10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

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 incorporation or organization)	(I.R.S. Employer 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:  None

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  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).  x Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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 Feb. 27, 2012, 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 2012 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 Instructions 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	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	5
ELECTRIC UTILITY OPERATIONS	6
Public Utility Regulation	6
Capacity and Demand	6
Energy Sources and Related Transmission Initiatives	7
Nuclear Power Operations and Waste Disposal	7
Nuclear Plant Power Uprates and Life Extension	9
Fuel Supply and Costs	9
Fuel Sources	10
Renewable Energy Sources	11
Wholesale Commodity Marketing Operations	11
Summary of Recent Federal Regulatory Developments	11
Electric Operating Statistics	14
NATURAL GAS UTILITY OPERATIONS	15
Overview	15
Public Utility Regulation	15
Capability and Demand	16
Natural Gas Supply and Costs	16
Natural Gas Operating Statistics	17
ENVIRONMENTAL MATTERS	17
EMPLOYEES	18
Item 1A — Risk Factors	18
Item 1B — Unresolved Staff Comments	26
Item 2 — Properties	26
Item 3 — Legal Proceedings	27
Item 4 — Mine Safety Disclosures	27
PART II	27
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6 — Selected Financial Data	28
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	31
Item 8 — Financial Statements and Supplementary Data	33
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	85
Item 9A — Controls and Procedures	85
Item 9B — Other Information	86
PART III	86
Item 10 — Directors, Executive Officers and Corporate Governance	86
Item 11 — Executive Compensation	86
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	86
Item 13 — Certain Relationships and Related Transactions, and Director Independence	86
Item 14 — Principal Accountant Fees and Services	86
PART IV	86
Item 15 — Exhibits, Financial Statement Schedules	86
SIGNATURES	90

This Form 10-K is filed by 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 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 Inc.’s  Subsidiaries and Affiliates (current and former)
NMC	Nuclear Management Company, LLC
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP System	The integrated electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, managed by NSP-Minnesota
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
SPS	Southwestern Public Service Company
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
Xcel Energy	Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
ASLB	Atomic Safety and Licensing Board
DOE	United States Department of Energy
DOER	Division of Energy Resources (formerly the Office of Energy Security)
DOI DOT	United States Department of the Interior United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPCA	Minnesota Pollution Control Agency
MPSC MPUC	Michigan Public Service Commission Minnesota Public Utilities Commission
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
PSCW	Public Service Commission of Wisconsin
SDPUC	South Dakota Public Utilities Commission
SEC	Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
EIR	Environmental improvement rider
FCA	Fuel clause adjustment
GAP	Gas affordability program
MCR	Mercury cost recovery rider
PGA	Purchased gas adjustment
RDF	Renewable development fund
RES	Renewable energy standard
SEP	State energy policy
TCR	Transmission cost recovery adjustment
Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
ARC	Aggregator of retail customers
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule

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CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CATR	Clean Air Transport Rule
CIPS	Critical Infrastructure Protection Standards
CO2	Carbon dioxide
Codification	FASB Accounting Standards Codification
CON	Certificate of need
CPCN	Certificate of public convenience and necessity
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
ERRP	Early retiree reimbursement program
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
IFRS	International Financial Reporting Standards
JOA	Joint operating agreement
LLW	Low-level radioactive waste
LNG	Liquefied natural gas
MACT	Maximum achievable control technology
MERP	Metropolitan Emissions Reduction Project.
MGP MISO	Manufactured gas plant Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
MRO	Midwest Reliability Organization
MVP	Multi-value project
Native load	Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract.
NEI NOL	Nuclear Energy Institute Net operating loss
NOx	Nitrogen oxide
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PFS	Private Fuel Storage, LLC
PJM	PJM Interconnection, LLC
PRP	Potentially responsible party
PV	Photovoltaic
REC RECB	Renewable energy credit Regional expansion criteria benefits
ROE	Return on equity
ROFR	Right of first refusal
RPS	Renewable portfolio standard
RSG	Revenue sufficiency guarantee
RTO	Regional Transmission Organization
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services
Measurements
Bcf	Billion cubic feet
KV	Kilovolts
KWh	Kilowatt hours
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

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COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota.  NSP-Minnesota is an operating utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota.  The wholesale customers served by NSP-Minnesota comprised approximately 5 percent of its total KWh sold in 2011.  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 2011.  Although NSP-Minnesota’s large commercial and industrial electric retail customers are comprised of many diversified industries, a significant portion of NSP-Minnesota’s large commercial and industrial electric sales include customers in the following industries: petroleum and coal, as well as food products.  For small commercial and industrial customers, significant electric retail sales include customers in the following industries: real estate and educational services.  Generally, NSP-Minnesota’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin.  A FERC-approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.  Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

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

NSP-Minnesota conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other.  See Note 14 to the consolidated financial statements for further discussion relating to comparative segment revenues, net income and related financial information.

