deliver power and energy to the NSP System for native load customers, which are retail and wholesale load obligations with terms of more than one year.

Excelsior Energy — In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project.  The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior’s petition.  The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.

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In its August 2007 Phase 1 order, the MPUC, found among other things, that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the OES and the guidance provided by the order.

In May 2009, the MPUC affirmed its previous order to deny Excelsior Energy’s Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC generating facility, which closed the docket.  In August 2009, Excelsior appealed the MPUC decision to the Minnesota Court of Appeals.  The Minnesota Court of Appeals heard arguments on Feb. 23, 2010, and a decision is anticipated in 2010.

GHG Emissions — The 2007 Minnesota legislature adopted the goal to reduce statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, to a level at least 30 percent below 2005 levels by 2025, and to a level at least 80 percent below 2005 levels by 2050.

The legislation also prohibits the construction within Minnesota of a new large energy facility, the import or commitment to import from outside Minnesota power from a new large energy facility, or entering into a new long-term power purchase agreement that would increase statewide power sector CO2 emissions.  The statute does not impose limitations on CO2 or other GHG emissions on NSP-Minnesota and provides for certain exemptions.

In November 2008, the MPUC approved NSP-Minnesota’s request to include the costs of a natural gas cast iron pipe replacement project in its SEP Rider.  The proposed cost recovery was enabled by the 2007 legislation, as the pipe replacement is expected to reduce GHG emissions.  NSP-Minnesota expects to recover approximately $1.4 million over the 2009-2013 period, when the project is scheduled to be complete.

2009 Minnesota Legislative Session — The 2009 Minnesota legislature considered and adopted several measures related to energy policy and regulation, including:

·Permitting enhanced recovery for costs associated with the urban central corridor development;

·Encouraging the development of solar resources; and

·Continued encouragement of DSM.

The legislature considered, but did not adopt, increased taxes on utility property.

Minnesota Resource Plan— In July 2009, the MPUC approved NSP-Minnesota’s 2007 resource plan.  The plan would reduce CO2emissions by 22 percent from 2005 to 2020, a 6 million ton reduction. The plan includes the following components:

·Energy efficiency savings of 1.15 percent in 2010, 1.2 percent in 2011 and 1.3 percent in 2012;

·Install sufficient renewables to meet the Minnesota RES;

·Obtain required approvals to extend the life of the Prairie Island nuclear plant and to increase the output at both Prairie Island and Monticello;

·Continue ongoing capacity expansion at Sherco Unit 3;

·Continue to investigate repowering Black Dog Units 3 and 4, and provide the MPUC with specific plans and timelines for the repowering;

·Obtain approval for the 375 MW intermediate and 350 MW diversity exchange with Manitoba Hydro beginning in 2015; and

·Continue to ensure sufficient transmission available to deliver generation to load.

Additionally, the MPUC required NSP-Minnesota to consider higher levels of DSM and energy efficiency and provide recommendations in NSP-Minnesota’s next resource plan, which is to be filed no later than Aug. 1, 2010.

RES — In 2007, the Minnesota legislature changed the state’s renewable energy objective into a standard that requires NSP-Minnesota to generate or cause to be generated electricity from renewable resources equaling:

·At least 15 percent of its retail sales by 2010;

·18 percent of retail sales by 2012;

·25 percent of retail sales by 2016; and

·30 percent by 2020.

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Of the 30 percent, at least 25 percent must be generated by wind energy conversion systems and the remaining five percent by other eligible energy technology.  The law allows for a modification or delay in the implementation of the standard if the implementation would cause significant rate impact, require significant measures to address reliability or raises significant technical issues.  All other Minnesota utilities are required to meet a 25 percent RES by 2025.  No Minnesota utility has requested a modification or delay of the standard at this time.

Minnesota Statutes also allow for recovery of eligible renewable energy investments through a cost recovery rider.  NSP-Minnesota began recovering eligible investments through this mechanism in 2008.

Wind Generation — NSP-Minnesota is investing approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project.  These projects are expected to be operational by the end of 2010 and 2011, respectively.  In June 2009, the MPUC approved the Nobles and Merricourt Wind Projects.  In August 2009, the NDPSC granted advanced determinations of prudence for the Nobles and Merricourt Wind Projects and a certificate of public convenience and necessity (CPCN) for the Merricourt Wind project.

NSP-Minnesota Transmission CONs — In April 2009, the MPUC granted a CON to construct three 345 KV electric transmission lines as part of the CapX 2020 project.  The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion.  The cost of the project to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million.  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 September 2009, two intervenors appealed the MPUC’s CON decisions in the Minnesota Court of Appeals.

As part of the regulatory process for the CapX 2020 345 KV projects, NSP-Minnesota and Great River Energy have filed four route permit applications with the MPUC.  Route permit applications for the remaining parts of the three lines are expected to be filed in adjoining states in 2010.  Three filed route permit applications are now in evidentiary hearing processes before ALJs.  The fourth application is expected to be sent to an evidentiary hearing process later in 2010.  NSP-Minnesota anticipates the first routing decisions in mid 2010.

As part of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and Great River Energy) filed a CON application in March 2008 for a 230 KV transmission line between Bemidji and Grand Rapids, Minn.  The CON application was approved in July 2009.  Route hearings are scheduled to begin March 30, 2010, and an MPUC decision is anticipated by the third quarter of 2010.  The Bemidji-Grand Rapids line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million, with construction to be completed by the end of 2011.  The estimated cost to NSP-Minnesota is approximately $26 million.

ARCs — In 2009, the FERC adopted rules requiring MISO to allow ARCs to offer demand response aggregation services to end-use customers in the states served by NSP-Minnesota, 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-Minnesota.  The MISO ARC tariff provisions are effective in June 2010.  The MPUC has opened an investigation regarding possible operation of ARCs in Minnesota.  NSP-Minnesota expects to file requests with the NDPSC and SDPUC by the end of the first quarter of 2010 asking the regulatory agencies to prohibit operations of ARCs in their respective states, and to take action prior to June 2010.

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.

Mercury Reduction and Emissions Reduction Filings — The MPUC has approved mercury control plans for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants.  A sorbent injection control system was put into service at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled to be completed in December 2010.  Currently, the estimated project costs are approximately $6.6 million for these two units, and the MPUC authorized NSP-Minnesota to collect the 2010 revenue requirement associated with these projects, which is approximately $3.5 million, from customers through a mercury rider in 2010.  On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and MPCA.  Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost rider.

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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 additional discussion regarding the nuclear generating plants in Note 15 to the consolidated financial statements.

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 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.  NSP-Minnesota is also able to utilize the Clive facility through various LLW processors.  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, if off-site LLW disposal facilities were not available.

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.  To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel.  See Item 3 — Legal Proceedings and Note 15 to the consolidated financial statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.  At the following dates casks for storage were either authorized or casks were loaded and stored:

·In 2003, the Minnesota legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the Prairie Island nuclear plant and to store spent fuel there until its current licenses with the NRC expire in 2013 and 2014.  It is estimated that operation through the end of the current license will require 29 storage casks at Prairie Island.

·In October 2006, effective June 2007, the MPUC authorized an on-site storage facility and dry cask storage of 30 casks at Monticello, which will allow the plant to operate to 2030.

·In December 2009, the MPUC authorized additional cask storage at Prairie Island to allow operation through 2033 for Unit 1 and 2034 for Unit 2.  The MPUC decision is currently stayed to allow the Minnesota legislature the opportunity to review the MPUC decision during the 2010 legislative session.  If no action is taken by the Minnesota legislature during the 2010 legislative session the MPUC order will go into effect on June 1, 2010.

·As of Dec. 31, 2009, there were 25 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant.

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 December 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 September 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 July 2007, PFS and the Skull Valley Band filed a lawsuit challenging these two Departments of the Interior 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 Xcel Energy’s and other nuclear reactor sites.

Nuclear Plant Power Uprates and Life Extension — NSP-Minnesota is pursuing life extensions and capacity increases of all three of its nuclear units that will total approximately 235 MW, if approved, between 2011 and 2015.  The life extension and a capacity increase for Prairie Island Unit 2 is contingent on the replacement of the original steam generators, currently planned for replacement during the refueling outage in 2013.  Capital investments for life cycle management and power uprate activities through 2009 have totaled over approximately $257 million.  For the years 2010 through 2015, spending is estimated at over $1.0 billion.

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In December 2008, the MPUC approved the Monticello CON for approximately 71 MW of power uprates.  In 2008, NSP-Minnesota re-submitted its NRC application for the Monticello plant extended power uprate, and the NRC’s sufficiency review of the license amendment re-submittal was completed.  NSP-Minnesota expects to receive NRC approval and achieve the extended power uprate during 2011.  The operating life of the Monticello nuclear plant has already been extended through 2030.

In December 2009, the MPUC approved both the additional dry spent fuel storage capacity to support life extension and the approximately 164 MW of power uprates at Prairie Island Units 1 and 2.  If no action is taken by the Minnesota legislature during the 2010 legislative session, the MPUC decision on dry spent fuel storage capacity to support life extension will go into effect on June 1, 2010.

In April 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 PIIC filed contentions in the NRC’s license renewal proceeding in August 2008, which was referred to an ASLB for review.  The ASLB granted the PIIC hearing request and has admitted seven of the 11 contentions filed.  To date, all seven admitted contentions have been resolved and removed from the ASLB docket.  Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions.  The ASLB has admitted one of the contentions and has not issued a decision on the other three.  NSP-Minnesota is challenging the admitted contention, and a decision on whether the other contentions will be accepted will be made in early 2010.  If the contentions are not resolved, the resulting adjudicatory process is expected to add approximately eight months onto the NRC’s standard 22 month review schedule, resulting in a decision on the Prairie Island license renewal in late 2010.

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.

													Weighted
	Coal*				Nuclear				Natural Gas				Average
NSP System Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent		Fuel Cost
2009	$	1.78	57	%	$	0.70	39	%	$	7.36	4	%	$	1.61
2008	1.73		58		0.56		39		10.09		3		1.55
2007	1.56		57		0.51		38		7.60		4		1.47

*  Includes refuse-derived fuel and wood

See additional discussion of fuel supply and costs under Item 1A — Risks Associated with Our Business.

Fuel Sources

Coal — The NSP System normally maintains approximately 40 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2009 and 2008, were approximately 43 and 49 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 10.2 and 11.0 million tons per year at Dec. 31, 2009 and 2008, respectively.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 91 percent of their coal requirements in 2010, 60 percent of their coal requirements in 2011 and 14 percent of their coal requirements in 2012.  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 in 2010, 28 percent of their coal requirements in 2011 and 28 percent of their coal requirements 2012.  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 — NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication for the operation of its nuclear generation plants.  The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium, conversion and enrichment with multiple producers to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

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·Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2010, approximately 85 percent of the requirements for 2011 through 2014, and 49 percent of the requirements for 2015 through 2017, with no arrangements for 2018 and beyond.  Contracts for additional uranium concentrate supplies are currently in various stages of negotiations 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 and approximately 70 percent of the requirements from 2012 through 2016, with no arrangements for 2017 and beyond.  Contracts for additional conversion services are being evaluated and negotiated to provide a portion of remaining open requirements for 2014 and beyond.

·Current enrichment services contracts cover 100 percent of 2010 through 2013 requirements.  Contracts for additional enrichment services are being evaluated and negotiated to provide a portion of the remaining open requirements for 2014 and beyond.

·Fabrication services for Monticello are covered through 2011.  Responses from the fuel fabrication vendors to our RFPs for additional supply for Monticello are being reviewed with plans to enter into a contract with one of the vendors in 2010. Prairie Island’s fuel fabrication is 100 percent committed through 2014.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants.   Some exposure to price volatility will remain, due to index-based pricing structures on the 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 2010 to 2028.  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, 2009, NSP-Minnesota’s commitments related to supply contracts were $53 million and commitments related to transportation and storage contracts were approximately $538 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 reduce commodity price and credit risk and hedge supplies and purchases.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

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, including 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 a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — 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.

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

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Electric Reliability Standards Compliance

Compliance Audits

NSP-Minnesota and NSP-Wisconsin share all NSP System generation and transmission costs by means of a FERC-approved tariff commonly referred to as the Interchange Agreement.  In 2008, the NSP System filed self-reports with the Midwest Reliability Organization (MRO) regional entity relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain critical infrastructure protection standards.  In 2009, the NSP System reached agreement with the MRO that would resolve all open audit findings and self reports by payment of a non-material penalty.  Xcel Energy, the parent company of NSP-Minnesota and NSP-Wisconsin, is in the process of developing a definitive settlement agreement.  The settlement agreement will be subject to NERC and FERC approval.

MRO/NERC Compliance Investigation

On Sept. 18, 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 September 2007 event.  Because the event affected more than one region, the NERC took over the investigation.  In January 2010, the NERC issued a preliminary 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.  Xcel Energy disagrees with many aspects of the preliminary report and filed its response with NERC on Feb. 19, 2010.  The final outcome of the NERC compliance investigation, and whether and to what extent penalties for violations may be assessed, is unknown at this time.

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.  Each RTO separately files regional transmission tariff rates for approval by the FERC.  All members within that RTO are then subjected to those rates.

Centralized Regional Wholesale Markets — The FERC rules allow RTOs to operate centralized regional wholesale energy markets.  In April 2005, MISO began operation of a Day 2 regional day-ahead and real time wholesale energy market.  The Day 2 market is designed to provide more efficient generation dispatch over the 15 state MISO region, including the NSP System.  In 2007, SPP began operation of an energy imbalance service (EIS) market, which provides a more limited wholesale energy balancing market for the region that includes the SPS system.

In January 2009, MISO began ASM operations, which provide further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2 energy market.

Market Based Rate Rules — Each of the Xcel Energy utility subsidiaries has been granted market-based rate authority.  Under market based rate rules, the NSP System was reauthorized to sell at market-based rates in June 2009.

On Dec. 22, 2008, the NSP System submitted their Triennial Market Power Analysis to the FERC to support their market-based rate authority.  Applying the FERC’s required tests, the Market Power Analysis submitted by the NSP System demonstrates that they have neither horizontal market power nor vertical market power in the relevant geographic market.  Consequently, the NSP System has requested that the FERC permit them to retain their market-based rate authority.

MISO Long-Term Transmission Pricing — Transmission service rates in the MISO region have historically used a rate design in which the transmission cost depends on the location of the load being served, which is referred to as license plate rates.  Costs of existing transmission facilities are thus not regionalized.  MISO has implemented several changes regarding the allocation of costs for new transmission facilities.  In 2006 and 2007, the FERC issued orders accepting the so-called RECB tariff, which provide a 20 percent limitation on the portion of transmission expansion costs that may be regionalized and recovered from all loads in the 15 state MISO region.

In 2007, AEP filed a proposal that would regionalize certain costs of the existing AEP system over the MISO and PJM RTO regions.  The AEP proposal would shift several million dollars in transmission costs annually to the NSP System.  The impact of the AEP proposal on transmission cost allocation in MISO is uncertain.

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In July 2009, MISO filed a proposed change to the RECB tariff with the FERC to address concerns regarding allocation of costs associated with new transmission required to deliver new wind generation.  This tariff would regionalize 10 percent of the cost of new 345 KV transmission facilities associated with new generation interconnections across transmission users in MISO, with the interconnecting generator paying the remaining 90 percent of the costs.  The generator is required to fund 100 percent of the costs for facilities less than 345 KV.  The FERC approved the tariff change in October 2009, subject to a permanent replacement cost allocation tariff to be filed with the FERC in July 2010.  The uncertainty surrounding allocation of costs associated with wind generation interconnection could affect the timing or location of such interconnections, which could affect near term NSP System transmission investment needs.

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.  The audit is a periodic financial audit, and NSP-Minnesota is fully cooperating with the audit.

Electric Operating Statistics

	Year Ended Dec. 31,
	2009			2008			2007
Electric sales (Millions of Kwh)
Residential	9,887			10,099			10,534
Commercial and industrial	24,603			25,847			25,844
Public authorities and other	265			260			275
Total retail	34,755			36,206			36,653
Sales for resale	3,899			3,692			4,073
Total energy sold	38,654			39,898			40,726
Number of customers at end of period
Residential	1,231,752			1,227,889			1,218,340
Commercial and industrial	149,187			148,060			146,487
Public authorities and other	6,055			6,067			6,072
Total retail	1,386,994			1,382,016			1,370,899
Wholesale	16			31			31
Total customers	1,387,010			1,382,047			1,370,930
Electric revenues (Thousands of Dollars)
Residential	$	1,006,380		$	1,018,810		$	1,015,315
Commercial and industrial	1,739,992			1,853,451			1,774,027
Public authorities and other	31,981			31,837			31,446
Total retail	2,778,353			2,904,098			2,820,788
Wholesale	102,786			180,618			198,248
Interchange revenues from NSP-Wisconsin	389,023			390,143			372,215
Other electric revenues	137,111			109,250			85,423
Total electric revenues	$	3,407,273		$	3,584,109		$	3,476,674
Kwh sales per retail customer	25,058			26,198			26,737
Revenue per retail customer	$	2,003		$	2,101		$	2,058
Residential revenue per Kwh	10.18		¢	10.09		¢	9.64		¢
Commercial and industrial revenue per Kwh	7.07			7.17			6.86
Wholesale revenue per Kwh	2.64			4.89			4.87

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NATURAL GAS UTILITY OPERATIONS

The most significant recent developments in the natural gas operations of NSP-Minnesota are continued volatility in natural gas market prices and the continued trend of declining use per customer by residential customers, as well as small commercial and industrial (C&I) customers, as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 1999 to 2009, average annual sales to the typical residential customer declined from 108 MMBtu per year to 87 MMBtu per year, and to a typical small C&I customer declined from 516 MMBtu to 355 MMBtu per year, on a weather-normalized basis.  Although recent wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

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 aspects of NSP-Minnesota’s financial activities, including 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.

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 are recovered from Minnesota customers through an annual cost-recovery mechanism for natural gas conservation and energy management program expenditures.  This law will change to an energy savings-based requirement beginning in 2010, and the costs of conservation improvement programs will continue to be recoverable in Minnesota through a rate adjustment mechanism.

For a further discussion of rate and regulatory matters see Note 13 to the consolidated financial statements.

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 720,983 MMBtu for 2009, which occurred on Jan. 15, 2009.

NSP-Minnesota purchases natural gas from independent suppliers.  These purchases are generally priced 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 589,492 MMBtu per day.  In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services.  These storage 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 32 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 2008-2009 and 2009-2010 entitlement levels are pending MPUC action.

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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:

2009	$	5.78
2008	8.41
2007	7.67

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 2010 through 2027.

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, 2009, NSP-Minnesota was committed to approximately $637 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 31 domestic suppliers and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

Other

Minnesota Office of Pipeline Safety (MnOPS)-Notice of Probable Violation (NPV) — On Feb. 1, 2010, a plumber working to clear a sewer line at a residence in St. Paul, Minn. struck a gas line, which ignited a fire that destroyed the house.  The plumber received minor burns, was treated and released that night, and no other injuries resulted.  An investigation revealed that the gas line to the house had penetrated and intersected the sewer line to the home.  On Feb. 5, 2010, MnOPS delivered an NPV to NSP-Minnesota. The NPV states that NSP-Minnesota failed to take appropriate measures to prevent this accident from occurring in violation of state and federal regulations.  The NPV also sets forth a four-part proposed compliance plan and a $1 million fine. The compliance order requires, among other things, that NSP-Minnesota submit an inspection and remediation plan. NSP-Minnesota subsequently investigated the sewer lines in the vicinity of the accident and determined that no additional conflicts exist. NSP-Minnesota intends to respond to the NPV on March 8, 2010.

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Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2009			2008			2007
Natural gas deliveries (Thousands of MMBtu)
Residential	39,329			41,589			38,024
Commercial and industrial	40,408			42,640			40,184
Other	320			529			2,276
Total retail	80,057			84,758			80,484
Transportation and other	12,618			12,484			8,528
Total deliveries	92,675			97,242			89,012
Number of customers at end of period
Residential	437,517			434,987			430,048
Commercial and industrial	40,468			40,174			39,570
Total retail	477,985			475,161			469,618
Transportation and other	15			15			14
Total customers	478,000			475,176			469,632
Natural gas revenues (Thousands of Dollars)
Residential	$	347,348		$	467,751		$	413,790
Commercial and industrial	283,953			413,871			350,640
Total retail	631,301			881,622			764,430
Transportation and other	9,022			8,336			12,541
Total natural gas revenues	$	640,323		$	889,958		$	776,971
MMBtu sales per retail customer	167.49			178.38			171.38
Revenue per retail customer	$	1,321		$	1,855		$	1,628
Residential revenue per MMBtu	8.83		¢	11.25		¢	10.88		¢
Commercial and industrial revenue per MMBtu	7.03			9.71			8.73
Transportation and other per MMBtu	0.72			0.67			1.47

ENVIRONMENTAL MATTERS

NSP-Minnesota’s facilities are regulated by federal and state environmental agencies.  These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances.  Various company activities require registrations, permits, licenses, inspections and approvals from these agencies.  NSP-Minnesota has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.  NSP-Minnesota facilities have been designed and constructed to operate in compliance with applicable environmental standards.

NSP-Minnesota strives to comply with all environmental regulations applicable to its operations.  However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have upon NSP-Minnesota’s operations.  For more information on environmental contingencies, see Notes 14 and 15 to the consolidated financial statements.

EMPLOYEES

The number of full-time NSP-Minnesota employees at Dec. 31, 2009 and 2008 was 3,763 and 3,637, respectively.  Of these full-time employees, 2,341 or 62 percent and 2,279, or 63 percent, respectively, are covered under collective bargaining agreements.  See Note 8 to the consolidated financial statements for further discussion of the bargaining agreements.  Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to NSP-Minnesota and are not considered in the above amounts.

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Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes NSP-Minnesota, is to understand and manage material risk; management is responsible for identifying and managing the risks, while directors oversee and hold management accountable.  Our risk management process has three parts: identification and analysis, management and mitigation, and communication and disclosure.  Our management identifies and analyzes risks to determine materiality and other attributes like timing, probability and controllability. 

Management broadly considers our business, the utility industry, the domestic and global economy, and the environment to identify risks.  Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the securities disclosure process, the hazard risk management process, and internal auditing and compliance with financial and operational controls.  Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy.  At the same time, the business planning process identifies areas where a business area may take inappropriate risk to meet goals.

The goal of the risk management process is to mitigate the risks inherent in the implementation of Xcel Energy’s and NSP-Minnesota’s strategy.  The process for risk management and mitigation includes our code of conduct and other compliance policies, formal structures and groups, and overall business management.  At a threshold level, we have developed a robust compliance program and promotes a culture of compliance, which mitigates risk.  In addition to the code of conduct, we have a robust compliance program, including policies, training and reporting options. 

Building on the culture of compliance, we manage and mitigate risks through formal structures and groups, including management councils, risk committees, and the services of corporate areas such as internal audit, the corporate controller and legal services.  While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas. 

We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2 and risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for our products and services.  Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy’s and NSP-Minnesota’s senior management.

Management provides information to the Xcel Energy’s Board in presentations and communications over the course of the Board calendar.  Senior management presents an assessment of key risks to the Board annually.  The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability.  Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy’s and NSP-Minnesota’s strategy.  

The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees.  The standing committees also oversee risk management as part of their charters.  Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk.  The Xcel Energy Board has overall responsibility for risk oversight.  As described above, the Board reviews the key risk assessment process presented by senior management.  This key risk assessment analyzes the most likely areas of future risk to Xcel Energy.  The Xcel Energy Board also reviews the performance and annual goals of each business area.  This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy.

Risks Associated with Our Business

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

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

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Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations.  We currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of our costs incurred in a test year.  Thus, the rates we are allowed to charge may or may not match our costs at any given time.  While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.  Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.  Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.  If all of our costs are not recovered through customer rates, we could incur financial operating losses, which, over the long term, could jeopardize our ability to meet our financial obligations.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place.  However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

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

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.  In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.  For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchase power contracts.  An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowing costs.

We are subject to interest rate risk.

If interest rates increase, we may incur increased interest expense on variable interest rate debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.

We are subject to capital market risk.

Our operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt markets.  Any disruption in capital markets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and are impacted by numerous events throughout the world economy.  Capital market disruption events, such as the collapse in the U. S. sub-prime mortgage market and subsequent broad financial market stress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.  Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily.  Additional margin requirements could impact our liquidity.

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

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

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility.  Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.

If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers.  The impact of these cost and reliability issues depends on unique operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.  These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination.  At Dec. 31, 2009, these sites included:

��

·Sites of former MGPs operated by us, our predecessors, or other entities; and

·Third party sites, such as landfills, for which we are alleged to be a potentially responsible party that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings.  These mandates are designed in part to mitigate the potential environmental impacts of utility operations.  Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us, including but not limited to regulation of mercury, NOx, SO2, CO2, particulates and coal ash.  We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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We are subject to physical and financial risks associated with climate change.

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk.  Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events.  We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.  Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.  Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues.  We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.  Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur.  We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so.  To the extent the frequency of extreme weather events increases, this could increase our cost of providing service.  Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy.  We may not recover all costs related to mitigating these physical and financial risks.

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

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

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk.  Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs.  Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress.  Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA.  On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare and that motor vehicle emissions contribute to the GHGs in the atmosphere.  This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles.  The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.  Xcel Energy, our parent company, is also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 14, Commitments and Contingent Liabilities, in our notes to the consolidated financial statements.  While Xcel Energy believes such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages.  Defense costs associated with such litigation can also be significant.  Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

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Many of the federal and state climate change legislative proposals, such as ACES, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap.  Under the proposals, the cap becomes more stringent with the passage of time.  The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year.  The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations.  Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions.  There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted.  The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices.  While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations.  Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not recover all costs related to complying with regulatory requirements imposed on us.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

For further discussion, see Note 14 to the consolidated financial statements.

We are subject to the risks of nuclear generation.

Our two nuclear stations, Prairie Island and Monticello, subject us to the risks of nuclear generation, which include:

·The risks associated with storage, handling and disposal of radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

·Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

·Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of licensed lives.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised NRC safety requirements could necessitate substantial capital expenditures at our nuclear plants.  In addition, the Institute for Nuclear Power Operations (INPO) reviews our nuclear operations and nuclear generation facilities. Compliance with INPO recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

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

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions.  The consequences of a prolonged recession may include a lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets.  A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth.  Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, and may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.  It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur.  See credit risk section for more related information.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies.  Additionally, the cost of those commodities may be higher than expected.

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

On a periodic basis, or as needed, our utility operations file long-term resource plans with our regulators.  These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer response and continuation of the existing utility business model.  Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide.  This could lead to under recovery of costs or insufficient resources to meet customer demand.

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business.  While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, including our nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel.  We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to implement the NERC critical infrastructure protection standards as they are implemented and clarified.

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

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

We are subject to business continuity risks associated with our ability to respond to unforeseen events.

The term business continuity refers to the ability of an entity to maintain day-to-day operations in response to unforeseen events.  While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations.  The company’s response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm’s on going business operations.

Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results.  It’s difficult to predict the magnitude of such events and associated impacts.

We are subject to information security risks.

A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information.  We are unable to quantify the potential impact of such an event.

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Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful.  In addition, higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on our results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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

Our electric and natural gas utility businesses are seasonal businesses, and weather patterns can have a material impact on our operating performance.  Demand for electricity is often greater in the summer and winter months associated with cooling and heating.  Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season.  Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.  Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.

Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.

There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.  For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased the FERC’s civil penalty authority for violation of FERC statutes, rules and orders.  The FERC can now impose penalties of $1 million per violation per day.  In addition, more than 120 electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by NERC or FERC for violations.  If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

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

We have defined benefit pension and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  Therefore, our funding requirements and related contributions may change in the future.

Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

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As we are a subsidiary of Xcel Energy, we may be negatively affected by events at Xcel Energy and its affiliates.  If Xcel Energy were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if Xcel Energy’s credit ratings and access to capital were restricted, this could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

As of Dec. 31, 2009, Xcel Energy had approximately $7.9 billion of long-term debt and $1.0 billion of short-term debt and current maturities.  Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2009, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $76.4 million and $18.0 million of exposure.  Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries.  The total amount of bonds with these indemnities outstanding as of Dec. 31, 2009, was approximately $29.9 million.  Xcel Energy’s total exposure under these indemnities cannot be estimated at this time.  If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

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

We have historically paid quarterly dividends to Xcel Energy.  In 2009, 2008 and 2007 we paid $232.7 million, $229.7 million and $226.8 million of dividends to Xcel Energy, respectively.  If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is limited to some extent by our indenture for our first mortgage bonds.

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

Virtually all of the utility plant of NSP-Minnesota is subject to the lien of its first mortgage bond indenture.

Electric utility generating stations:

			Summer 2009
			Net Dependable
Station, City and Unit	Fuel	Installed	Capability (MW)
Steam:
Sherburne-Becker, Minn.
Unit 1	Coal	1976	697
Unit 2	Coal	1977	697
Unit 3	Coal	1987	521	(a)
Prairie Island-Welch, Minn.
Unit 1	Nuclear	1973	551
Unit 2	Nuclear	1974	545
Monticello-Monticello, Minn	Nuclear	1971	572
King-Bayport, Minn	Coal	1968	510
Black Dog-Burnsville, Minn.
2 Units	Coal/Natural Gas	1955-1960	282
2 Units	Natural Gas	1987-2002	298
Riverside-Minneapolis, Minn., 3 Units	Natural Gas	2009	511
Combustion Turbine:
Angus Anson-Sioux Falls, S.D., 3 Units	Natural Gas	1994-2005	384
High Bridge-St. Paul, Minn., 3 Units	Natural Gas	2008	566
Inver Hills-Inver Grove Heights, Minn., 6 Units	Natural Gas	1972	350
Blue Lake-Shakopee, Minn., 6 Units	Natural Gas	1974-2005	490
Various locations, 23 Units	Various	Various	181
Wind:
Grand Meadow - Mower County, Minn.	Wind	2008	101	(b)
		Total	7,256

(a)	Based on NSP-Minnesota’s ownership of 59 percent.
(b)	This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.
	Therefore, the on-demand net maximum capacity is zero.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2009:

Conductor Miles
500 KV	2,917
345 KV	6,385
230 KV	1,801
161 KV	428
115 KV	7,103
Less than 115 KV	82,782

NSP-Minnesota had 375 electric utility transmission and distribution substations at Dec. 31, 2009.

Natural gas utility mains at Dec. 31, 2009:

Miles
Transmission	135
Distribution	9,586

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Item 3 — Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota.  After consultation with legal counsel, NSP-Minnesota has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

For a discussion of legal claims and environmental proceedings, see Note 14 to the consolidated financial statements.  For a discussion of proceedings involving utility rates and other regulatory matters, see Item 1 for Public Utility Regulation and Summary of Recent Federal Regulatory Developments and Note 13 to the consolidated financial statements.

Item 4 — Reserved

PART II

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

NSP-Minnesota is a wholly owned subsidiary and there is no market for its common equity securities.

NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock.  Even with these restrictions, NSP-Minnesota could have paid more than $1.1 billion and $1.0 billion in additional cash dividends on common stock at Dec. 31, 2009 and 2008, respectively.

In addition, NSP-Minnesota had dividend restrictions imposed by its credit facility, FERC rules and state regulatory commissions.

·NSP-Minnesota’s credit facility includes a financial covenant that requires the equity-to-total capitalization ratio to be greater than or equal to 35 percent.  NSP-Minnesota was in compliance as its equity-to-total capitalization ratio was 52 percent and 50 percent at Dec. 31, 2009 and 2008, respectively.

·Dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

·State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy by requiring an equity-to-total capitalization ratio between 45.99 percent and 56.21 percent.  NSP-Minnesota was in compliance as described above.  Total capitalization for NSP-Minnesota cannot exceed $7.5 billion.

The dividends declared during 2009 and 2008 were as follows:

(Thousands of Dollars)	2009		2008
First quarter	$	57,256	$	56,668
Second quarter	58,575		58,449
Third quarter	58,463		58,501
Fourth quarter	58,415		58,414

Item 6 — Selected Financial Data

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

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Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries.  It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Forward Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of NSP-Minnesota during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the respective accompanying consolidated financial statements and notes to the consolidated financial statements.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of NSP- Minnesota to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; environmental laws and regulations; actions of accounting regulatory bodies; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2009 and Exhibit 99.01 to NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2009.

Results of Operations

NSP-Minnesota’s net income was approximately $293.8 million for 2009, compared with approximately $285.1 million for 2008.

Electric Revenues and Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  Due to fuel and purchased energy cost-recovery mechanisms for customers,  fluctuations in these costs do not materially affect electric utility margin.

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and commodity trading activities.  Short-term wholesale refers to energy-related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from, NSP-Minnesota’s generation assets and energy and capacity purchased to serve native load.  Commodity trading is not associated with NSP-Minnesota’s generation assets or the energy or capacity purchased to serve native load.  Wholesale sales were immaterial to revenue and gross margin as a percentage of revenue at Dec. 31, 2009 and 2008.

Electric —The following tables detail the electric revenues and margin:

(Millions of Dollars)	2009			2008
Electric revenues	$	3,407		$	3,584
Electric fuel and purchased power	(1,412		)	(1,681		)
Electric margin	$	1,995		$	1,903

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

Electric Revenues

(Millions of Dollars)	2009 vs. 2008
Fuel and purchased power cost recovery	$	(209	)
Trading	(54		)
Retail sales decline (excluding weather impact)	(20		)
Firm wholesale	(14		)
Estimated impact of weather	(12		)
Minnesota retail rate increase	88
MERP rider	17
2008 refund of nuclear refueling outage revenues due to change in recovery method	16
Non-fuel riders	9
Transmission revenue	5
Other, net	(3		)
Total decrease in electric revenues	$	(177	)

Electric Margin

(Millions of Dollars)	2009 vs. 2008
Minnesota retail rate increase	$	88
Interchange agreement billing with NSP-Wisconsin	28
MERP rider	17
2008 refund of nuclear refueling outage revenues due to change in recovery method	16
Non-fuel riders	9
Retail sales decline (excluding weather impact)	(20		)
Estimated impact of weather	(12		)
Transmission revenue, net of expense	(8		)
Higher purchased capacity costs	(5		)
Firm wholesale	(5		)
Trading	(4		)
Other, net	(12		)
Total increase in electric margin	$	92

Natural Gas Revenues and Margins

The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases.  However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

Natural Gas — The following tables detail natural gas revenues and margin:

(Millions of Dollars)	2009			2008
Natural gas revenues	$	640		$	890
Cost of natural gas sold and transported	(464		)	(702		)
Natural gas margin	$	176		$	188

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The following summarizes the components of the changes in natural gas revenues and margin for the year ended Dec. 31:

Natural Gas Revenues

(Millions of Dollars)	2009 vs. 2008
Purchased natural gas adjustment clause recovery	$	(241	)
Conservation program revenue and incentive (generally offset by expenses)	(9		)
Estimated impact of weather	(5		)
Other, net	5
Total decrease in natural gas revenues	$	(250	)

Natural Gas Margin

(Millions of Dollars)	2009 vs. 2008
Conservation program revenue and incentive (generally offset by expenses)	$	(9	)
Estimated impact of weather	(5		)
Other, net	2
Total decrease in natural gas margin	$	(12	)

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Operating and maintenance expenses for 2009 increased $90.9 million, or 10.4 percent, compared to 2008.  The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2009 vs. 2008
Higher employee benefit costs	$	37
Nuclear outage costs, net of deferral	30
Higher nuclear plant operation costs	21
Higher insurance costs	6
Higher labor costs	4
Higher information technology costs	3
Interchange agreement billing with NSP-Wisconsin	3
Lower consulting costs	(9		)
Lower uncollectible receivable costs	(6		)
Other, net	2
Total increase in other operating and maintenance expenses	$	91

·Higher employee benefits costs are primarily attributable to 2009 employee based incentive compensation expenses and increased medical expenses.  In 2008, no employee based incentive benefits were earned.

·The increase in nuclear outage costs is due to the timing of outages in conjunction with the MPUC’s approval of the change in the nuclear refueling outage recovery method from the direct expense method to the deferral and amortization method in 2008.

·The increase in nuclear plant operation costs is driven primarily by an increase in security costs and regulatory fees, resulting from new NRC requirements.

Conservation Program Expenses — Conservation program expenses decreased $6.6 million, or 10.1 percent, for 2009, compared with 2008.  The decrease was primarily due to an adjustment in the 2009 rider for over-recovery in 2008, which resulted from the timing of the rider rate approval.

Depreciation and Amortization — Depreciation and amortization expense decreased by approximately $23.0 million, or 5.6 percent, for 2009, compared with 2008.  In September 2009, as a result of the MPUC decision in the Minnesota electric rate case, NSP-Minnesota began recognizing a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation, effective Jan. 1, 2009.  In addition, in June 2009, the MPUC extended the recovery period of decommissioning expense by 10 years for the Prairie Island and the Monticello nuclear plants.  These decreases were partially offset by normal system expansion.

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Taxes Other than Income — Taxes other than income increased by approximately $9.0 million, or 6.5 percent, for 2009, compared with 2008.  The increase was primarily due to increased property taxes.

Other Income, Net — Other income, net, decreased by approximately $9.3 million for 2009, compared with 2008.  The decrease was primarily due to lower interest income in 2009 and changes in non-qualified benefit plan liabilities related to market activity.

Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC is a non-cash amount capitalized as a part of construction costs representing the cost of financing the construction.  Generally, these costs are recovered from customers, in future rates, as the related property is depreciated.  AFUDC, resulting in part from these projects, increased by approximately $2.9 million, or 6.8 percent, for the twelve months of 2009 compared with the same period in 2008.  NSP-Minnesota’s overall increase in AFUDC is due to the Monticello Extended Power Uprate Project and various nuclear projects.

Interest Charges — Interest charges decreased by approximately $3.6 million, or 1.8 percent, for 2009, compared with 2008.  The decrease was due to lower interest rates on short-term debt.

Income Taxes — Income tax expense decreased by $3.1 million for 2009, compared with 2008.  The effective tax rate was 37.3 percent for 2009, compared with 38.5 percent for 2008.  The decrease in income tax expense and the lower effective tax rate for 2009 were primarily due to reduced state unitary tax expense in 2009.  If state unitary tax expense in 2008 would have been consistent with 2009, the effective tax rate for 2008 would have been 37.0 percent.

The effective tax rates for 2009 and 2008 differ from their statutory federal income tax rates, primarily due to state income tax expense partially offset by tax credits recognized and tax benefit from plant related regulatory differences.   See Note 7 to the consolidated financial statements.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, NSP-Minnesota is exposed to a variety of market risks.  Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  All financial and commodity-related instruments, including derivatives, are subject to market risk.  Market risks associated with derivatives are discussed in further detail in Note 10 to the consolidated financial statements.

NSP-Minnesota is exposed to the impact of changes in price for energy and energy related products, which is partially mitigated by NSP-Minnesota’s use of commodity derivatives.  Though no material non-performance risk currently exists with the counterparties to NSP-Minnesota’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties.  Distress in the financial markets may also impact the fair value of the debt and equity securities in the nuclear decommissioning trust fund and master pension trust, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash.

Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its electric and natural gas operations.  Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities.  Commodity price risk is also managed through the use of financial derivative instruments.  NSP-Minnesota’s risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.

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

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Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec. 31 were as follows:

(Thousands of Dollars)	2009			2008
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	3,615		$	2,112
Contracts realized or settled during the period	(11,681		)	(2,391		)
Commodity trading contract additions and changes during period	17,042			3,894
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	8,976		$	3,615

At Dec. 31, 2009, the fair values by source for the commodity trading net asset balance were as follows:

	Futures / Forwards
		Maturity							Maturity		Total Futures/
	Source of	Less Than			Maturity		Maturity		Greater Than		Forwards
(Thousands of Dollars)	Fair Value	1 Year			1 to 3 Years		4 to 5 Years		5 Years		Fair Value
NSP-Minnesota	1	$	(319	)	$	2,577	$	—	$	—	$	2,258
	2	2,338			4,220		160		—		6,718
		$	2,019		$	6,797	$	160	$	—	$	8,976

1 — Prices actively quoted or based on actively quoted prices.

2 — Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available.  Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms.  The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes.  Market price uncertainty and other risks also are factored into the model.

Normal purchases and sales transactions, as defined by ASC 815 Derivatives and Hedging, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.

At Dec. 31, 2009, a 10 percent increase in market prices over the next 12 months for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.8 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.8 million.

NSP-Minnesota’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR).  VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.

The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis, were as follows:

	Year Ended
(Millions of Dollars)	Dec. 31		VaR Limit		Average		High		Low
2009	$	0.50	$	5.00	$	0.44	$	2.02	$	0.06
2008	0.30		5.00		0.30		1.14		0.01

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

At Dec. 31, 2009, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would have no impact pretax interest expense.  See Note 10 to the consolidated financial statements for a discussion of NSP-Minnesota’s interest rate derivatives.

34

NSP-Minnesota also maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning.  These trust funds are subject to interest rate risk and equity price risk.  At Dec. 31, 2009, these funds were invested in a diversified portfolio of taxable and municipal fixed income securities and equity securities.  These funds may be used only for activities related to nuclear decommissioning.  The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore fluctuations in equity prices, or interest rates do not have an impact on earnings.

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

At Dec. 31, 2009, a 10 percent increase in prices would have resulted in an increase in credit exposure of $2.3 million, while a decrease of 10 percent in prices would have resulted in an increase in credit exposure of $3.0 million.

NSP-Minnesota conducts standard credit reviews for all counterparties.  NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.  The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.  Distress in financial markets could increase NSP-Minnesota’s credit risk.

Fair Value Measurements

NSP-Minnesota adopted new accounting and disclosure guidance on fair value measurements on Jan. 1, 2008 which established a hierarchy for inputs used in measuring fair value, and generally requires that the most observable inputs available be used for fair value measurements.  Note 12 to the consolidated financial statements describes the fair value hierarchy, and discloses the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.

Commodity Derivatives — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2009.  Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues.  Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms NSP-Minnesota also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.  The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2009.

Commodity derivatives assets and liabilities assigned to Level 3 consist primarily of FTRs, as well as forwards and options that are either long-term in nature or related to commodities and delivery points with limited observability.  Level 3 commodity derivative assets and liabilities represent approximately 3 percent and 79 percent of total assets and liabilities measured at fair value, respectively, at Dec. 31, 2009.

Determining the fair value of a FTR requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3.  Level 3 commodity derivatives assets and liabilities include $23.6 million and $3.3 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2009.

Determining the fair value of certain commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers.  When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3.  Level 3 commodity derivatives assets and liabilities include $17.8 million and $10.9 million of estimated fair values, respectively, for commodity forwards and options held at Dec. 31, 2009.

35

Nuclear Decommissioning Fund — Nuclear decommissioning fund assets assigned to Level 3 consist of asset-backed and mortgage-backed securities.  To the extent appropriate, observable market inputs are utilized to estimate the fair value of these securities, however, less observable and subjective risk-based adjustments to estimated yield and forecasted prepayments are often significant to these valuations.  Therefore, estimated fair values for all asset-backed and mortgage-backed securities totaling $93.1 million in the nuclear decommissioning fund at Dec. 31, 2009 (approximately 7 percent of total assets measured at fair value), are assigned to Level 3.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset

Item 8 — Financial Statements and Supplementary Data

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

See Note 19 to the consolidated financial statements for summarized quarterly financial data.

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Management Report on Internal Controls Over Financial Reporting

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

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

NSP-Minnesota management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2009.  In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.  Based on our assessment, we believe that, as of Dec. 31, 2009, the company’s internal control over financial reporting is effective based on those criteria.

NSP-Minnesota’s independent auditors have issued an audit report on the company’s internal control over financial reporting.  Their report appears herein.

/S/ JUDY M. POFERL	/S/ DAVID M. SPARBY
Judy M. Poferl	David M. Sparby
President and Chief Executive Officer	Vice President and Chief Financial Officer
March 1, 2010	March 1, 2010

37

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Northern States Power Company — Minnesota

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company, a Minnesota Corporation, and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of income, common stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009.  Our audits also included the financial statement schedule listed in the Index at Item 15.  These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company, a Minnesota corporation, and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 1, 2010

38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Northern Power States Company, a Minnesota corporation

We have audited the internal control over financial reporting of Northern Power States Company, a Minnesota corporation, and subsidiaries (the “Company”) as of December 31, 2009, based on criteria established Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2009 of the Company and our report dated March 1, 2010 expressed an unqualified opinion on those financial statements and financial statement schedule.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 1, 2010

39

NSP-MINNESOTA AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME(amounts in thousands of dollars)

	Year Ended Dec. 31,
	2009			2008			2007
Operating revenues
Electric	$	3,407,273		$	3,584,109		$	3,476,674
Natural gas	640,323			889,958			776,971
Other	19,093			19,569			18,569
Total operating revenues	4,066,689			4,493,636			4,272,214
Operating expenses
Electric fuel and purchased power	1,411,877			1,680,795			1,576,901
Cost of natural gas sold and transported	464,043			701,687			602,617
Cost of sales — other	11,076			10,034			9,212
Other operating and maintenance expenses	968,370			877,497			884,554
Conservation program expenses	59,244			65,876			72,912
Depreciation and amortization	389,367			412,362			405,569
Taxes (other than income taxes)	147,193			138,184			130,094
Total operating expenses	3,451,170			3,886,435			3,681,859
Operating income	615,519			607,201			590,355
Other income, net	1,572			10,895			6,105
Allowance for funds used during construction — equity	28,848			26,510			21,826
Interest charges and financing costs
Interest charges — includes other financing costs of $5,778, $5,834, and $5,271, respectively	194,808			198,369			186,293
Allowance for funds used during construction — debt	(17,760		)	(17,140		)	(17,334		)
Total interest charges and financing costs	177,048			181,229			168,959
Income before income taxes	468,891			463,377			449,327
Income taxes	175,121			178,236			182,025
Net income	$	293,770		$	285,141		$	267,302

See Notes to Consolidated Financial Statements

40

NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS(amounts in thousands of dollars)

	Year Ended Dec. 31,
	2009			2008			2007
Operating activities
Net income	$	293,770		$	285,141		$	267,302
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	394,712			407,343			415,651
Nuclear fuel amortization	80,104			64,203			53,453
Deferred income taxes	177,347			140,701			172,004
Amortization of investment tax credits	(3,120		)	(3,503		)	(3,897		)
Allowance for equity funds used during construction	(28,848		)	(26,510		)	(21,826		)
Provision for bad debts	19,408			25,506			23,336
Net realized and unrealized hedging and derivative transactions	(4,960		)	(4,484		)	(5		)
Changes in operating assets and liabilities
Accounts receivable	74,818			21,928			(84,250		)
Accrued unbilled revenues	19,113			(22,050		)	(6,367		)
Inventories	89,984			(75,265		)	(52,226		)
Recoverable purchased natural gas and electric energy costs	(3,823		)	10,252			(19,184		)
Other current assets	(13,589		)	11,394			(2,790		)
Accounts payable	39,229			14,557			(66,920		)
Net regulatory assets and liabilities	(67,056		)	(23,128		)	(14,661		)
Other current liabilities	19,066			(13,348		)	7,624
Change in other noncurrent assets	44			15,781			17,719
Change in other noncurrent liabilities	(25,122		)	(37,139		)	(38,139		)
Net cash provided by operating activities	1,061,077			791,379			646,824
Investing activities
Utility capital/construction expenditures	(844,556		)	(1,015,827		)	(1,060,796		)
Allowance for equity funds used during construction	28,848			26,510			21,826
Purchase of investments in external decommissioning fund	(1,644,278		)	(957,752		)	(712,462		)
Proceeds from sale of investments in external decommissioning fund	1,664,957			914,514			669,070
Cash obtained from consolidation of NMC	—			—			38,950
Investments in utility money pool arrangement	(132,500		)	(943,400		)	(423,500		)
Repayments from utility money pool arrangement	125,500			943,400			423,500
Advances to affiliate	(62,500		)	(337,600		)	(371,250		)
Advances from affiliate	47,000			396,200			342,950
Other investments	(6,415		)	10,501			5,224
Net cash used in investing activities	(823,944		)	(963,454		)	(1,066,488		)
Financing activities
(Repayment of) proceeds from short-term borrowings, net	(65,000		)	(276,500		)	252,500
Borrowings under utility money pool arrangement	601,700			433,300			937,600
Repayments under utility money pool arrangement	(665,200		)	(464,900		)	(842,500		)
Proceeds from issuance of long-term debt	295,340			493,751			343,670
Repayment of long-term debt, including reacquisition premiums	(250,041		)	(10		)	(186,689		)
Borrowings under 5-year unsecured credit facility	—			—			200,000
Repayments under 5-year unsecured credit facility	—			—			(200,000		)
Capital contributions from parent	112,736			203,863			150,514
Dividends paid to parent	(232,708		)	(229,712		)	(226,824		)
Net cash (used in) provided by financing activities	(203,173		)	159,792			428,271
Net increase (decrease) in cash and cash equivalents	33,960			(12,283		)	8,607
Cash and cash equivalents at beginning of period	12,343			24,626			16,019
Cash and cash equivalents at end of period	$	46,303		$	12,343		$	24,626
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(178,017	)	$	(170,168	)	$	(151,409	)
Cash received (paid) for income taxes, net	24,719			(27,292		)	(50,016		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	34,172		$	24,109		$	15,670

See Notes to Consolidated Financial Statements

41

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31,
	2009		2008
Assets
Current assets
Cash and cash equivalents	$	46,303	$	12,343
Notes receivable from affiliates	15,500		—
Investments in utility money pool arrangement	7,000		—
Accounts receivable, net	300,103		413,156
Accounts receivable from affiliates	31,245		12,418
Accrued unbilled revenues	229,338		248,451
Inventories	255,919		345,903
Recoverable purchased natural gas and energy costs	30,428		26,605
Derivative instruments valuation	59,482		70,252
Prepayments and other	81,688		48,493
Total current assets	1,057,006		1,177,621
Property, plant and equipment, net	6,958,656		6,804,794
Other assets
Nuclear decommissioning fund and other investments	1,264,687		1,084,827
Regulatory assets	797,663		828,712
Derivative instruments valuation	117,216		129,605
Other	23,581		21,266
Total other assets	2,203,147		2,064,410
Total assets	$	10,218,809	$	10,046,825
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	175,037	$	250,060
Short-term debt	—		65,000
Borrowings under utility money pool arrangement	—		63,500
Accounts payable	407,500		389,676
Accounts payable to affiliates	83,759		52,291
Taxes accrued	125,650		121,163
Accrued interest	62,780		68,009
Dividends payable to parent	58,415		58,414
Derivative instruments valuation	24,661		39,816
Other	59,353		50,696
Total current liabilities	997,155		1,158,625
Deferred credits and other liabilities
Deferred income taxes	1,234,366		987,050
Deferred investment tax credits	37,134		40,254
Asset retirement obligations	797,476		1,055,689
Regulatory liabilities	469,769		459,880
Pension and employee benefit obligations	310,066		269,537
Derivative instruments valuation	209,528		219,421
Other	83,965		77,775
Total deferred credits and other liabilities	3,142,304		3,109,606
Commitments and contingent liabilities
Capitalization
Long-term debt	2,838,141		2,712,689
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10		10
Additional paid-in capital	2,028,593		1,915,857
Retained earnings	1,210,894		1,149,833
Accumulated other comprehensive income	1,712		205
Total common stockholder’s equity	3,241,209		3,065,905
Total liabilities and equity	$	10,218,809	$	10,046,825

See Notes to Consolidated Financial Statements

42

NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME
(amounts in thousands of dollars)

	Common Stock								Accumulated			Total
				Additional					Other			Common
		Par		Paid In		Retained			Comprehensive			Stockholder’s
	Shares	Value		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2006	1,000,000	$	10	$	1,561,480	$	1,055,983		$	6,199		$	2,623,672
Adoption of new accounting guidance for uncertainty in income taxes						884						884
Net income						267,302						267,302
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $551									797			797
Net derivative instrument fair value changes during the period, net of tax of $(503)									(728		)	(728		)
Comprehensive income for 2007												268,255
Common dividends declared to parent						(226,812		)				(226,812		)
Contribution of capital by parent				150,514								150,514
Balance at Dec. 31, 2007	1,000,000	$	10	$	1,711,994	$	1,097,357		$	6,268		$	2,815,629
Adoption of new accounting guidance for endorsement split-dollar life insurance, net of tax of $(401)						(633		)				(633		)
Net income						285,141						285,141
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $228									331			331
Net derivative instrument fair value changes during the period, net of tax of $(3,901)									(5,651		)	(5,651		)
Unrealized loss - marketable securities, net of tax of $(513)									(743		)	(743		)
Comprehensive income for 2008												279,078
Common dividends declared to parent						(232,032		)				(232,032		)
Contribution of capital by parent				203,863								203,863
Balance at Dec. 31, 2008	1,000,000	$	10	$	1,915,857	$	1,149,833		$	205		$	3,065,905
Net income						293,770						293,770
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $143									208			208
Net derivative instrument fair value changes during the period, net of tax of $615									888			888
Unrealized loss - marketable securities, net of tax of $284									411			411
Comprehensive income for 2009												295,277
Common dividends declared to parent						(232,709		)				(232,709		)
Contribution of capital by parent				112,736								112,736
Balance at Dec. 31, 2009	1,000,000	$	10	$	2,028,593	$	1,210,894		$	1,712		$	3,241,209

See Notes to Consolidated Financial Statements

43

NSP-MINNESOTA AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CAPITALIZATION(amounts in thousands of dollars)

	Dec. 31,
	2009			2008
Long-Term Debt
First Mortgage Bonds, Series due:
Aug. 1, 2010, 4.75%	$	175,000		$	175,000
Aug. 28, 2012, 8%	450,000			450,000
March 1, 2018, 5.25%	500,000			500,000
March 1, 2019, 8.5% (a)	27,900			27,900
Sept. 1, 2019, 8.5% (a)	100,000			100,000
July 1, 2025, 7.125%	250,000			250,000
March 1, 2028, 6.5%	150,000			150,000
April 1, 2030, 8.5% (a)	69,000			69,000
July 15, 2035, 5.25%	250,000			250,000
June 1, 2036, 6.25%	400,000			400,000
July 1, 2037, 6.2%	350,000			350,000
Nov. 1, 2039, 5.35%	300,000			—
Senior Notes, due Aug. 1, 2009, 6.875%	—			250,000
Other	66			107
Unamortized discount	(8,788		)	(9,258		)
Total	3,013,178			2,962,749
Less current maturities	175,037			250,060
Total long-term debt	$	2,838,141		$	2,712,689
Common Stockholder’s Equity
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares in 2009 and 2008	$	10		$	10
Additional paid in capital	2,028,593			1,915,857
Retained earnings	1,210,894			1,149,833
Accumulated other comprehensive income	1,712			205
Total common stockholder’s equity	$	3,241,209		$	3,065,905

(a)  Pollution control financing

See Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts— NSP-Minnesota is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas.  NSP-Minnesota is subject to regulation by the FERC and state utility commissions.  All of NSP-Minnesota’s accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation— NSP-Minnesota has subsidiaries, which have been consolidated and for which all intercompany transactions and balances have been eliminated.

In 2007, NSP-Minnesota obtained 100 percent ownership in NMC.  Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were included in NSP-Minnesota’s consolidated financial statements from the transaction date.  NSP-Minnesota has reintegrated its nuclear operations into its generation operations.  The NRC approved the transfer of the nuclear operating licenses from NMC to NSP-Minnesota on Sept. 22, 2008.

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

NSP-Minnesota has various rate-adjustment mechanisms in place that currently provide for the recovery of natural gas and electric fuel costs, as well as purchased energy costs.  These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred.  Where applicable, under governing state regulatory commission rate orders, fuel costs over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets.  A summary of significant rate adjustment mechanisms follows:

·NSP-Minnesota’s rates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowing recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.  The electric cost-of-fuel-and-purchased-energy mechanism in North Dakota also provides a sharing among shareholders and customers of certain margins on short-term wholesale and commodity trading. NSP Minnesota’s rates include a rider for cost recovery of DSM program costs as well as recovery of a financial incentive for meeting energy savings goals.