NSP-Minnesota’s corporate strategy focuses on three core objectives: obtain stakeholder alignment; invest in our regulated utility businesses; and earn a fair return on our utility investments.  NSP-Minnesota files periodic rate cases and establishes formula rates or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations.  Environmental leadership is a priority for NSP-Minnesota and is designed to meet customer and policy maker expectations while creating shareholder value.

Seasonality

The demand for electric power generation and natural gas is affected by seasonal differences in the weather.  In general, peak sales of electricity occur in the summer and winter months, and peak sales of natural gas occur in the winter months.  As a result, the overall operating results may fluctuate substantially on a seasonal basis.  Additionally, NSP-Minnesota’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.  See Item 7 — Management’s Discussion of Financial Condition and Results of Operations.

Competition

NSP-Minnesota’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity.  In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  The FERC has continued to promote competitive wholesale markets through open access transmission and other means.  As a result, NSP-Minnesota and its wholesale customers can purchase generation resources from competing wholesale suppliers and use the transmission systems of the Xcel Energy Inc.’s utility subsidiaries on a comparable basis to serve their native load.  While facing these challenges, NSP-Minnesota’s rates are competitive with currently available alternatives.

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ELECTRIC UTILITY OPERATIONS

Public Utility Regulation

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

NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce.  NSP-Minnesota has requested continued authorization from the FERC to make wholesale electric sales at market-based prices.  See Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules for further discussion.  NSP-Minnesota is a transmission owning member of the MISO RTO.

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

· CIP — The CIP recovers the costs of programs that help customers save energy.  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.

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

· RES — The RES is a rider that recovers the costs of new renewable generation.

· SEP — The SEP recovers costs related to various energy policies approved by the Minnesota legislature.

· TCR — The TCR recovers costs associated with new investments in electric transmission.

NSP-Minnesota has requested that the recovery of the costs associated with the EIR and RES be included in base rates, which is included in the Minnesota electric rate case currently pending approval with the MPUC.

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

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

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2012, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2009		2010	2011		2012 Forecast
NSP System		8,615	9,131		9,792	9,213

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The peak demand for the NSP System typically occurs in the summer.  The 2011 uninterrupted system peak demand for the NSP System occurred on July 18, 2011.  The 2011 peak demand occurred on a day with extremely high temperatures and humidity, which resulted in the highest uninterrupted system peak demand since July 31, 2006.

Energy Sources and Related Transmission Initiatives

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

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

Purchased Transmission Services — In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contracts with MISO and regional transmission service providers to deliver power and energy to the NSP System.

NSP System Resource Plans — In December 2011, NSP-Minnesota filed an update to the 2011 through 2025 resource plan with the MPUC.  To account for slower economic growth and the loss of NSP-Wisconsin’s wholesale customers, NSP-Minnesota modified the five-year plan to include a recommendation to withdraw the Black Dog repowering project CON and to reassess the wind procurement plan and resource contingency plan in detail.  The resource plan update also notified the MPUC that there have been changes in the size, timing, and cost estimates for the extended power uprate projects at the Prairie Island nuclear plant.  As a result of these changes, NSP-Minnesota has notified the MPUC that it is completing a new economic and project design analysis and will submit a Change in Circumstances filing seeking reaffirmation of the CON approval before proceeding with the project.  Some elements of the resource plan remain unchanged such as the extension of certain contracts, the Monticello nuclear generating plant extended power uprate project and the commitment to specific CIP program annual achievements.

NSP-Minnesota CapX2020 CON  — In 2009, the MPUC granted CONs to construct one 230 KV electric transmission line and three 345 KV electric transmission lines as part of the CapX2020 project.  The estimated cost of the four major transmission projects is $1.9 billion.  NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total cost.  The remainder of the costs will be born by other utilities in the upper Midwest.  These cost estimates will be revised after the regulatory process is completed.

NSP-Minnesota and Great River Energy filed four route permit applications with the MPUC in addition to a facility permit application with the SDPUC, a certificate of corridor compatibility application with the NDPSC and a CPCN application with the PSCW.  The MPUC has issued route permits for the Minnesota portion of the Fargo, N.D. to St. Cloud, Minn. project and the Bemidji, Minn. to Grand Rapids, Minn. project.  The remaining required permit activities are on-going in North Dakota, Wisconsin and Minnesota.