·NSP-Minnesota operates under various service quality standards, which could require customer refunds if certain criteria are not met.  NSP-Minnesota’s rates in Minnesota include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually.  NSP-Minnesota is allowed to recover certain costs associated with new transmission facilities to deliver renewable energy resources and certain costs associated with production facilities through rate riders.

·NSP-Minnesota sells firm power and energy in wholesale markets, which are regulated by the FERC.  Certain of these rates include monthly wholesale fuel cost-recovery mechanisms through prices that are indexed to NSP-Minnesota retail rates, including the monthly cost of fuel and purchased energy recovery mechanism.

Commodity Trading Operations— All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from NSP-Minnesota are apportioned to PSCo and SPS.  Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value in accordance with ASC 815 Derivatives and Hedging.  In addition, commodity trading results include the impact of all margin-sharing mechanisms.  For more information, see Note 10 to the consolidated financial statements.

45

Fair Value Measurements —NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest to approximate fair value.  Changes in the observed trading prices and liquidity of cash equivalents, including commercial paper and money market funds, are also monitored as additional support for determining fair value and losses are recorded in earnings if fair value falls below recorded cost.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, NSP-Minnesota may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value.  For the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each class of security.

Types of and Accounting for Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by ASC 815 Derivatives and Hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation.  This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification is dependent on the applicability of specific regulation.

Gains or losses on hedging transactions for the sale of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; hedging transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.  NSP-Minnesota is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Cash Flow Hedges — Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge).  The accounting for derivatives requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.  NSP-Minnesota formally documents all hedging relationships in accordance with this guidance.  The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedging transaction.  In addition, at inception and on a quarterly basis, NSP-Minnesota formally assesses whether the derivative instruments being used are highly effective in offsetting changes in the cash flows of the hedged items.

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.  NSP-Minnesota discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur.  To test the effectiveness of hedges, a hypothetical hedge is used to mirror all the critical terms of the hedged transaction and the dollar-offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis.  Gains and losses related to discontinued hedges that were previously deferred in OCI or deferred as regulatory assets or liabilities will remain deferred until the hedged transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, in which case, associated deferred amounts are immediately recognized in current earnings.

Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for the purchase and sale of commodities for use in their business operations.  ASC 815 Derivatives and Hedging requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting as normal purchases or normal sales.

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

For further discussion of NSP-Minnesota’s risk management and derivative activities, see Note 10 to the consolidated financial statements.

46

Property, Plant and Equipment and Depreciation— Property, plant and equipment is stated at original cost.  The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense.  The cost of plant retired is charged to accumulated depreciation and amortization.  Regulatory obligations to incur removal costs are recorded as regulatory liabilities.  Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.  Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred.  Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use.

NSP-Minnesota records depreciation expense related to its plant by using the straight-line method over the plant’s useful life.  Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2009, 2008 and 2007 was 3.2, 3.6 and 3.6 percent, respectively.

AFUDC— AFUDC represents the cost of capital used to finance utility construction activity.  AFUDC is computed by applying a composite pretax rate to qualified construction work in progress.  The amount of AFUDC capitalized as a utility construction cost is credited to nonoperating income (for equity capital) and interest charges (for debt capital).  AFUDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility service rates.  In addition to construction-related amounts, AFUDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota.

Generally AFUDC costs are recovered from customers as the related property is depreciated.  In 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants located in the Minneapolis-St. Paul metropolitan area to natural gas and to install advanced pollution control equipment at a third coal-fired plant.  These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW.  The first of these projects began operating in July 2007, the second of these projects began operating in May 2008 and the remaining projects began operations in March 2009, at a cumulative investment of approximately $1 billion.  The MPUC has approved a more current recovery of the financing costs related to the MERP.  The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting in a lower recognition of AFUDC.

Decommissioning— NSP-Minnesota accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs.  The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material and extends over the estimated lives of the plants.  The calculation assumes that NSP-Minnesota will recover those costs through rates.  The fair value of external nuclear decommissioning fund investments is determined based on quoted market prices for those or similar investments.  Unrealized gains or losses on the fund’s assets are included with regulatory assets on the consolidated balance sheets.  For more information on nuclear decommissioning, see Note 15 to the consolidated financial statements.

Nuclear Fuel Expense— Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFUDC), as well as future disposal costs of spent nuclear fuel, costs associated with the end-of-life fuel segments and fees assessed by the DOE for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel enrichment facility.

Nuclear Refueling Outage Costs — Effective Jan. 1, 2008, NSP-Minnesota expensed the costs associated with refueling outages as incurred at its nuclear plants.  In September 2008, the MPUC authorized NSP-Minnesota to use a deferral and amortization method for the nuclear refueling O&M costs effective Jan. 1, 2008.  This method amortizes refueling outage costs over the period between refueling outages to better match revenues and expenses.

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

47

Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If several designated responsible parties exist, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs — Litigation accruals are recorded when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated.  External legal fees related to settlements are expensed as incurred.

Income Taxes— NSP-Minnesota accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements.  NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  NSP-Minnesota uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse.  The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.  Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized.  In making such a determination, all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense.  Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property.  Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 16 to the consolidated financial statements.  For more information on income taxes, see Note 7 to the consolidated financial statements.

NSP-Minnesota follows the guidance in ASC 740 Income Taxes to measure and disclose uncertain tax positions that NSP-Minnesota has taken or expects to take in its income tax returns.  In accordance with this guidance, NSP-Minnesota recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

NSP-Minnesota reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy and its subsidiaries, including NSP- Minnesota, file consolidated federal income tax returns and combined and separate state income tax returns.  Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state filings.  The holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company.

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

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

Inventory— All inventory for NSP-Minnesota is recorded at average cost.

48

Regulatory Accounting— NSP-Minnesota accounts for certain income and expense items in accordance with ASC 980 Regulated Operations.  Under this guidance:

·Certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and

·Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item.  Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.  If restructuring or other changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on NSP-Minnesota’s results of operations in the period the write-off is recorded.  See more discussion of regulatory assets and liabilities in Note 16 to the consolidated financial statements.

Deferred Financing Costs— Other assets included deferred financing costs, net of amortization, of approximately $23.7 million and $21.3 million at Dec. 31, 2009 and 2008, respectively.  NSP-Minnesota is amortizing these financing costs over the remaining maturity periods of the related debt.

Debt premiums, discounts and expenses are amortized over the life of the related debt.  The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

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

Renewable Energy Credits — RECs aremarketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources.  RECs are awarded upon delivery of the associated energy and can be bought and sold.  RECs are typically used as a form of measurement of compliance to RPSs enacted by those states that are encouraging construction and consumption of renewable energy, but can also be sold separately from the energy produced.  Currently, NSP-Minnesota acquires RECs from the generation or purchase of renewable power.

When RECs are acquired in the course of generation or purchase as a result of meeting load obligations, they are recorded as inventory at cost.  RECs acquired for trading purposes are recorded as other investments and are also recorded at cost.  The cost of RECs that are retired for compliance purposes is recorded as electric fuel and purchased power expense.  The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues, net of any margin sharing requirements.

Emission Allowances — Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA.  NSP-Minnesota follows the inventory accounting model for all allowances.  The sales of allowances are reported in the operating activities section of the consolidated statements of cash flows.  The net margin on sales of emission allowances is included in electric utility operating revenues as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2009 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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2.Accounting Pronouncements

Recently Adopted

Business Combinations— In December 2007, the FASB issued new guidance on business combinations which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This new guidance is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008.  NSP-Minnesota implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Noncontrolling Interests — Also in December 2007, the FASB issued new guidance on noncontrolling interests in consolidated financial statements which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This new guidance was effective for fiscal years beginning on or after Dec. 15, 2008.  NSP-Minnesota implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Derivatives and Hedging Disclosures — In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows.  The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts.  This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008.  NSP-Minnesota implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.  For further discussion and the required disclosures, see Note 10 to the consolidated financial statements.

Interim Fair Value Disclosures — In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements.  This new guidance was effective for interim periods ending after June 15, 2009.  NSP-Minnesota implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Fair Value in Inactive Markets — Also in April 2009, the FASB issued new guidance for identifying market transactions that are not orderly and determining fair value when market trading activity has decreased significantly.  The new guidance emphasizes that even if there has been a significant decrease in the volume and level of market activity for an asset or liability, fair value still represents the exit price in an orderly transaction between market participants.  This new guidance was effective for interim and annual periods ending after June 15, 2009.  NSP-Minnesota implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Other-Than-Temporary Impairments — Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments.  This new guidance was effective for interim and annual periods ending after June 15, 2009.  NSP-Minnesota implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

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Accounting Standards Codification — In June 2009, the FASB issued Topic 105 — Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB ASC to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC.  All other accounting literature not included in the Codification is to be considered non-authoritative.  The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009.  NSP-Minnesota implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009.  The implementation did not have a material impact on NSP-Minnesota’s consolidated financial statements.

Postretirement Benefit Plans — In December 2008, the FASB issued new guidance on employers’ disclosures about postretirement benefit plan assets.  The guidance amends and expands previous disclosure requirements for plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, and information regarding fair value measurements.  This new guidance was effective for disclosures for fiscal years ending after Dec. 15, 2009.  NSP-Minnesota implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.  For further discussion and the required disclosures, see Note 8 to the consolidated financial statements.

Fair Value of Liabilities — In August 2009, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value (ASU No. 2009-05), which updates the Codification with clarifications for measuring the fair value of liabilities.  The liability-specific guidance includes clarifications and guidelines for using, when available, the most observable prices in active markets for identical liabilities or similar liabilities, or the prices of identical liabilities or similar liabilities traded as assets, rather than more complex and less observable valuation techniques and inputs such as those used in a present value model.  The updates to the Codification contained in ASU No. 2009-05 were effective for interim and annual periods beginning after its August, 2009 issuance.  NSP-Minnesota implemented the guidance on Sept. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

Recently Issued

Consolidation of Variable Interest Entities — In June 2009, the FASB issued new guidance on consolidation of variable interest entities.  The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.  This new guidance is effective for interim and annual periods beginning after Nov. 15, 2009.  NSP-Minnesota does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value.  The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements.  The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010.  NSP-Minnesota does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.

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3.Selected Balance Sheet Data

	Dec. 31,
(Thousands of Dollars)	2009			2008
Accounts receivable, net
Accounts receivable	$	322,778		$	438,855
Less allowance for bad debts	(22,675		)	(25,699		)
	$	300,103		$	413,156
Inventories
Materials and supplies	$	105,508		$	97,945
Fuel	99,705			141,190
Natural gas	50,706			106,768
	$	255,919		$	345,903
Property, plant and equipment, net
Electric plant	$	9,679,288		$	9,472,073
Natural gas plant	948,708			916,740
Common and other property	472,624			452,308
Construction work in progress	587,080			615,734
Total property, plant and equipment	11,687,700			11,456,855
Less accumulated depreciation	(5,030,836		)	(4,907,681		)
Nuclear fuel	1,737,469			1,611,193
Less accumulated amortization	(1,435,677		)	(1,355,573		)
	$	6,958,656		$	6,804,794

4.Short-Term Borrowings

Commercial Paper— At Dec. 31, 2008, NSP-Minnesota had commercial paper outstanding of $65.0 million.  NSP-Minnesota has approval by the Board of Directors to issue up to $500 million of commercial paper.  The weighted average interest rate at Dec. 31, 2008 was 2.57 percent.  NSP-Minnesota had no commercial paper outstanding at Dec. 31, 2009.

Money Pool— Xcel Energy and its utility subsidiaries have established a utility money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other.  The Holding Company may make investments in the utility subsidiaries at market-based interest rates.  However, the money pool arrangement does not allow the utility subsidiaries to make investments in the Holding Company.  NSP-Minnesota has approval to borrow up to $250 million under the arrangement.  At Dec. 31, 2009 and 2008, NSP-Minnesota had money pool investments of $7.0 million and borrowings of $63.5 million, respectively.  The weighted average interest rates at Dec. 31, 2009 and 2008 were 0.36 percent and 3.48 percent, respectively.

5.    Long-Term Debt

Credit Facilities — At Dec. 31, 2009, NSP-Minnesota had the following committed credit facility in effect, in millions of dollars:

Credit
Facility		Drawn*		Available		Original Term	Maturity
$	482	$	6	$	476	Five year	December 2011

* Includes direct borrowings, outstanding commercial paper and issued and outstanding letters of credit.

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The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.  NSP-Minnesota has the right to request an extension of the final maturity date by one year.  The maturity extension is subject to majority bank group approval.

·The credit facility has one financial covenant requiring that NSP-Minnesota’s debt-to-total capitalization ratio be less than or equal to 65 percent.  NSP-Minnesota was in compliance as its debt-to-total capitalization ratio was 48 percent and 50 percent at Dec. 31, 2009 and 2008, respectively.  If NSP-Minnesota does not comply with the covenant, it is deemed an event of default and any outstanding amounts due under the facility can be declared due by the lender.

·The credit facility has a cross default provision that provides the borrower will be in default on its borrowings under the facility if any of its subsidiaries, comprising more than 15 percent of the consolidated assets, defaults on any of its indebtedness greater than $50 million.

·The interest rate is based on the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as based on NSP-Minnesota’s senior unsecured credit ratings from Moody, Standard & Poor and Fitch.  Based on NSP-Minnesota’s current credit rating the borrowing margin is 25 basis points.  The commitment fees are calculated for the unused portion of the credit facility at 6 basis points for NSP-Minnesota.

·At Dec. 31, 2009, NSP-Minnesota had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $5.8 million of letters of credit.  At Dec. 31, 2008, NSP-Minnesota had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $65.0 million of commercial paper outstanding and $5.8 million of letters of credit.

Long-Term Borrowings

In November 2009, NSP-Minnesota issued $300 million of 5.35 percent first mortgage bonds, series due Nov. 1, 2039.  NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper and borrowings under the utility money pool arrangement incurred to fund the repayment at maturity of $250 million of 6.875 percent unsecured senior notes due Aug. 1, 2009.

In March 2008, NSP-Minnesota issued $500 million of 5.25 percent first mortgage bonds, series due March 1, 2018.  NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper and borrowings under the utility money pool arrangement.

All property of NSP-Minnesota is subject to the lien of its first mortgage indenture.  NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay Xcel Energy, the holder of its common stock.  Even with these restrictions, NSP-Minnesota could have paid more than $1.1 billion and $1.0 billion in additional cash dividends on common stock at Dec. 31, 2009 and 2008, respectively.

Maturities of long-term debt are:

(Millions of Dollars)
2010	$	175
2011	—
2012	450
2013	—
2014	—

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6.    Joint Plant Ownership

Following are the investments by NSP-Minnesota in jointly owned plants and the related ownership percentages as of Dec. 31, 2009:

					Construction
	Plant in		Accumulated		Work in
(Thousands of Dollars)	Service		Depreciation		Progress		Ownership %
Sherco Unit 3	$	535,643	$	340,258	$	8,172	59.0
Sherco common facilities Units 1, 2 and 3	124,319		77,319		640		59.0 - 100.0
Sherco Substation	4,790		2,354		—		59.0
Grand Meadow Line and Substation	11,204		378		—		50.0
CapX2020	—		—		25,738		26.2 - 72.1
Total	$	675,956	$	420,309	$	34,550

NSP-Minnesota is part owner of Sherco Unit 3, an 860 MW, coal-fueled electric generating unit.  NSP-Minnesota is the operating agent under the joint ownership agreement.  NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility accounts.  Each of the respective owners is responsible for funding its portion of the construction costs.

7.Income Taxes

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  In 2008, the IRS completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003).  The IRS did not propose any material adjustments for those tax years.  The statute of limitations applicable to Xcel Energy’s 2004 and 2005 federal income tax returns expired on Dec. 31, 2009.  The IRS commenced an examination of tax years 2006 and 2007 in 2008, and this audit is expected to be completed in the first quarter of 2010.  As of Dec. 31, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

State Audits —  NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  In 2008, the state of Minnesota concluded an income tax audit through tax year 2001.  No material adjustments were proposed for this audit.  As of Dec. 31, 2009, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004.  In the third quarter of 2009, Xcel Energy received a request for information from the state of Minnesota relating to tax years 2002 through 2007 in order to determine whether to undertake an audit of those years.  As of Dec. 31, 2009, the state of Minnesota had not informed Xcel Energy of its intentions.  There currently are no state income tax audits in progress.

Unrecognized Tax Benefits — The amount of unrecognized tax benefits was $12.5 million and $20.2 million on Dec. 31, 2009 and Dec. 31, 2008, respectively.  A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2009			2008
Balance at Jan. 1	$	20.2		$	14.3
Additions based on tax positions related to the current year	6.9			5.4
Reductions based on tax positions related to the current year	(1.4		)	(0.4		)
Additions for tax positions of prior years	3.6			4.9
Reductions for tax positions of prior years	(1.5		)	—
Settlements with taxing authorities	(15.3		)	(4.0		)
Balance at Dec. 31	$	12.5		$	20.2

The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryovers of $2.8 million on Dec. 31, 2009 and $4.4 million on Dec. 31, 2008.

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The unrecognized tax benefit balance included $2.7 million and $7.2 million of tax positions on Dec. 31, 2009 and Dec. 31, 2008, respectively, which if recognized would affect the annual effective tax rate.  In addition, the unrecognized tax benefit balance included $9.8 million and $13.0 million of tax positions on Dec. 31, 2009 and Dec. 31, 2008, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The decrease in the unrecognized tax benefit balance of $7.7 million in 2009, was due to the resolution of certain federal audit matters, partially offset by an increase due to the addition of similar uncertain tax positions related to ongoing activity.  NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months when the IRS and state audits resume.  At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2009			2008
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(1.3	)	$	(1.9	)
Interest income related to unrecognized tax benefits	1.0			0.6
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.3	)	$	(1.3	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2009 or Dec. 31, 2008.