In December 2011, the Monticello, Minn. to St. Cloud, Minn. project was placed in service and MISO granted the final approval of the Brookings, S.D. project as an MVP.

Black Dog Repowering CON — In March 2011, NSP-Minnesota filed a request with Minnesota regulators to approve a CON for the project to retire its last two coal-burning units (Units 3 and 4) at the Black Dog plant in Burnsville, Minn. and replace them with combined-cycle natural gas burning units.  Units 1 and 2 were converted to natural gas combined-cycle operation in 2002.

In December 2011, NSP-Minnesota requested to withdraw the CON and close the docket.  The request to withdraw is pending an ALJ decision.  NSP-Minnesota will reevaluate the Black Dog repowering project as part of the next resource plan expected in 2013.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant.  Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes.  The discharge and handling of 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 — LLW from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Clive facility located in Utah.  If off-site LLW disposal facilities become unavailable, NSP-Minnesota has storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives.

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High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes.  The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management.  This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility.

Nuclear Geologic Repository - Yucca Mountain Project

In 2002, the U.S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository.  In 2008, the DOE submitted an application to construct a deep geologic repository at this site to the NRC.  In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC to approve the withdrawal of the application.  A number of parties have challenged the DOE’s authority to stop the project and withdraw the application.  The utility industry, including Xcel Energy, is represented in the challenges by the NEI.  In light of the DOE’s plan to stop the project and withdraw its application, Xcel Energy in a separate action has requested the Secretary of Energy to set the fee collection rate for the Nuclear Waste Fund to zero until a definitive program is in place.  In April 2010, the NEI, on behalf of its members, including Xcel Energy, filed a lawsuit against the DOE in federal court, requesting that the fee be suspended.  The Secretary of Energy has convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposal of used nuclear fuel. On Jan. 26, 2012, the Blue Ribbon Commission report was issued.  The report provides numerous policy recommendations that will be considered by the Secretary of Energy.

In June 2010, the ASLB issued a ruling that the DOE could not withdraw the Yucca Mountain application.  In September 2011, the NRC announced that it was evenly divided on whether to take the affirmative action of overturning or upholding the ASLB decision.  Because the NRC could not reach a decision, an order was issued instructing that information associated with the ASLB adjudication should be preserved.  The ASLB complied and the proceeding has been suspended.

Nuclear Spent Fuel Storage

In July 2011, a settlement agreement resolving the method by which NSP-Minnesota can recover certain incremental spent fuel storage costs through 2013 was approved with the DOE.  The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation.  NSP-Minnesota received a $100 million payment in August 2011, of which $14.5 million was allocated to NSP-Wisconsin.  As of Dec. 31, 2011, NSP-Minnesota has recorded the payment as restricted cash and a regulatory liability.  Additionally, a claim for incremental spent fuel storage costs from 2009-2010 was submitted to the DOE in September 2011 and a claim for 2011 will be submitted to the DOE in May 2012.

NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.  As of Dec. 31, 2011, there were 29 casks loaded and stored at the Prairie Island plant and 10 canisters 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 2006, the U.S. Department of the Interiorissued two findings: (1) that it would not grant the leases for rail or intermodal sites and (2) that it was revoking its previous conditional approval of the site lease between PFS and the Skull Valley Indian tribe.In 2007, PFS and the Skull Valley Band filed a lawsuit challenging these actions.  The lawsuit remains pending.  A judicial appeal of the NRC licensing decision has been held in abeyance pending the outcome of the lawsuit challenging the DOI decisions.  The existence of PFS as a licensed out-of-state storage option remains a credible alternative if PFS and the Skull Valley Band can prevail in the pending litigation and if the federal government fails to make progress with their obligation to take title and remove spent nuclear fuel from all domestic reactor sites.

See Note 12 to the consolidated financial statements for further discussion regarding the nuclear generating plants.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact the operations of the nuclear plants.  The event at the nuclear plant in Fukushima, Japan could impact the NRC’s deliberations on NSP-Minnesota’s power uprates discussed below.  This event could also result in additional regulation by the NRC, which could require additional capital expenditures or operating expenses.  The NRC has created an internal task force to develop recommendations for NRC consideration on whether it should require immediate emergency preparedness and mitigating enhancements at U.S. reactors and any changes to NRC regulations, inspection procedures and licensing processes.

In July 2011, the task force released its recommendations.  The report confirmed the safety of U.S. nuclear energy facilities and recommends actions to enhance U.S. nuclear plant readiness to safely manage severe events.  In October 2011, the NRC Staff identified the near-term regulatory actions to be taken and prioritized these recommendations into a three-tiered approach.  In December 2011, the NRC Commissioners approved the prioritization of the first tier and second tier recommendations.  The NRC Staff and the industry are working to establish guidance to implement the NRC’s direction regarding resolution of the Tier 1 recommendations and final action by the NRC on these recommendations is expected in the first half of 2012.

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The industry is considering a wide range of strategies to address anticipated NRC regulation. Depending on the approach selected, preliminary estimates range from $20 million to $250 million dollars of capital investment approximately over the next five to eight years to address postulated safety upgrades to the Xcel Energy nuclear facilities.  The low end of this range would apply if the NRC accepts the industry’s ‘flex’ approach which provides diverse and portable sources of providing emergency power and water. The high end estimate considers added cost of requiring permanently installed modifications with a higher degree of engineering analysis to meet nuclear standards for flooding, seismic and other local environmental considerations.  Xcel Energy believes the costs of implementing these requirements would be recoverable through regulatory mechanisms, and it does not expect a material impact on its results of operations.

To better coordinate response activities, the U.S. nuclear energy industry has created a steering committee made up of representatives from major electric sector organizations, including Xcel Energy, to integrate and coordinate the industry’s ongoing responses.  In addition, the NRC has conducted technical inspections at Xcel Energy’s nuclear facilities to assess the capability to respond to extraordinary consequences similar to those that occurred at Fukushima, Japan.  These inspections identified no significant findings or issues.

Nuclear Plant Power Uprates and Life Extension

Life Extensions— In 2006, the NRC renewed the Monticello operating license allowing the plant to operate until 2030.  In June 2011, the NRC issued renewed operating licenses for Prairie Island Units 1 and 2, allowing Unit 1 to operate until 2033 and Unit 2 until 2034.

Monticello Nuclear Plant Extended Power Uprate—  In 2008, NSP-Minnesota filed for both state and federal approvals of an extended power uprate of approximately 71 MW for NSP-Minnesota’s Monticello nuclear plant.  The MPUC approved the CON for the extended power uprate in 2008.  The filing was placed on hold by the NRC Staff to address concerns raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance.  NSP-Minnesota has been working with the industry and regulatory agencies to address this issue and had expected to receive a regulatory decision on the license application in 2012.  In October 2011, the Advisory Committee recommended that all licensing actions that credit the use of containment accident pressure be suspended until the causes and risks of Japan’s Fukushima incident are better understood.  NSP-Minnesota is evaluating the impact of this recommendation on the timing of the license decision which will likely result in a delay of the approval.  NSP-Minnesota has rescheduled the remaining equipment changes needed to complete the Monticello power uprate project during the planned spring 2013 refueling outage.

Prairie Island Nuclear Plant Extended Power Uprate — In 2008, NSP-Minnesota filed for an extended power uprate of approximately 164 MW for Prairie Island Units 1 and 2, which the MPUC approved in 2009.  Analysis of recent extended power uprate submittals to the NRC concluded that significant additional design work beyond current schedule and cost plan estimates are now being required to submit a successful application.  As a result, NSP-Minnesota is completing an economic and new project design analysis to determine project impacts and anticipates submitting a Change in Circumstances filing with the MPUC in the first quarter of 2012.

Total capital investment between 2012 and 2015 for the Monticello and Prairie Island power uprate and life cycle management activities is estimated to be approximately $640 million.

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
2011	$	2.06	55	%	$	0.89	40	%	$	6.56	5	%	$	1.82
2010		1.89	51			0.83	42			6.29	7			1.73
2009		1.78	57			0.70	39			7.36	4			1.61

*  Includes refuse-derived fuel and wood

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

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Fuel Sources

Coal — The NSP System normally maintains approximately 40 days of coal inventory.  Coal supply inventories at Dec. 31, 2011 and 2010 were approximately 48 and 39 days usage, respectively.  NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana.  During 2011 and 2010, coal requirements for the NSP System’s major coal-fired generating plants were approximately 9.5 million tons.  The estimated coal requirements for 2012 are approximately 8 million tons, including adjustments to account for Sherco Unit 3, which was shut down in November 2011 after experiencing a significant failure of its turbine, generator and exciter systems.  It is uncertain when Sherco Unit 3 will recommence operations.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 99 percent of their coal requirements in 2012, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the following year, 67 percent of requirements in two years, and 33 percent of requirements in three years.  Remaining requirements will be filled through the procurement process or over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2012 and 2013.  Coal delivery may be subject to short-term interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

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

· Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2017 and approximately 66 percent of the requirements for 2018 through 2025.