Other Income Tax Matters — NOL and tax credit carryforwards as of Dec. 31, 2009 and 2008 were as follows:

(Millions of Dollars)	2009		2008
Federal NOL carryforward	$	25.8	$	22.1
Federal tax credit carryforwards	23.0		14.8
State tax credit carryforwards, net of federal detriment	1.8		1.6

The federal carryforward periods expire between 2021 and 2029.  The state carryforward periods expire between 2018 and 2024.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.  The following reconciles such differences for the years ending Dec. 31:

	2009		2008		2007
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	6.2		7.6		8.4
Tax credits recognized, net of federal income tax expense	(2.7	)	(1.6	)	(1.5	)
Regulatory differences — utility plant items	(1.6	)	(2.3	)	(1.7	)
Resolution of income tax audits and other	1.4		—		0.4
Change in unrecognized tax benefits	(1.0	)	0.1		0.2
Life insurance policies	(0.3	)	(0.2	)	(0.2	)
Other, net	0.3		(0.1	)	(0.1	)
Effective income tax rate	37.3	%	38.5	%	40.5	%

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The components of NSP-Minnesota’s income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2009			2008			2007
Current federal tax expense (benefit)	$	(12,136	)	$	9,527		$	15,277
Current state tax expense	19,195			27,802			4,987
Current change in unrecognized tax expense (benefit)	(6,165		)	3,709			(6,346		)
Deferred federal tax expense	154,858			122,485			117,433
Deferred state tax expense	30,364			25,653			50,151
Deferred change in unrecognized tax expense (benefit)	1,667			(3,106		)	7,416
Deferred tax credits	(9,542		)	(4,331		)	(2,996		)
Deferred investment tax credits	(3,120		)	(3,503		)	(3,897		)
Total income tax expense	$	175,121		$	178,236		$	182,025

The components of deferred income tax at Dec. 31 were:

(Thousands of Dollars)	2009			2008
Deferred tax expense excluding items below	$	228,821		$	80,493
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(50,432		)	55,322
Tax expense (benefit) allocated to other comprehensive income and other	(1,042		)	4,886
Deferred tax expense	$	177,347		$	140,701

The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

(Thousands of Dollars)	2009		2008
Deferred tax liabilities:
Difference between book and tax bases of property	$	1,224,338	$	1,003,706
Regulatory assets	106,687		81,411
Unbilled revenue - fuel costs	7,837		6,342
Deferred fuel costs	6,677		9,211
Other	10,088		17,083
Total deferred tax liabilities	$	1,355,627	$	1,117,753
Deferred tax assets:
Employee benefits	$	62,046	$	62,410
Rate refund	26,835		19,144
Tax credit carry forward	24,831		16,392
Regulatory liabilities	16,478		18,514
Deferred investment tax credits	15,174		16,443
Bad debts	9,266		10,497
Net operating loss carry forward	9,206		6,790
Other	1,018		5,611
Total deferred tax assets	$	164,854	$	155,801
Net deferred tax liability	$	1,190,773	$	961,952

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8.    Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.

Xcel Energy, which includes NSP-Minnesota, offers various benefit plans to its employees.  At Dec. 31, 2009, NSP-Minnesota had 2,119 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2010.  NSP-Minnesota also had an additional 222 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates through September 2010.

Effective Jan. 1, 2009, Xcel Energy and NSP-Minnesota adopted new guidance on employers’ disclosures about pension and postretirement benefit plan assets.  The new guidance expands employers’ disclosure requirements for benefit plan assets, including investment policies and strategies, major categories of plan assets, and information regarding fair value measurements consistent with the disclosures for entities’ recurring fair value measurements prescribed by ASC 820 Fair Value Measurements.

ASC 820 Fair Value Measurements establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value.  The three levels defined by the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date.  The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as common stocks listed by the New York Stock Exchange.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date.  The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs, such as corporate bonds with pricing based on market interest rate curves and recent trades of similarly rated securities.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation, such as asset and mortgage backed securities, for which subjective risk-based adjustments to estimated yield and forecasted prepayments are significant inputs.

Pension Benefits

Xcel Energy, which includes NSP-Minnesota, has several noncontributory, defined benefit pension plans that cover almost all employees.  Benefits are based on a combination of years of service, the employee’s average pay and social security benefits.  Xcel Energy’s and NSP-Minnesota’s policy is to fully fund the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws, into an external trust over time.

Xcel Energy and NSP-Minnesota base investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts.  The historical weighted average annual return for the past 20 years for the portfolio of pension investments is 8.98 percent, which is greater than the current assumption level.  The pension cost determination assumes a forecasted mix of investment types over the long term.  Investment returns in 2009 were above the assumed level of 8.50 percent while returns in 2008 and 2007 were below the assumed level of 8.75 percent.  Xcel Energy and NSP-Minnesota continually review the pension assumptions.  In 2010, Xcel Energy will use an investment-return assumption, for all pension plans in aggregate, of 7.79 percent.

The assets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk.  The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class.  There were no significant concentrations of risk in any particular industry, index, or entity, however, a higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year.

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The following table presents the target range pension asset allocations for 2009 and 2008:

	2009		2008
Domestic and international equity securities	24	%	52	%
Long duration fixed income securities	34		—
Short to intermediate term fixed income securities	19		25
Alternative investments	18		23
Cash	5		—
Total	100	%	100	%

In 2009, Xcel Energy and NSP-Minnesota engaged J.P. Morgan’s Pension Advisory Group to evaluate the allocation of the total assets in the master pension trust, taking into consideration the funded status of each individual pension plan.  The investment strategy employed during 2009 is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of short-to-intermediate term and long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following table presents, for each of the fair value hierarchy levels, pension plan assets that are measured at fair value as of Dec. 31, 2009:

(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	—	$	221,971		$	—	$	221,971
Short-term investments & money market securities	—		324,683			—		324,683
Derivatives	—		11,606			—		11,606
Government securities	—		94,949			—		94,949
Corporate bonds	—		522,403			—		522,403
Asset-backed & mortgage-backed securities	—		—			191,831		191,831
Common stock	89,260		—			—		89,260
Private equity investments	—		—			82,098		82,098
Commingled equity and bond funds	—		1,014,072			—		1,014,072
Real estate	—		—			66,704		66,704
Securities lending collateral obligation and other	—		(170,251		)	—		(170,251		)
Total	$	89,260	$	2,019,433		$	340,633	$	2,449,326

The following table presents the changes in Level 3 pension plan assets for the year ended Dec. 31, 2009:

(Thousands of Dollars)	Jan. 1, 2009		Realized and Unrealized Gains (Losses)			Purchases, Issuances, and Settlements (net)			Dec. 31, 2009
Asset-backed & mortgage-backed securities	$	244,008	$	151,755		$	(203,932	)	$	191,831
Real estate	109,289		(43,207		)	622			66,704
Private equity investments	81,034		(5,682		)	6,746			82,098
Total	$	434,331	$	102,866		$	(196,564	)	$	340,633

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Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:

(Thousands of Dollars)	2009			2008
Accumulated Benefit Obligation at Dec. 31	$	2,676,174		$	2,435,513
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,598,032		$	2,662,759
Service cost	65,461			62,698
Interest cost	169,790			167,881
Plan amendments	(35,341		)	—
Actuarial loss (gain)	223,122			(47,509		)
Benefit payments	(191,433		)	(247,797		)
Obligation at Dec. 31	$	2,829,631		$	2,598,032
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	2,185,203		$	3,186,273
Actual return (loss) on plan assets	255,556			(788,273		)
Employer contributions	200,000			35,000
Benefit payments	(191,433		)	(247,797		)
Fair value of plan assets at Dec. 31	$	2,449,326		$	2,185,203
Funded Status of Plans at Dec. 31:
Funded status	$	(380,305	)	$	(412,829	)
Noncurrent assets	—			15,612
Noncurrent liabilities	(380,305		)	(428,441		)
Net pension amounts recognized on consolidated balance sheets	$	(380,305	)	$	(412,829	)
NSP-Minnesota accrued benefit liability recorded	$	157,687		$	91,095
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	530,197		$	454,770
Prior service cost	34,496			46,222
Total	$	564,693		$	500,992
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	564,693		$	500,992
Measurement date	Dec. 31, 2009			Dec. 31, 2008
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.00		%	6.75		%
Expected average long-term increase in compensation level	4.00			4.00
Mortality table	RP 2000			RP 2000

At Dec. 31, 2009, Xcel Energy’s pension plans, in the aggregate, had plan assets of $2.4 billion and projected benefit obligations of $2.8 billion.  At Dec. 31, 2008, one of the pension plans had plan assets of $259.9 million, which exceeded projected benefit obligations of $244.3 million and all other plans in the aggregate had plan assets of $1.9 billion and projected benefit obligations of $2.4 billion.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations.  These regulations did not require cash funding for 2007 through 2009 for the pension plans and are not expected to require cash funding in 2010.

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Xcel Energy accelerated its planned 2010 contribution of $100 million based on available liquidity, bringing its total pension contributions to $200 million during 2009.

·Voluntary contributions were made to the PSCo Bargaining Pension Plan of $173 million in 2009, $35 million in 2008 and $35 million in 2007.

·Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $27 million in 2009.  No voluntary contributions were made to the plan during 2007 or 2008.

·Pension funding contributions for 2011, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $100 million to $150 million.

Plan Amendments — The decrease in the projected benefit obligation for the plan amendment is due to a change in the average earnings calculation resulting from negotiations with the PSCo Bargaining Pension Plan.

Benefit Costs — The components of net periodic pension cost (credit) are:

(Thousands of Dollars)	2009			2008			2007
Service cost	$	65,461		$	62,698		$	61,392
Interest cost	169,790			167,881			162,774
Expected return on plan assets	(256,538		)	(274,338		)	(264,831		)
Amortization of prior service cost	24,618			20,584			25,056
Amortization of net loss	12,455			11,156			15,845
Net periodic pension cost (credit)	$	15,786		$	(12,019	)	$	236
NSP-Minnesota:
Net periodic pension cost (credit)	$	2,891		$	(9,034	)	$	(9,682	)
(Costs) credits not recognized due to effects of regulation	(2,891		)	9,034			11,147
Net benefit cost recognized for financial reporting	$	—		$	—		$	1,465
Significant Assumptions Used to Measure Costs:
Discount rate for year-end valuation	6.75		%	6.25		%	6.00		%
Expected average long-term increase in compensation level	4.00			4.00			4.00
Expected average long-term rate of return on assets	8.50			8.75			8.75

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan.  The return assumption used for 2010 pension cost calculations will be 7.79 percent.  The cost calculation uses a market-related valuation of pension assets.  Xcel Energy, including NSP-Minnesota, uses a calculated value method to determine the market-related value of the plan assets.  The market-related value begins with the fair market value of assets as of the beginning of the year.  The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.

Xcel Energy, which includes NSP-Minnesota, also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel.  Benefits for these unfunded plans are paid out of their operating cash flows.

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Defined Contribution Plans

Xcel Energy, which includes NSP-Minnesota, maintains 401(k) and other defined contribution plans that cover substantially all employees.  The contributions for NSP-Minnesota were approximately $7.5 million in 2009 and $4.2 million in 2008 and 2007.

Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Minnesota, has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees.  The former NCE discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999.  Employees of the former NCE who retired after 1998 are eligible to participate in the health care program with no employer subsidy.

In 1993, Xcel Energy and NSP-Minnesota adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs.  NSP-Minnesota transitioned to full accrual accounting for postretirement benefit costs, with regulatory differences fully amortized prior to 1997.

Plan Assets — Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs.  Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the pension plans.  These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy  and NSP-Minnesota base investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio.  The assets are invested in a portfolio according to Xcel Energy’s and NSP-Minnesota’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk.  The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class.  There were no significant concentrations of risk in any particular industry, index, or entity.  Investment-return volatility is not considered to be a material factor in postretirement health care costs.

The following table presents, for each of the fair value hierarchy levels, postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2009:

(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	—	$	165,291	$	—	$	165,291
Short term investments	—		2,226		—		2,226
Derivatives	—		5,937		—		5,937
Government securities	—		1,538		—		1,538
Corporate bonds	—		60,416		—		60,416
Asset-backed & mortgage-backed securities	—		—		55,371		55,371
Preferred stock	—		540		—		540
Registered investment companies (mutual funds)	—		89,296		—		89,296
Securities lending collateral obligation and other	—		4,074		—		4,074
Total	$	—	$	329,318	$	55,371	$	384,689

The following table presents the changes in Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2009:

(Thousands of Dollars)	Jan. 1, 2009		Realized and Unrealized Gains		Purchases, Issuances, and Settlements (net)			Dec. 31, 2009
Asset-backed & mortgage-backed securities	$	78,693	$	4,051	$	(27,373	)	$	55,371

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Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets, on a combined basis,  is presented in the following table:

(Thousands of Dollars)	2009			2008
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	794,597		$	830,315
Service cost	4,665			5,350
Interest cost	50,412			51,047
Medicare subsidy reimbursements	3,226			6,178
Plan amendments	(27,407		)	—
Plan participants’ contributions	13,786			13,892
Actuarial gain	(47,446		)	(46,827		)
Benefit payments	(62,931		)	(65,358		)
Obligation at Dec. 31	$	728,902		$	794,597
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	299,566		$	427,459
Actual return (loss) return on plan assets	72,101			(132,226		)
Plan participants’ contributions	13,786			13,892
Employer contributions	62,167			55,799
Benefit payments	(62,931		)	(65,358		)
Fair value of plan assets at Dec. 31	$	384,689		$	299,566
Funded Status of Plans at Dec. 31:
Funded status	$	(344,213	)	$	(495,031	)
Current liabilities	(2,240		)	(4,928		)
Noncurrent liabilities	(341,973		)	(490,103		)
Net pension amounts recognized on consolidated balance sheets	$	(344,213	)	$	(495,031	)
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	49,444		$	78,140
Net prior service credit	(1,152		)	—
Transition obligation	4,073			5,419
Total	$	52,365		$	83,559
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	49,240		$	80,105
Deferred Income taxes	1,277			1,411
Net-of-tax accumulated comprehensive income	1,848			2,043
Total	$	52,365		$	83,559
NSP-Minnesota accrued benefit liability recorded	$	124,657		$	152,792
Measurement date	Dec. 31, 2009			Dec. 31, 2008
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.00		%	6.75		%
Mortality table	RP 2000			RP 2000

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Effective Dec. 31, 2009, Xcel Energy and NSP-Minnesota reduced the initial medical trend assumption from 7.4 percent to 6.8 percent.  The ultimate trend assumption remained unchanged at 5.0 percent.  The period until the ultimate rate is reached is three years.  Xcel Energy and NSP-Minnesota base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

A 1-percent change in the assumed health care cost trend rate would have the following effects on NSP-Minnesota:

(Thousands of Dollars)
1-percent increase in APBO components of Dec. 31, 2009	$	12,757
1-percent decrease in APBO components of Dec. 31, 2009	(10,801		)
1-percent increase in service and interest components of the net periodic cost.	1,123
1-percent decrease in service and interest components of the net periodic cost.	(933		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans.  Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously.  Xcel Energy, which includes NSP-Minnesota, contributed $62.2 million during 2009 and $55.6 million during 2008 and expects to contribute approximately $45.4 million during 2010.

Plan Amendments — The decrease in the projected benefit obligation for the plan amendment is due to a change in the medical experience rate resulting from negotiations with the PSCo Bargaining Postretirement Health Care Plan.

Benefit Costs — The components of net periodic postretirement benefit cost are:

(Thousands of Dollars)	2009			2008			2007
Service cost	$	4,665		$	5,350		$	5,813
Interest cost	50,412			51,047			50,475
Expected return on plan assets	(22,775		)	(31,851		)	(30,401		)
Amortization of transition obligation	14,444			14,577			14,577
Amortization of prior service cost	(2,726		)	(2,175		)	(2,178		)
Amortization of net loss	19,329			11,498			14,198
Net periodic postretirement benefit cost	$	63,349		$	48,446		$	52,484
NSP-Minnesota:
Net periodic postretirement benefit cost	13,419			13,958			13,761
Significant Assumptions Used to Measure Costs:
Discount rate for year-end valuation	6.75		%	6.25		%	6.00		%
Expected average long-term rate of return on assets (before tax)	7.50			7.50			7.50

Benefit Payments

The following table lists the projected benefit payments for the pension and postretirement benefit plans.

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2010	$	238,929	$	58,738	$	4,901	$	53,837
2011	230,833		60,202		5,184		55,018
2012	234,256		60,665		5,529		55,136
2013	237,817		60,785		5,841		54,944
2014	244,160		61,260		6,075		55,185
2015-2019	1,256,824		313,040		33,598		279,442

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9.Other Income, Net

Other income (expense), net for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2009			2008			2007
Interest income	$	7,473		$	10,005		$	10,208
Other nonoperating (expense) income	(6		)	1,274			1,818
Insurance policy expenses	(5,895		)	(384		)	(5,921		)
Other income, net	$	1,572		$	10,895		$	6,105

10.  Derivative Instruments

Effective Jan. 1, 2009, NSP-Minnesota adopted new guidance on disclosures about derivative instruments and hedging activities contained in ASC 815 Derivatives and Hedging, which requires additional disclosures regarding why an entity uses derivative instruments, the volume of an entity’s derivative activities, the fair value amounts recorded to the consolidated balance sheet for derivatives, the gains and losses on derivative instruments included in the consolidated statement of income or deferred, and information regarding certain credit-risk-related contingent features in derivative contracts.

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices, as well as variances in forecasted weather.  See additional information pertaining to the valuation of derivative instruments in Note 12 to the consolidated financial statements.

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

At Dec. 31, 2009, accumulated other comprehensive income related to interest rate derivatives included $0.2 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest transactions impact earnings.

Commodity Derivatives — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes.  This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale, and vehicle fuel.

At Dec. 31, 2009, NSP-Minnesota had vehicle fuel contracts designated as cash flow hedges extending through December 2012.  NSP-Minnesota also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  NSP-Minnesota recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the year ended Dec. 31, 2009.

At Dec. 31, 2009, accumulated other comprehensive income related to vehicle fuel cash flow hedges included $1.8 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers.  Changes in the fair value of these commodity derivatives are recorded in income, subject to applicable customer margin-sharing mechanisms.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the year ended Dec. 31, 2009.  Therefore, no gains or losses from fair value hedges or related hedged transactions for the period were recognized.