· Current contracts for conversion services cover 100 percent of the requirements through 2017 and approximately 78 percent of the requirements for 2018 through 2025.

· Current enrichment service contracts cover 100 percent of the requirements through 2016 and approximately 95 percent of the requirements for 2017 through 2025.

Fabrication services for Monticello and Prairie Island are 100 percent committed through 2025 and 2014, respectively.  A contract for fuel fabrication services for Prairie Island is currently being negotiated for 2015 and beyond.

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

Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers.  Natural gas supplies and associated transportation and storage services for power plants are procured under contracts with various terms to provide an adequate supply of fuel.  However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market.  Generally, natural gas supply contracts have pricing that is tied to various natural gas indices.  Most transportation contract pricing is based on FERC approved transportation tariff rates. These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2010, the NSP System’s commitments related to gas supply contracts were $14 million and commitments related to gas transportation and storage contracts were approximately $499 million.   At Dec. 31, 2011, the NSP System did not have any commitments related to gas supply contracts; however, commitments related to gas transportation and storage contracts, which expire in various years from 2012 to 2028, were approximately $462 million.  The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

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Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, biomass, solar and hydroelectric power from both owned generating facilities and purchased power agreements.Renewable energy comprised 19.7 percent and 18.3 percent of the NSP System’s total owned and purchased energy for 2011 and 2010, respectively.  Biomass and solar power comprised approximately 2.8 percent and 2.9 percent of renewable energy for 2011 and 2010, respectively, with the remaining renewable energy provided by wind and hydroelectric sources.  As of Dec. 31, 2011, the NSP System is in compliance with its renewable portfolio standards, which require generation from renewable resources of 15 percent and 8.89 percent of Minnesota and Wisconsin electric retail sales, respectively. 

The NSP System also offers customer-focused renewable energy initiatives.  The Windsource® program allows customers in Minnesota and Wisconsin to purchase a portion or all of their electricity from renewable sources.   Approximately 22,715 and 22,676 customers purchased 176,522 MWh and 166,979 MWh of electricity under the Windsource program in 2011 and 2010, respectively.  Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program.  Over 300 PV systems with approximately 3 MW of aggregate capacity and 166 PV systems with approximately 1 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2011 and Dec. 31, 2010, respectively.  

Wind—The NSP System acquires the majority of its wind energy from purchased power agreements with wind farm owners, primarily in Southwestern Minnesota. The NSP System currently has more than 100 of these agreements in place, with facilities ranging in size from under 1 MW to more than 200 MW.  In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements.  The average cost per MWh of wind energy under these contracts was approximately $39 and $37 for 2011 and 2010, respectively.  The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state specific renewable resource requirements, and the year of contract execution.

Generally, contracts executed in 2011 have benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to expiration of the Federal Production Tax Credits in 2012.

The NSP System also fully owns and operates two wind farms.  The 101 MW Grand Meadow Wind Farm began generating electricity in 2008 and the 201 MW Nobles Wind Farm began generating electricity in 2010.  Collectively, the NSP System had over 1,600 MW and nearly 1,500 MW of wind energy on its system at the end of 2011 and 2010, respectively. Wind energy comprised 9.4 percent and 8.0 percent of the total owned and purchased energy on the NSP System for 2011 and 2010, respectively.

In 2011, NSP-Minnesota agreed to purchase 200 MW of wind power from Geronimo Wind Energy’s Prairie Rose Wind Farm, which is expected to be completed in 2012.  By the end of 2012, the NSP System plans to have over 1,900 MW of wind energy on its system.

Hydroelectric—The NSP System acquires its hydroelectric energy from both owned generation and purchased power agreements.  The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 253 MW of capacity.  For most of 2011, there were eight purchased power agreements in place which provided approximately 24 MW of hydroelectric capacity.  In December 2011, an additional nine MW of purchased hydroelectric capacity was brought onto the system.  Additionally, the NSP System purchases significant generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.  Hydroelectric energy comprised 7.5 percent and 7.4 percent of the total owned and purchased energy on the NSP System for 2011 and 2010, respectively.