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The following table shows the major components of derivative instruments valuation in the consolidated balance sheets:

	2009				2008
	Derivative		Derivative		Derivative		Derivative
	Instruments		Instruments		Instruments		Instruments
	Valuation -		Valuation -		Valuation -		Valuation -
(Thousands of Dollars)	Assets		Liabilities		Assets		Liabilities
Long-term purchased power agreements	$	127,164	$	216,191	$	151,884	$	230,715
Commodity derivatives	49,534		17,998		47,973		28,522
Total	$	176,698	$	234,189	$	199,857	$	259,237

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota’s accumulated other comprehensive income, included as a component of common stockholder’s equity, is detailed in the following tables:

(Thousands of Dollars)	2009			2008			2007
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	3,053		$	8,704		$	9,432
After-tax net unrealized losses related to derivatives accounted for as hedges	(1,219		)	(5,463		)	(346		)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings	2,107			(188		)	(382		)
Accumulated other comprehensive income related to cash flow hedges at Dec. 31	$	3,941		$	3,053		$	8,704

The following table details the fair value of commodity derivatives recorded to derivative instruments valuation in the consolidated balance sheet, by category:

	Dec. 31, 2009
						Derivative
			Counterparty			Instruments
(Thousands of Dollars)	Fair Value		Netting (a)			Valuation
Current derivative assets
Other derivative instruments:
Trading commodity	$	19,999	$	(11,638	)	$	8,361
Electric commodity	23,540		1,425			24,965
Natural gas commodity	1,580		54			1,634
Total current derivative assets	$	45,119	$	(10,159	)	$	34,960
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	85	$	—		$	85
Other derivative instruments:
Trading commodity	18,650		(4,193		)	14,457
Natural gas commodity	31		1			32
	18,681		(4,192		)	14,489
Total noncurrent derivative assets	$	18,766	$	(4,192	)	$	14,574

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	Dec. 31, 2009
						Derivative
			Counterparty			Instruments
(Thousands of Dollars)	Fair Value		Netting (a)			Valuation
Current derivative liabilities
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	2,266	$	—		$	2,266
Other derivative instruments:
Trading commodity	17,979		(15,504		)	2,475
Electric commodity	3,276		1,425			4,701
Natural gas commodity	640		54			694
	21,895		(14,025		)	7,870
Total current derivative liabilities	$	24,161	$	(14,025	)	$	10,136
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	11,694	$	(4,197	)	$	7,497
Natural gas commodity	364		1			365
Total noncurrent derivative liabilities	$	12,058	$	(4,196	)	$	7,862

(a)ASC 815 Derivatives and Hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between Xcel Energy and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following table details the impact of derivative activity during the year ended Dec. 31, 2009, on other comprehensive income, regulatory assets and liabilities, and income:

	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into
	During the Period in:						Income During the Period from:						Pre-Tax Gains (Losses)
	Other			Regulatory			Other			Regulatory			Recognized
	Comprehensive			Assets and			Comprehensive			Assets and			During the Period
(Thousands of Dollars)	Income (Loss)			Liabilities			Income (Loss)			Liabilities			in Income
Derivatives designated as cash flow hedges
Interest rate	$	(3,209	)	$			$	(201	)(a)	$			$
Electric commodity				(18,600		)				(4,755)		(c)
Natural gas commodity				(811		)				8,915		(d)	(6,951		)(d)
Vehicle fuel and other commodity	1,147						3,766		(e)
Total	$	(2,062	)	$	(19,411	)	$	3,565		$	4,160		$	(6,951	)
Other derivative instruments
Trading commodity													7,857		(b)
Electric commodity				20,607						(343)		(c)
Natural gas commodity				(373		)				980		(d)
Other													(160		)(b)
Total	$	—		$	20,234		$	—		$	637		$	7,697

(a)Recorded to interest charges.

(b)Recorded to electric operating revenues.  Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and    deducted from gross revenue, as appropriate.

(c)Recorded to electric fuel and purchased power; these derivative settlement gains and losses are shared with electric customers through fuel and    purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(d)Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(e)Recorded to other operating and maintenance expenses.

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At Dec. 31, 2009, commodity derivatives recorded to derivative instruments valuation included derivative contracts with gross notional amounts of approximately 34,374,000 megawatt hours (MwH) of electricity, 9,777,000 MMBtu of natural gas and 2,021,000 gallons of vehicle fuel.  These amounts reflect the gross notional amounts of futures, forwards and financial transmission rights and are not reflective of net positions in the underlying commodities.  Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

Credit Related Contingent Features — Contract provisions of the derivative instruments that NSP-Minnesota enters into may require the posting of collateral or settlement of the contracts for various reasons, including if NSP-Minnesota is unable to maintain its credit rating.  If the credit rating of NSP-Minnesota at Dec. 31, 2009 were downgraded below investment grade, no contracts underlying NSP-Minnesota’s derivative liabilities would require the posting of collateral or contract settlement upon the downgrade.

Certain of NSP-Minnesota’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses.  These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired.  As of Dec. 31, 2009, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

11.  Financial Instruments

The estimated Dec. 31 fair values of NSP-Minnesota’s recorded financial instruments are as follows:

	2009				2008
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Nuclear decommissioning fund	$	1,248,739	$	1,248,739	$	1,075,294	$	1,075,294
Other investments	695		695		725		725
Long-term debt, including current portion	3,013,178		3,238,854		2,962,749		3,100,223

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts.  The fair value of NSP-Minnesota’s nuclear decommissioning fund is based on published trading data and pricing models, generally using the most observable inputs available for each class of security.  The fair value of NSP-Minnesota’s other investments are estimated based on quoted market prices for those or similar investments.  The fair value of NSP-Minnesota’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2009 and 2008.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.

Letters of Credit

NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Dec. 31, 2009 and 2008, there were $6.9 million letters of credit outstanding.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

12.Fair Value Measurements

Effective Jan. 1, 2008, NSP-Minnesota adopted new guidance for recurring fair value measurements contained in ASC 820 Fair Value Measurements and Disclosures which provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value.  A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value was established by this guidance.  The three levels in the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date.  The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

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Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of financial transmission rights.

NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment, as well as an assessment of the impact of NSP-Minnesota’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.

The following tables present, for each of these hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis:

	Dec. 31, 2009
							Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting			Net Balance
Assets
Nuclear decommissioning fund
Cash equivalents	$	—	$	28,134	$	—	$	—		$	28,134
Debt securities	—		545,503		93,107		—			638,610
Equity securities	581,995		—		—		—			581,995
Commodity derivatives	—		22,481		41,404		(14,351		)	49,534
Total	$	581,995	$	596,118	$	134,511	$	(14,351	)	$	1,298,273
Liabilities
Commodity derivatives	$	—	$	22,052	$	14,167	$	(18,221	)	$	17,998

	Dec. 31, 2008
							Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting			Net Balance
Assets
Nuclear decommissioning fund
Cash equivalents	$	—	$	8,449	$	—	$	—		$	8,449
Debt securities	—		491,486		109,423		—			600,909
Equity securities	465,936		—		—		—			465,936
Commodity derivatives	—		17,039		38,207		(7,273		)	47,973
Total	$	465,936	$	516,974	$	147,630	$	(7,273	)	$	1,123,267
Liabilities
Commodity derivatives	$	—	$	21,509	$	14,960	$	(7,947	)	$	28,522

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The following table presents the changes in Level 3 recurring fair value measurements:

	Dec. 31,
	2009						2008
	Commodity			Nuclear			Commodity			Nuclear
	Derivatives,			Decommissioning			Derivatives,			Decommissioning
(Thousands of Dollars)	Net			Fund			Net			Fund
Balance at Jan. 1	$	23,247		$	109,423		$	15,345		$	108,656
Purchases, issuances, and settlements, net	(476		)	(28,356		)	(1,585		)	12,198
Transfers into (out of) Level 3	700			—			(2,578		)	—
(Losses) gains recognized in earnings	(3,115		)	—			496			—
Gains (losses) recognized as regulatory assets and liabilities	6,881			12,040			11,569			(11,431		)
Balance at Dec. 31	$	27,237		$	93,107		$	23,247		$	109,423

Losses on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2009, include $5.7 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2009.  Gains on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2008, include $2.9 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2008.  Realized and unrealized gains and losses on commodity trading activities are included in electric revenues.  Realized and unrealized gains and losses on non-trading derivative instruments are recorded in other comprehensive income or deferred as regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

13.  Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — MPUC

Base Rate

NSP-Minnesota Electric Rate Case — In November 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually.  This request was later modified to $136 million.

In September 2009, the MPUC voted to approve a rate increase of approximately $91.4 million.  As part of its decision, the MPUC approved a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation and decommissioning expenses, effective Jan. 1, 2009.  This decision reduced NSP-Minnesota’s overall revenue deficiency by approximately $40 million, while at the same time reducing expense accruals by a corresponding amount.  A summary of the key terms is listed below:

	Revised Request	Approved
Rate increase	$136 million	$91 million
Return on equity	11.0%	10.88%
Equity ratio	52.5%	52.5%
Electric rate base	$4.1 billion	$4.1 billion
Depreciation life extension for Prairie Island nuclear plant	0 years	10 years

The written order was issued Oct. 23, 2009.  As of December 2009, NSP-Minnesota recorded a customer refund of approximately $39.7 million to reflect the difference between interim rates that were implemented Jan. 2, 2009 and the amount approved by the MPUC.

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NSP-Minnesota Gas Rate Case — In November 2009, NSP-Minnesota filed a request with the MPUC to increase Minnesota gas rates by $16.2 million for 2010, which represents a 2.8 percent overall increase in customer bills.  This request is based on a ROE of 11 percent, an equity ratio of 52.46 percent and a rate base of $441 million.  NSP-Minnesota also requested an additional increase of $3.45 million, for recovery of pension funding costs effective Jan. 1, 2011 to comply with federal law.   In December 2009, the MPUC voted to approve an interim rate increase of $11.1 million, subject to refund.  These rates went into effect on Jan. 11, 2010.  The procedural schedule is listed below and a decision is expected in the fall of 2010.

·Intervenor direct testimony on May 3, 2010;

·NSP-Minnesota rebuttal testimony on June 2, 2010;

·Surrebuttal testimony on June 15, 2010;

·Evidentiary hearings on June 21-25, 2010;

·Initial briefs on July 27, 2010;

·Reply briefs and proposed findings on Aug. 19, 2010; and

·ALJ report on Oct. 1, 2010.

Electric, Purchased Gas and Resource Adjustment Clauses

TCR Rider — The MPUC has approved a TCR rider, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases.  The MPUC approved a rider request to recover approximately $14 million in 2009.  NSP-Minnesota has a request pending seeking recovery of $12.1 million in 2010.  The OES recommended disallowance of $1.7 million of plant costs because one project was over budget and also recommended that the Brookings line, which is subject to dispute at FERC on cost allocation not be recovered through the rider at this time. The request is pending MPUC action.

RES Rider — The MPUC has approved a rider to recover the costs for utility-owned projects implemented in compliance with the RES.  In 2009, the MPUC approved the RES rider request to recover approximately $22 million in 2009.  In September 2009, NSP-Minnesota submitted its proposed RES rider, seeking to recover $45.6 million in 2010.  The OES expressed concerns because some of the projected costs were slightly higher than the levels included in NSP-Minnesota’s certificate filings and requested additional information, which has been provided.  The request is pending MPUC action.

MERP Rider — The MPUC authorized NSP-Minnesota to recover costs related to environmental improvement projects amounting to approximately $113.7 million in 2009 through the MERP rider.  In December 2009, the MPUC authorized a new rate adjustment, which will recover approximately $116.7 million in 2010.

Mercury Cost Rider — The MPUC has approved mercury control plans for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants.  A sorbent injection control system was put into service at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled to be completed in December 2010.  Currently, the estimated project costs are approximately $6.6 million for these two units, and the MPUC authorized NSP-Minnesota to collect the 2010 revenue requirement associated with these projects, which is approximately $3.5 million, from customers through a mercury rider in 2010.  On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and MPCA.  Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost rider.  The plan proposes a flexible program of testing and monitoring as new technology emerges and federal regulations change over the next several years.  The plan calls for the addition of sorbent injection by the statutory deadline of the end of 2014.  The MPCA has six months to review the plan.

SEP Rider — In September 2009, the MPUC approved  NSP-Minnesota proposed rider to recover approximately $2.5 million from its electric customers and $0.1 million from its natural gas customers to recover  costs related to SEP mandates and a cast iron natural gas pipe replacement project to reduce GHG emissions.  The revised SEP rate recovery factors were placed into effect in October 2009.

Energy Innovation Corridor (EIC) Initiative — In December 2009, NSP-Minnesota filed a request with the MPUC for approval of specific projects totaling $15 million including a $2 million deferral request.  The EIC initiative will be a first-of-its-kind clean energy and transportation model in an established urban center in the upper Midwest.  The 2009 legislation authorized rider cost recovery for MPUC approved projects, including NSP-Minnesota’s costs to relocate its facilities along the transportation corridor.  Rider cost recovery is also authorized for MPUC approved EIC projects that demonstrate the best energy efficiency management practices and the installation of innovative and sustainable energy technologies and programs for transforming a mature urban center into a national model for the future development of transportation and energy corridors.   The EIC initiative will advance critical local, state, regional and federal efforts to invest in energy efficiency, transportation electrification, renewable energy and smart grid technology.  MPUC action is pending.

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Annual Automatic Adjustment Report for 2007/2008 — In September 2008, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2007 through June 30, 2008.  During that time period, $848.5 million in fuel and purchased energy costs, including $258.8 million of MISO charges, were recovered from Minnesota electric customers through the FCA.  In addition, approximately $680 million of purchased natural gas and transportation costs were recovered through the PGA.   In February 2010, the MPUC voted to accept the 2008 natural gas annual automatic adjustment report.

Annual Automatic Adjustment Report for 2008/2009 — In September 2009, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2008 through June 30, 2009.  During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the FCA.  In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered through the PGA.  Comments are due in May 2010 on NSP-Minnesota’s 2008/2009 electric and natural gas annual automatic adjustment reports.  The request is pending MPUC action.

Conservation Incentive Filing — In July 2009, NSP-Minnesota filed its proposed incentive plan for achieving significantly higher DSM goals.  The incentive would allow for sharing of savings of up to 15 percent of the net present value of benefits, depending on the level of savings achieved.  In December 2009, the MPUC approved the proposed shared savings model.  The plan would allow NSP-Minnesota to earn a higher incentive than under the previous method if it achieves the higher goals established by the OES.  The amount of the incentive increases to the extent that NSP-Minnesota cost-effectively exceeds the goal.  A written order was issued in January 2010.

Gas Meter Module Failures — Approximately 8,700 customers in the St. Cloud and East Grand Forks areas of Minnesota and about 4,000 customers in the Fargo, N.D. area were under billed for a period of time during the 2007-2008 heating season due to the failure of the automated meter reading (AMR) module installed on their natural gas meters.  While the modules failed to register usage, the meters continued to function.

Pursuant to the NDPSC-approved plan, which provided customers with a $50 service quality credit for each customer experiencing a module failure, NSP-Minnesota began implementing the service quality credits and the rebilling of remaining North Dakota customers in June 2009.  In total, NSP-Minnesota rebilled North Dakota customers approximately $1.5 million for the estimated gas usage during the module failure period.

In July 2009, NSP-Minnesota filed with the MPUC a withdrawal of its request to rebill Minnesota customers experiencing a module failure, which the MPUC approved in October 2009.  NSP-Minnesota completed the customer refunds in January 2010.  In November 2009, NSP-Minnesota completed its dispute resolution with its provider of the AMR modules and meter reading services, and filed a summary of the resolution and proposed disposition of any proceeds with the MPUC.  MPUC action is pending.  NSP-Minnesota has determined that a number of AMR modules designed for commercial customers are defective and as a result  broadened its efforts to evaluate the performance of both gas and electric AMR modules.

Annual Review of Remaining Lives — In February 2009, NSP-Minnesota filed a petition with the MPUC requesting an increase in proposed service lives, salvage rates and resulting depreciation rates for its electric and gas production facilities and a depreciation study for other gas and electric assets, effective Jan 1, 2009.  In addition, the OES recommended a 10-year lengthening of depreciation life of the Prairie Island nuclear plant.  In July 2009, the MPUC approved the proposed service lives, salvage rates, and resulting depreciation rates effective Jan. 1, 2009, for plant in service, with the exception of the Prairie Island nuclear plant.  In the NSP-Minnesota electric rate case, the MPUC extended the depreciation life of the Prairie Island nuclear plant by 10 years beyond the current license life in light of NSP-Minnesota’s application to extend the life of its nuclear plants by 20 years.

Nuclear Decommissioning Expenses — In June 2009, the MPUC issued its order in its review of NSP-Minnesota’s 2009 nuclear plant decommissioning accruals.  The order extended the decommissioning life for the Prairie Island nuclear plant by 10 years.  The order reduced the amount of future nuclear decommissioning expenses that must be collected from customers from $32 million to zero, effective Jan. 1, 2009.

In August 2009, NSP-Minnesota filed a proposal with the MPUC to provide one-time refunds to return to customers their contributions of $22.8 million made to the external escrow decommissioning fund for the Monticello nuclear plant, which the MPUC approved in November 2009.  NSP-Minnesota began refunding the excess escrow to customers in February 2010.

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Pending and Recently Concluded Regulatory Proceedings — NDPSC and SDPUC

South Dakota Electric Rate Case —In June 2009, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $18.6 million annually, or 12.7 percent.  This proposed increase includes approximately $2.9 million in revenues currently recovered through automatic recovery mechanisms.  Thus, the requested increase, net of current automatic recovery mechanisms, is approximately $15.7 million or 10.7 percent.  The request is based on a 2008 historic test year adjusted for known and measurable changes in rate base and O&M expenses, an electric rate base of $282 million, a requested ROE of 11.25 percent, and an equity ratio of 51.63 percent.

On Jan. 5, 2010, the South Dakota Commission approved a settlement agreement, which increases electric base rates by $10.9 million.  The primary difference between the approved rate increase and requested amount was due to a lower ROE and the use of a 20-year life for the Prairie Island nuclear plant, which reduced the revenue deficiency and expense accruals by a corresponding amount.  New rates were effective on Jan. 18, 2010.

Pending and Recently Concluded Regulatory Proceedings — FERC

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.  A proposal in 2005 by MISO to refine the RSG charge initiated protracted proceedings.  In the subsequent compliance proceeding, the FERC has issued numerous orders, attempting to refine and clarify the RSG charge.  With the issuance of these orders, the FERC has directed certain refunds to market participants, but has subsequently refined or waived various refund requirements.  The FERC granted rehearing in part of certain earlier orders directing refunds to correct a rate mismatch in the RSG charge.

In August 2007, numerous parties filed complaints against MISO, arguing that the allocation of the RSG charge (only to certain market participants actually withdrawing energy) was unjust, unreasonable, and unduly discriminatory.  After protracted proceedings, the FERC found in November 2008 that the RSG charge was unjust and unreasonable, and directed refunds.  In May 2009, FERC granted rehearing in part regarding the applicability of refunds for the RSG charges.  Specifically, the FERC determined that the refund-effective date is November 2008, the date of the FERC order determining that the allocation to market participants of the RSG charges was unjust and unreasonable.

The FERC directed MISO to implement an interim RSG cost allocation to be effective starting in August 2007.  The FERC further directed MISO to submit a complete and final proposal, to be implemented on a prospective basis after the commencement of the MISO’s ASMs in January 2009.  In February 2009, MISO submitted a filing to implement the new RSG rate design; however, the FERC has not yet rendered a final decision to implement the new rate design.  In August 2009, the FERC issued an order in which it invalidated numerous exemptions to the RSG that had previously been utilized by MISO through its business practice manuals.  Several parties have sought rehearing of the order and a final FERC decision is still pending.

Xcel Energy is a party to each of the relevant RSG-related proceedings.  Each of the relevant RSG-related orders has been the subject of requests for rehearing at the FERC and petitions for review filed at the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit).  The separate RSG proceedings have proceeded in parallel at the FERC, and the most recent orders  are subject to pending requests for rehearing.  The D.C. Circuit proceedings are being held in abeyance pending final action in the FERC proceedings.

FERC Section 5 Rate Cases for Interstate Gas Pipelines — In November 2009, the FERC approved orders initiating rate investigations under Section 5 of the Natural Gas Act (NGA) against Northern Natural Gas Company (NNG) and Great Lakes Gas Transmission Company (GLGT).  NSP-Minnesota and NSP-Wisconsin are together the largest customer on NNG, holding $41 million per year of maximum rate storage and transportation contracts.

According to the FERC orders, FERC staff concluded, based on a review of the financial information filed with the FERC by the pipelines, that each of the pipelines are substantially over-recovering their cost of service and earning excessive ROEs.  The orders require the pipelines to file full cost and revenue studies, and the matters were set for hearing before an ALJ on an expedited basis.  If the FERC orders the pipelines to reduce their transportation and storage rates, the rate reductions and any associated refunds would be reflected in the purchased gas and electric fuel cost adjustment mechanisms of the Xcel Energy utility subsidiaries.

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Xcel Energy has filed an intervention as part of a group of similarly-situated GLGT shippers in the GLGT Section 5 case, and filed to intervene individually in the NNG Section 5 rate case.  The FERC ALJ conducted a pre-hearing conference on Jan. 12, 2010 and established the procedural schedule for the proceedings.  If fully litigated, the Section 5 rate cases can be expected to go to hearings before the ALJ beginning Aug. 2, 2010.  An initial decision must be issued by Nov. 11, 2010.

14.  Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2009, the estimated cost of the capital expenditure programs and other capital requirements of NSP-Minnesota is approximately $1.2 billion in 2010, $1.2 billion in 2011 and $1.0 billion in 2012.  NSP-Minnesota’s capital forecast includes the following major projects.

Nuclear Capacity Increases and Life Extension — NSP-Minnesota is seeking a 20-year license renewal for the Monticello and Prairie Island nuclear plants. A renewed operating license was approved and issued for Monticello by the NRC in November 2006 licensing the plant to operate until 2030, and the MPUC order approving the spent fuel storage capacity needed to support plant operations until 2030 went into effect in June 2007. The application to renew Prairie Island’s operating licenses was submitted to the NRC in April 2008 and the application for a CON for additional spent fuel storage capacity to support 20 additional years of plant operation was approved by the MPUC in December 2009.  Final state and federal approvals are expected in 2010.

NSP-Minnesota is pursuing capacity increases of Monticello and Prairie Island that will total approximately 235 MW, to be implemented, if approved, between 2010 and 2015. The life extension and capacity increase for Prairie Island Unit 2 is contingent on replacement of Unit 2’s original steam generators, currently planned during the refueling outage in 2013. Total capital investment for these activities is estimated to be over $1 billion between 2010 and 2015. NSP-Minnesota submitted the CON and site permit applications for Monticello’s power uprate in the first quarter of 2008 and the CON and site permit applications for Prairie Island’s power uprate in the second quarter of 2008.  The MPUC approved the Monticello power uprate CON and site permit in December 2008 and the Prairie Island power uprate CON and site permit in December 2009.

Wind Generation — NSP-Minnesota is investing approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project.  These projects are expected to be operational by the end of 2010 and 2011, respectively.   NSP-Minnesota has received regulatory approval for the projects, and has requested recovery of eligible costs beginning in 2010.

CapX 2020 — In 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy, announced that it had identified several groups of transmission projects that proposed to be complete by 2020.  Group 1 project investments are expected to total approximately $1.7 billion, with major construction targeted to begin in 2010 and ending three to five years later. Xcel Energy’s investment is expected to be approximately $900 million depending on the route and configuration approved by the MPUC and the PSCW. Approximately 75 percent of the 2010 capital expenditures and return on investment for transmission projects are expected to be recovered under an NSP-Minnesota TCR tariff rider mechanism authorized by Minnesota legislation, as well as a similar TCR mechanism passed in South Dakota. Cost-recovery by NSP-Wisconsin is expected to occur through the biennial PSCW rate case process.

The capital expenditure programs of NSP-Minnesota are subject to continuing review and modification.  Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth regulatory decisions, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting NSP-Minnesota’s long-term energy needs.  In addition, NSP-Minnesota’s ongoing evaluation of compliance with future requirements to install emission-control equipment and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Fuel Contracts— NSP-Minnesota has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements.  These contracts expire in various years between 2010 and 2028.  In addition, NSP-Minnesota may be required to pay additional amounts depending on actual quantities shipped under these agreements.  The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs.

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The estimated minimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2009, is as follows:

(Millions of Dollars)	2009
Coal	$	599.1
Nuclear fuel	598.3
Natural gas supply	278.0
Gas storage and transportation	950.1

Purchased Power Agreements — NSP-Minnesota has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages and meet operating reserve obligations.  NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2033.  In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts.  Certain contractual payment obligations are adjusted based on indices.  However, the effects of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

At Dec. 31, 2009, the estimated future payments for capacity, accounted for as executory contracts, that NSP-Minnesota is obligated to purchase, subject to availability, were as follows:

(Millions of Dollars)
2010	$	110.7
2011	110.0
2012	109.2
2013	111.8
2014	114.3
2015 and thereafter	319.8
Total *	$	875.8

*  Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Leases— NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business, which are accounted for as operating leases.  Total rental expense under operating lease obligations was approximately $76.2 million, $70.7 million and $53.3 million for 2009, 2008 and 2007, respectively.  Included in total rental expense were purchase power agreement payments of $56.2 million, $48.6 million and $29.5 million in 2009, 2008 and 2007, respectively.

Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with ASC 840 Leases.  Future commitments under operating leases are:

(Millions of Dollars)	Other Operating Leases		Purchased Power Agreement Operating Leases (a) (b)		Total Operating Leases
2010	$	10.5	$	53.1	$	63.6
2011	11.2		54.0		65.2
2012	9.5		55.0		64.5
2013	8.9		55.9		64.8
2014	8.5		56.8		65.3
Thereafter	51.1		674.1		725.2

(a) Amounts not included in purchase power agreement estimated future payments above.

(b) Purchase power agreement operating leases contractually expire through 2025.

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Environmental Contingencies

NSP-Minnesota has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, NSP-Minnesota believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other PRPs and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense.

Site Remediation —NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including sites of former manufactured gas plants operated by NSP-Minnesota, its predecessors or other entities; and third party sites, such as landfills, to which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes.  At Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.3 million, of which $0.2 million was considered to be a current liability.

Asbestos Removal —Some of NSP-Minnesota’s facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed.  NSP-Minnesota has recorded an estimate for final removal of the asbestos as an ARO.  See additional discussion of AROs below.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

EPA GHG Endangerment Finding — On Dec. 7, 2009, in response to the U. S. Supreme Court’s decision in Massachusetts v. EPA, 549 U. S. 497 (2007), the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere.  This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty vehicles.  The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010.  Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.

CAIR — In March 2005, the EPA issued the CAIR to further regulate SO2and NOx emissions.  The objective of CAIR is to cap emissions of SO2and NOx in the eastern United States, including Minnesota.  In response to the decisions by the D.C. Circuit Court of Appeals vacating but reinstating CAIR while the EPA develops revised regulations, the EPA has indicated that a CAIR replacement rule will be proposed in early 2010 with finalization planned for early 2011.

As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions.  Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions.  It will be based on stringent emission controls and forms the basis for a cap and trade program.  State emission budgets or caps decline over time.  States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

On Nov. 3, 2009, the EPA published a rule staying the effectiveness of CAIR in Minnesota effective Dec. 3, 2009.  Cost estimates are therefore not included at this time for NSP-Minnesota.

CAMR — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U. S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury legislation and rules.  The EPA has agreed to finalize MACT emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR.  Xcel Energy, the parent company of NSP-Minnesota, anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.

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Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants.  For NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities.  Xcel Energy installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.

In September 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs recoverable under the Act.  In January 2007, the MPUC approved this request to defer these costs as a regulatory asset with a cap of $6.3 million.  In November 2008, NSP-Minnesota filed a request with the MPUC to reflect its requested recovery of these emission reduction compliance costs incurred through 2009 in the NSP-Minnesota electric rate case.  In June 2009, NSP-Minnesota received an order from the MPUC closing the docket to correspond with the inclusion of costs in the electric rate case.  The recovery of the costs was allowed as part of the rate case.

In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans.  A sorbent injection control system was installed at Sherco Unit 3 in December 2009, with installation at A. S. King scheduled for December 2010.  In an order dated Nov. 4, 2009, the MPUC authorized NSP-Minnesota to collect approximately $3.5 million from customers through a mercury rider in 2010.

On Dec. 21, 2009, NSP-Minnesota filed the plans for mercury control at Sherco Units 1 and 2 with the MPUC and the MPCA.  Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.

Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions of the regional haze rule that require emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.

NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  On Nov. 13, 2008, NSP-Minnesota submitted a revised BART alternatives analysis letter to the MPCA to account for increased construction and equipment costs.  The underlying conclusions and proposed emission control equipment, however, remained unchanged from the original 2006 BART analysis.  The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft state implementation plan (SIP) that are equivalent to the reductions made under CAIR.

On Oct. 21, 2009, the United States Department of Interior certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to pollution emissions from Xcel Energy’s Sherco Plant  Units 1 and 2.  The EPA currently administers the 1980 Visibility Protection Rules for the State of Minnesota through a Federal Implementation Plan.  As such, EPA Region 5 is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and if so, to determine the appropriate BART levels of control.

The MPCA determined that this certification does not alter the proposed SIP.  The SIP proposes BART controls for Sherco that are designed to improve visibility in the national parks, but does not require Selective Catalytic Reduction (SCR) on Units 1 and 2.  The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs.  On Dec. 15, 2009, the MPCA Citizens Board approved the SIP, which has been submitted to the EPA for approval.

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Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts.  In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants.  Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit (Court of Appeals) challenging the phase II rulemaking.  In January 2007, the Court of Appeals issued its decision and remanded the rule to the EPA for reconsideration.  In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the remand.  In April 2008, the U. S. Supreme Court granted limited review of the Court of Appeals’ opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA.  On April 1, 2009, the U. S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds to the Court of Appeals’ decision, the rule’s compliance requirements and associated deadlines will remain unknown.  As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

The MPCA exercised its authority under best professional judgment to require the Black Dog Generating Station in its recently renewed wastewater discharge permit to create a plan by April 2010 to reduce the plant intake’s impact on aquatic wildlife.  NSP-Minnesota is discussing alternatives with the local community and regulatory agencies to address this concern.

Asset Retirement Obligations

NSP-Minnesota records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with ASC 410 Asset Retirement and Environmental Obligations.  This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.

Recorded ARO — AROs have been recorded for plant related to nuclear production, steam production, electric transmission and distribution, gas distribution and office buildings.  The steam production obligation includes asbestos, ash containment facilities, radiation sources and decommissioning.  The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota.  NSP-Minnesota also recorded asbestos recognition for its general office building.

Generally, this asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  AROs also have been recorded for NSP-Minnesota steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.  The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities.  Additional AROs have been recorded for NSP-Minnesota steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.

NSP-Minnesota recognized an ARO for the retirement costs of natural gas mains and for the removal of electric transmission and distribution equipment.  The electric transmission and distribution ARO consists of many small potential obligations associated with polychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps.  These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year.  Therefore, the obligation was measured using an average service life.

For the nuclear assets, the ARO associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originates with the in-service date of the facility.  Monticello began operation in 1971.  Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively.  See Note 15 to the consolidated financial statements for further discussion of nuclear obligations.

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A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota’s AROs is shown in the table below for the 12 months ended Dec. 31, 2009 and Dec. 31, 2008, respectively:

	Beginning								Revisions			Ending
	Balance		Liabilities		Liabilities				to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2009		Recognized		Settled		Accretion		Estimates			Dec. 31, 2009
Electric plant
Steam production asbestos	$	19,520	$	—	$	—	$	1,126	$	(3,870	)	$	16,776
Steam production ash containment	13,844		—		—		814		(2,111		)	12,547
Steam production radiation sources	61		—		—		4		(8		)	57
Nuclear production decommissioning	1,013,342		—		—		61,469		(315,888		)	758,923
Wind production	7,447		—		—		483		(179		)	7,751
Electric transmission and distribution	151		—		—		9		(20		)	140
Natural gas plant
Gas transmission and distribution	245		—		—		16		—			261
Common and other property
Common general plant asbestos	1,079		—		—		59		(117		)	1,021
Total liability	$	1,055,689	$	—	$	—	$	63,980	$	(322,193	)	$	797,476

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear AROs is $1.2 billion as of Dec. 31, 2009, including external nuclear decommissioning investment funds and internally funded amounts.

NSP-Minnesota also incurred revisions for asbestos, nuclear production, radiation sources, wind turbines, ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

The revised end of life date for the Prairie Island nuclear plant approved by the MPUC in 2008 and effective Jan. 1, 2009 resulted in the nuclear production decommissioning ARO and related regulatory asset decreasing by $315.9 million in the fourth quarter of 2009.

	Beginning								Revisions			Ending
	Balance		Liabilities		Liabilities				to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2008		Recognized		Settled		Accretion		Estimates			Dec. 31, 2008
Electric plant
Steam production asbestos	$	22,423	$	—	$	—	$	1,279	$	(4,182	)	$	19,520
Steam production ash containment	18,111		—		—		1,001		(5,268		)	13,844
Steam production radiation sources	—		61		—		—		—			61
Nuclear production decommissioning	1,209,746		—		—		71,370		(267,774		)	1,013,342
Wind production	—		7,408		—		39		—			7,447
Electric transmission and distribution	125		—		—		7		19			151
Natural gas plant
Gas transmission and distribution	12,685		—		—		314		(12,754		)	245
Common and other property
Common general plant asbestos	1,278		—		—		70		(269		)	1,079
Total liability	$	1,264,368	$	7,469	$	—	$	74,080	$	(290,228	)	$	1,055,689

A new decommissioning study filed with the MPUC in 2008 proposed the extension of the final removal date of the Monticello and Prairie Island nuclear plants by 14 and 26 years, respectively, effective Jan. 1, 2009.  As a result of the studies for the Monticello and Prairie Island nuclear plants, the nuclear production decommissioning ARO and related regulatory asset decreased by $128.5 million and $139.3 million, respectively, in the fourth quarter of 2008.

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Removal Costs— NSP-Minnesota accrues an obligation for plant removal costs for generation, transmission and distribution facilities.  Generally, the accrual of future non-ARO removal obligations is not required.  However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.  These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities.  Given the long periods over which the amounts were accrued and the changing of rates through time, NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities.  Removal costs as of Dec. 31, 2009 and 2008 were $372 million and $354 million, respectively.

Nuclear Insurance

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $12.5 billion under the Price-Anderson amendment to the Atomic Energy Act of 1954, as amended.  NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies.  The remaining $12.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident.  NSP-Minnesota is subject to assessments of up to $117.5 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States.  The maximum funding requirement is $17.5 million per reactor during any one year.  These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes.  The NRC’s last adjustment was effective Oct. 29, 2008.  The next adjustment is due on or before Oct. 29, 2013.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL).  The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites.  NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units.  Premiums are expensed over the policy term.  All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds.  Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.  However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $15.2 million for business interruption insurance and $30.9 million for property damage insurance if losses exceed accumulated reserve funds.

Legal Contingencies

Lawsuits and claims arise in the normal course of business.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Minnesota’s financial position and results of operations.

Environmental Litigation

Carbon Dioxide Emissions Lawsuit — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U. S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of NSP-Minnesota, to force reductions in CO2 emissions.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the U. S. Court of Appeals for the Second Circuit.  On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision.  On Nov. 5, 2009 the defendants, including Xcel Energy, filed a petition for rehearing and en banc review.  It is uncertain when the Court of Appeals will respond to the petition.

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Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of NSP-Minnesota, received notice of a purported class action lawsuit filed in U. S. District Court in the Southern District of Mississippi.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds.  Plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Fifth Circuit.  On Oct. 16, 2009, the U. S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court.  On Nov. 27, 2009, defendants, including Xcel Energy, filed a petition for en banc review.  It is uncertain when the Court of Appeals will respond to the petition.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U. S. District Court for the Northern District of California against Xcel Energy, the parent company of NSP-Minnesota, and 23 other utilities, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008.  On Oct. 15, 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds.  On Nov. 5, 2009, plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Ninth Circuit.

Employment, Tort and Commercial Litigation

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U. S. Court of Federal Claims against the United States requesting breach of contract damages for the U. S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota.  At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004.  On Sept. 26, 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In December 2007, the court denied the DOE’s motion for reconsideration.  In February 2008, the DOE filed an appeal to the U. S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue.  In April 2008, the DOE asked the Court of Appeals to stay briefing until the appeals in several other nuclear waste cases have been decided, and the Court of Appeals granted the request.  In December 2008, NSP-Minnesota made a motion in the Court of Appeals to lift the stay, which was denied by the Court of Appeals in February 2009.  Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved.  Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U. S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract.  This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel.  Per the court’s scheduling order, NSP-Minnesota’s expert report on damages was submitted on April 15, 2009, and asserts damages in excess of $250 million.  In November 2009, the Court ordered the DOE to submit its expert report by May 17, 2010.  Trial is expected to take place in mid to late 2010.

Siewert vs. Xcel Energy — In 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems.  Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system.  Plaintiffs claim losses of approximately $7 million.  NSP-Minnesota denies all allegations.  In December 2008, the Court of Appeals issued a decision ordering dismissal of Plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial.  The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review and heard oral arguments on Dec. 2, 2009.  It is uncertain when the Minnesota Supreme Court will render a decision.

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15. Nuclear Obligations

Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants.  The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U. S. nuclear plants.  NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981.  The fuel disposal fees are based on a charge of 0.1 cent per Kwh sold to customers from nuclear generation.  Fuel expense includes the DOE fuel disposal assessments of approximately $12 million in 2009, $13 million in 2008 and $13 million 2007, respectively.  In total, NSP-Minnesota had paid approximately $398 million to the DOE through Dec. 31, 2009.  The Nuclear Waste Policy Act of 1982 required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998.  NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities at both sites.  The amount of spent fuel storage capacity currently authorized by the NRC and the MPUC will allow NSP-Minnesota to continue operation of its Prairie Island nuclear plant until the end of its current license terms in 2013 and 2014 and its Monticello nuclear plant until the end of its renewed operating license in 2030.  Other alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.

Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities is planned for the period from cessation of operations through 2067, assuming the prompt dismantlement method. NSP-Minnesota is currently recording the regulatory costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in a regulatory liability account. The total decommissioning cost obligation is recorded as an ARO in accordance with ASC 410 Asset Retirement and Environmental Obligations.

Monticello began operation in 1971 and with its renewed operating license and CON for spent fuel capacity to support 20 years of extended operation can operate until 2030.  The Monticello 20-year depreciation life extension until September 2030 was granted by the MPUC in 2007. Construction of the Monticello dry-cask storage facility is complete and 10 of the 30 canisters authorized have been filled and placed in the facility.

Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are currently licensed to operate until 2013 and 2014, respectively.  In April 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 PIIC filed contentions in the NRC’s license renewal proceeding in August 2008.  The PIIC request was referred to an ASLB for review.  The ASLB has granted the PIIC hearing request and has admitted seven of the 11 contentions filed.  To date, all seven admitted contentions have been resolved and removed from the ASLB docket.  Subsequent to the NRC issuance of the final Safety Evaluation Report and the draft supplemental environmental impact statement, the PIIC filed four additional contentions.  The ASLB has admitted one of the contentions and has not issued a decision on the other three.  NSP-Minnesota is challenging the admitted contention, and a decision on whether the other contentions will be accepted will be made in early 2010.  If the contentions are not resolved, the resulting adjudicatory process is expected to add approximately eight months onto the NRC’s standard 22 month review schedule, resulting in a decision on the Prairie Island license renewal in late 2010.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC, when decommissioning commences. The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in October 2009, using 2008 cost data.  The next study update will be submitted in October 2011 for the 2012 accrual. The MPUC approval, eliminated 2009 decommissioning funding for Minnesota retail customers, due to a full extension of the accrual period for the Monticello unit from 2020 to 2030, along with an extension of the accrual period for Prairie Island (from 2013 for Unit 1 and 2014 for Unit 2 to 2023 and 2024 respectively).  Further, in November 2009, the MPUC also approved a proposal to refund the Minnesota portion of the Monticello escrow fund in a supplemental filing.

The assets held in trusts, primarily consist of investments in fixed income securities, such as tax-exempt municipal bonds and U. S. government securities that mature in one to 20 years and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

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Consistent with cost-recovery in utility customer rates, NSP-Minnesota previously recorded annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding.  Cost studies quantify decommissioning costs in current dollars.  The most recent study, which resulted in an authorization of no funding presumes that costs will escalate in the future at a rate of 2.89 percent per year.  The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period.  This annuity approach uses an assumed rate of return on funding, which is currently 6.30 percent, net of tax, for external funding.  The net unrealized loss on nuclear decommissioning investments is deferred as a regulatory liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

The external funds are held in trust and in escrow.  The portion in escrow is subject to refund if approved by the various rate commissions.  The MPUC authorized the return of $23.5 million of funds associated with the Monticello plant for the Minnesota retail jurisdictions.  This amount was withdrawn in December 2009 and was refunded on customer’s bills in February 2010.

At Dec. 31, 2009, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning expense of $1.3 billion.  The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters.  Xcel Energy believes future decommissioning cost expense, if necessary, will continue to be recovered in customer rates.  These amounts are not those recorded in the financial statements for the ARO.

(Thousands of Dollars)	2009			2008
Estimated decommissioning cost obligation from most recently approved study (2008 dollars)	$	2,308,196		$	1,683,750
Effect of escalating costs to 2009 and 2008 dollars (2.89 and 3.61 percent per year, respectively)	66,707			189,012
Estimated decommissioning cost obligation in current dollars	2,374,903			1,872,762
Effect of escalating costs to payment date (2.89 and 3.61 percent per year, respectively)	2,741,460			1,254,064
Estimated future decommissioning costs (undiscounted)	5,116,363			3,126,826
Effect of discounting obligation (using risk-free interest rate)	(3,973,493		)	(1,847,526		)
Discounted decommissioning cost obligation	1,142,870			1,279,300
Assets held in external decommissioning trust	1,248,739			1,075,294
Discounting decommissioning obligation compared to assets currently held in external trust	$	(105,869	)	$	204,006

Decommissioning expenses recognized include the following components:

(Thousands of Dollars)	2009			2008			2007
Annual decommissioning cost expense reported as depreciation expense:
Externally funded	$	2,849		$	43,239		$	43,392
Internally funded (including interest costs)	(884		)	(819		)	(759		)
Net decommissioning expense recorded	$	1,965		$	42,420		$	42,633

Reductions to expense for internally-funded portions in 2009, 2008 and 2007 are a direct result of the 2008 and 2005 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the remaining operating life of the unit.  The 2008 nuclear decommissioning filing approved in 2009 has been used for the regulatory presentation.  The change in estimated decommissioning obligations was calculated using a cost estimate for Monticello assuming a 60-year operating life.

16. Regulatory Assets and Liabilities

NSP-Minnesota’s consolidated financial statements are prepared in accordance with the provisions of ASC 980 Regulated Operations, as discussed in Note 1 to the consolidated financial statements.  Under this guidance, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates.  Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities.  If changes in the utility industry or the business of NSP-Minnesota no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in its consolidated statement of income.

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The components of unamortized regulatory assets and liabilities on the consolidated balance sheets of NSP-Minnesota are:

(Thousands of Dollars)	See Note	Remaining Amortization Period	2009		2008
Regulatory Assets
Current regulatory asset - Recoverable purchased natural gas and electric energy costs	1	Less than one year	$	30,428	$	26,605
Pension and employee benefit obligations (d)		Various	$	188,139	$	153,892
Net AROs (a)	14	Plant lives	155,773		256,791
AFUDC recorded in plant (b)	14	Plant lives	133,602		124,242
Contract valuation adjustments(c)	10	Term of contract	89,026		86,937
Nuclear outage costs	13	Generally 18-24 months	60,747		40,690
Conservation programs (b)		Up to two years	46,028		23,911
Renewable and environmental initiative costs		Two to three years	41,935		58,056
Losses on reacquired debt	1	Term of related debt	23,505		26,081
Purchased power contracts costs	10	Term of related contract	20,014		13,228
Unrecovered natural gas costs	1	One to two years	10,620		14,657
MISO Day 2 costs	1	Three years	9,829		8,742
Nuclear fuel storage	1	Three to six years	8,301		9,652
State commission accounting adjustments (b)	13	Plant lives	4,631		4,398
Other		Various	5,513		7,435
Total noncurrent regulatory assets			$	797,663	$	828,712
Regulatory Liabilities
Plant removal costs	14		$	371,867	$	354,117
Deferred income tax adjustments			32,792		30,787
Investment tax credit deferrals			25,659		27,797
Contract valuation adjustments (c)			20,871		23,355
Nuclear outage costs collected in advance from customers			10,322		13,678
Low income discount program			2,634		3,943
Gain on sale of emission allowances			2,239		2,727
Interest on income tax refunds			1,302		1,736
Other			2,083		1,740
Total noncurrent regulatory liabilities			$	469,769	$	459,880

(a)  Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

(b)  Earns a return on investment in the ratemaking process.  These amounts are amortized consistent with recovery in rates.

(c)  Includes the fair value of certain long-term purchased power agreements used to meet energy capacity requirements.

(d)  Includes $427.2 million for the regulatory recognition of the pension expense, offset by $1.4 million of regulatory assets related to the non-qualified pension plan.

17. Segments and Related Information

NSP-Minnesota has two reportable segments, regulated electric utility and regulated natural gas utility.

·NSP-Minnesota’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, North Dakota and South Dakota.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.

·NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota.

83

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of NSP-Minnesota.

To report net income for regulated electric and regulated natural gas utility segments, NSP-Minnesota must assign or allocate all costs and certain other income.  In general, costs are:

·Directly assigned wherever applicable;

·Allocated based on cost causation allocators wherever applicable; or

·Allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the consolidated financial statements.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2009
Operating revenues from external customers	$	3,407,273	$	640,323	$	19,093		$			$	4,066,689
Intersegment revenues	414		1,799		—			(2,213		)	—
Total revenues	$	3,407,687	$	642,122	$	19,093		$	(2,213	)	$	4,066,689
Depreciation and amortization	$	353,089	$	35,854	$	424		$	—		$	389,367
Interest charges and financing cost	160,091		16,608		354			(5		)	177,048
Income tax expense (benefit)	167,708		11,677		(4,264		)	—			175,121
Income from continuing operations	261,556		21,881		10,333			—			293,770
2008
Operating revenues from external customers	$	3,584,109	$	889,958	$	19,569		$	—		$	4,493,636
Intersegment revenues	564		4,863		—			(5,427		)	—
Total revenues	$	3,584,673	$	894,821	$	19,569		$	(5,427	)	$	4,493,636
Depreciation and amortization	$	376,768	$	35,209	$	385		$	—		$	412,362
Interest charges and financing cost	162,697		17,464		1,454			(386		)	181,229
Income tax expense (benefit)	167,961		12,509		(2,234		)	—			178,236
Income from continuing operations	250,785		28,887		5,469			—			285,141
2007
Operating revenues from external customers	$	3,476,674	$	776,971	$	18,569		$	—		$	4,272,214
Intersegment revenues	655		16,261		—			(16,916		)	—
Total revenues	$	3,477,329	$	793,232	$	18,569		$	(16,916	)	$	4,272,214
Depreciation and amortization	$	372,270	$	32,896	$	403		$	—		$	405,569
Interest charges and financing cost	151,012		17,256		707			(16		)	168,959
Income tax expense	165,531		11,315		5,179			—			182,025
Income (loss) from continuing operations	246,086		21,485		(269		)	—			267,302

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18.  Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including NSP-Minnesota.  The services are provided and billed to each subsidiary in accordance with Service Agreements executed by each subsidiary.  Costs are charged directly to the subsidiary which uses the service whenever possible and are allocated if they cannot be directly assigned.

Xcel Energy has established a utility money pool arrangement with the utility subsidiaries.  See Note 4 for further discussion of this borrowing arrangement.

Nuclear Plant Operation — On Sept. 28, 2007, NSP-Minnesota obtained 100 percent ownership in NMC as a result of Wisconsin Energy Corporation (WEC), exiting the partnership due to the sale of its Point Beach Nuclear Plant to FPL Energy.  Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were included in NSP-Minnesota’s consolidated financial statements from the Sept. 28, 2007, transaction date.  NSP-Minnesota has reintegrated its nuclear operations into its generation operations.  The NRC transferred the nuclear operating licenses from NMC to NSP-Minnesota effective Sept. 22, 2008.

Prior to Sept. 28, 2007, NSP-Minnesota also paid its proportionate share of the operating expenses and capital improvement costs incurred by NMC, in accordance with the Nuclear Power Plant Operating Services Agreement.  NSP-Minnesota paid NMC $235.2 million in 2007.

The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin.  The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:

(Thousands of Dollars)	2009		2008		2007
Operating revenues:
Electric	$	389,023	$	390,143	$	372,215
Gas	309		312		366
Operating expenses:
Purchased power	64,059		64,195		79,345
Transmission expense	45,192		42,167		40,872
Other operations — paid to Xcel Energy Services Inc.	303,348		275,618		267,281
Interest expense	596		1,645		1,742
Interest income	50		2,536		1,422

Accounts receivable and payable with affiliates at Dec. 31, was:

	2009				2008
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Wisconsin	$	31,243	$	—	$	12,416	$	—
PSCo	—		15,789		—		15,987
SPS	—		2,268		—		3,330
Other subsidiaries of Xcel Energy	2		65,702		2		32,974
	$	31,245	$	83,759	$	12,418	$	52,291

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements.  At Dec. 31, 2009 and 2008, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $15.5 million and $0.0 million, respectively.

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19. Summarized Quarterly Financial Data (Unaudited)

Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.  Summarized quarterly unaudited financial data is as follows:

	Quarter Ended
(Thousands of Dollars)	March 31, 2009		June 30, 2009		Sept. 30, 2009		Dec. 31, 2009
Operating revenues	$	1,203,383	$	866,404	$	969,359	$	1,027,543
Operating income	158,984		115,290		196,448		144,797
Net income	76,199		49,898		92,549		75,124

	Quarter Ended
(Thousands of Dollars)	March 31, 2008		June 30, 2008		Sept. 30, 2008		Dec. 31, 2008
Operating revenues	$	1,267,724	$	1,021,865	$	1,103,096	$	1,100,951
Operating income	130,865		112,003		218,319		146,014
Net income	63,968		48,353		110,340		62,480

Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

During 2008 and 2009, and through the date of this report, there were no disagreements with the independent public accountants for NSP-Minnesota on accounting principles or practices, financial statement disclosures or auditing scope or procedures.

Item 9A — Controls and Procedures

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Dec. 31, 2009, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Controls Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting.  NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting.  NSP-Minnesota has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level.  During the year and in preparation for issuing its report for the year ended Dec. 31, 2009 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting.  Based on the control evaluation, testing and remediation performed, NSP-Minnesota did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

Item 9B — Other Information

None.

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PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for NSP-Minnesota in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13 — Certain Relationships and Related Transactions, and Director Independence

Item 14 — Principal Accountant Fees and Services

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2010 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits and Financial Statement Schedules

1.	Consolidated Financial Statements:
	Management Report on Internal Controls — For the year ended Dec. 31, 2009.
	Report of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2009, 2008 and 2007.
	Consolidated Statements of Income — For the three years ended Dec. 31, 2009, 2008 and 2007.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2009, 2008 and 2007.
	Consolidated Balance Sheets — As of Dec. 31, 2009 and 2008.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2009, 2008 and 2007.
3.	Exhibits

*Indicates incorporation by reference

+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of NSP-Minnesota (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.03*	By-Laws of NSP-Minnesota as Amended and Restated (a Minnesota corporation) (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee.  (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034).  Supplemental Indentures between NSP-Minnesota and said Trustee, dated as follows:
	- Supplemental Indenture dated Oct. 1, 1992 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 13, 1992 Rider A).
	- Supplemental Indenture dated April 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 1993 Rider A).
	- Supplemental Indenture dated Dec. 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 7, 1993 Rider A).
	- Supplemental Indenture dated June 1, 1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995 Rider A).
	- Supplemental Indenture dated March 1, 1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
	- Supplemental Indenture dated May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000 Rider A).
	- Supplemental Indenture dated June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000 Rider A).

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4.02*	- Supplemental Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.03*	Trust Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, National Association (NA), as Trustee.  (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.04*	Supplemental Trust Indenture, dated July 15, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee.  (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.05*	Supplemental Trust Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee.  (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.06*	Supplemental Trust Indenture dated June 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31387) for the quarter ended Sept. 30, 2002).
4.07*	Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31387) for the quarter ended Sept. 30, 2002).
4.08*	Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indenture dated July 1, 1999, between NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).
4.09*	Supplemental Trust Indenture dated Aug. 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between NSP-Minnesota and BNY Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.10*	Supplemental Trust Indenture dated Aug. 1, 2003 between NSP-Minnesota and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.11*	Supplemental Trust Indenture dated May 1, 2003 between NSP-Minnesota and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988.  (Exhibit 4.73 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2003).
4.12*	Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 001-31387) dated July 14, 2005).
4.13*	Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400,000,000 principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 001-31387) dated May 18, 2006).
4.14*	Supplemental Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee.  (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007).
4.15*	Supplemental Indenture dated March 1, 2008 between NSP-Minnesota and The Bank of New York Trust Company, NA, as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated March 11, 2008.
4.16*	Supplemental Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300,000,000 principal amount of 5.35 percent First Mortgage Bonds, Series due Sept. 1, 2039 (Exhibit 4.01 of Form 8-K of NSP-Minnesota dated Nov. 16, 2009 (file no. 001-31387)).
10.01*+	Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+	Xcel Energy Inc. Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Amended and Restated Executive Long-Term Incentive Award Stock Plan.  (Exhibit 10.02 to Xcel Energy Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+	New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+	Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).

88

10.08*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to
	Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+	Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+	Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.14*+	Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.15*+	Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*+	First Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of Jan. 1, 2009 (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.17*+	First Amendment to the Xcel Energy Inc. Omnibus Incentive Award Plan as of Jan. 1, 2009 (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.18*	Facilities Agreement, dated July 21, 1976, between NSP-Minnesota and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06I to file no. 2-54310).
10.19*	Transactions Agreement, dated July 21, 1976, between NSP-Minnesota and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06J to file no. 2-54310).
10.20*	Coordinating Agreement, dated July 21, 1976, between NSP-Minnesota and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line.  (Exhibit 5.06K to file no. 2-54310).
10.21*	Ownership and Operating Agreement, dated March 11, 1982, between NSP-Minnesota, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3.  (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.22*	Power Agreement, dated June 14, 1984, between NSP-Minnesota and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005.  (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.23*	Power Agreement, dated August 1988, between NSP-Minnesota and Minnkota Power Co. (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).
10.24*	Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly known as Norenco Corp.) and NSP-Minnesota and Norenco Corp. (Exhibit 10.33 to NRG’s Registration on Form S-1, file no. 333-35096).
10.25*	Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and NSP-Minnesota.  (Exhibit 10.34 to NRG’s Registration on Form S-1, file no. 333-35096).
10.26*	Amended Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between NSP-Minnesota and Norenco Corp. (Exhibit 10.36 to NRG’s Registration on Form S-1, file no. 333-35096).
10.27*	Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.28*	500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between NSP-Minnesota and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 25, 2003).
10.29*	Amendment dated as of April 13, 2009 to the NSP-Minnesota Credit Agreement dated as of Dec. 14, 2006.  (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.30*	Credit Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.31*+	Second Amendment to the Xcel Energy 2005 Omnibus Incentive Plan (renaming it the Xcel Energy 2005 Long-Term Incentive Plan) (Exhibit 10.05 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.32*+	Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy.  (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.33*+	Second Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan (Effective May 25, 2005) (Exhibit 10.07 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).

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10.34*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.35*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

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SCHEDULE II

NSP-MINNESOTA AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2009, 2008 and 2007
(amounts in thousands of dollars)

			Additions
	Balance at Jan. 1		Charged to costs and expenses		Charged to other accounts(a)		Deductions from reserves(b)		Balance at Dec. 31
Reserve deducted from related assets:
Allowance for bad debts:
2009	$	25,699	$	19,408	$	5,521	$	27,953	$	22,675
2008	20,103		25,506		6,113		26,023		25,699
2007	13,408		23,336		5,853		22,494		20,103

(a)  Recovery of amounts previously written off.

(b)  Principally bad debts written off or transferred.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NORTHERN STATES POWER COMPANY
	/S/ DAVID M. SPARBY
	David M. Sparby Vice President, Chief Financial Officer and Director (Principal Financial Officer)
March 1, 2010

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on March 1, 2010.

/s/ JUDY M. POFERL	/S/ RICHARD C. KELLY
Judy M. Poferl President, Chief Executive Officer and Director (Principal Executive Officer)	Richard C. Kelly Chairman and Director
/S/ TERESA S. MADDEN	/S/ DAVID M. SPARBY
Teresa S. Madden Vice President and Controller (Principal Accounting Officer)	David M. Sparby Vice President, Chief Financial Officer and Director (Principal Financial Officer)
/S/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III Vice President and Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

NSP-Minnesota has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

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