Wholesale Commodity Marketing Operations

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

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota, including enforcement of NERC mandatory electric reliability standards.  State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 10 to the accompanying consolidated financial statements for discussion of other regulatory matters.

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FERC Transmission Planning and Cost Allocation — The FERC has approved the open access transmission planning processes for the RTO serving the NSP System, MISO, set forth in tariffs filed in compliance with FERC Order 890.

In July 2011, the FERC issued Order 1000 adopting modified rules for regional transmission planning, wholesale transmission cost allocation and transmission development.  The new rules would eliminate any preferential right at the federal level for an incumbent transmission provider to construct transmission facilities subject to regional cost allocation, referred to as a ROFR.  The transmission planning and cost allocation processes will be subject to additional tariff revisions subsequent to Order 1000 compliance filings due in October 2012.

The impacts of the provisions of Order 1000 regarding transmission planning and cost allocation on the NSP System are expected to not be significant as they already participate in MISO regional planning and cost allocation processes.  NSP-Minnesota is in the process of determining the impacts of the Order 1000 requirements related to future transmission development and ownership.  Irrespective of the new rules, the NSP System is pursuing several new transmission facility projects.

ARCs — In 2009, the FERC adopted rules requiring RTOs to allow ARCs to offer demand response aggregation services to end-use customers of large utilities unless the relevant state regulatory agency prohibited the operation of ARCs.  Under MISO’s proposed tariff revisions, ARCs would operate in competition with the state-regulated retail demand response programs offered by NSP-Minnesota.  In 2010, MISO requested its compliance tariff revisions be effective in June 2010, and the MPUC, NDPSC, SDPUC, PSCW, and MPSC all issued orders prohibiting, or temporarily prohibiting, the operation of ARCs in their states. 

In January 2011, the MPUC asked public utilities to explore the potential of programs with ARCs that compliment existing CIP initiatives.  In September 2011, NSP-Minnesota agreed to propose a pilot program that would expand existing retail CIP services in a manner analogous to an ARC, but complementary with its existing CIP programs.  NSP-Minnesota is waiting on the MPUC for further guidance prior to proceeding with the pilot program.

In December 2011, the FERC issued orders denying rehearing of the rules and approving most aspects of the MISO compliance filing.  The FERC retained the rules allowing state regulatory authorities to prohibit ARCs within their state.  

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

In September 2010, the FERC issued a policy statement establishing guidelines to determine the financial penalties that would be applied for violations of FERC statutes, rules and orders, including violations of NERC mandatory reliability standard violations investigated by the FERC.  The guidelines established a base violation level for various types of violations, plus mitigating or aggravating factor adders and multipliers, depending on the nature and severity of the violation.  Under the guidelines, penalties can range between a minimal amount and $290 million.  The guidelines indicate that the FERC can deviate from the guidelines in its discretion.  The guidelines can apply to any investigation where the FERC Staff has not begun settlement negotiations regarding an alleged violation.

While NSP-Minnesota cannot predict the ultimate impact new FERC regulations will have on its results of operations, cash flows or financial position, NSP-Minnesota continues to take action to comply with existing rules and to implement new FERC rules and regulations as they become effective.

NERC Compliance Audits and Self-Reports — In 2010 and 2011, the NSP System filed a self-report with the MRO potential violations of certain NERC CIPS.  Based on the issues identified with CIPS compliance, the NSP System submitted a mitigation plan that provides for a comprehensive review of the CIPS compliance programs.  Following this comprehensive review, additional self-reports of potential violations were filed.

In 2011, the NSP System was subject to a comprehensive triennial audit by the MRO regarding compliance with various NERC mandatory reliability standards, including CIPS.  The MRO found potential violations of seven standards; five are related to CIPS.  The written MRO audit reports have been issued and referred to MRO’s enforcement function for further action.  None of the potential violations are expected to result in a material penalty.

NERC Compliance Investigations — In September 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection as a result of a series of transmission line outages.  In addition, service to approximately 790 MW of load was temporarily interrupted, primarily in Saskatchewan, Canada.  In late 2010, NERC transferred responsibility for completing the compliance investigation to the MRO.  The final outcome of the compliance investigation, and whether and to what extent penalties for alleged violations may be assessed, is unknown at this time.

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In February 2010, the NERC notified NSP-Minnesota that it was commencing a non-public investigation of NSP-Minnesota maintenance practices associated with insulating oil levels in bulk electric system substations, as the result of an anonymous complaint received by the NERC.  In February 2011, NERC transferred responsibility for completing the compliance investigation to the MRO.  The MRO reviewed the status of insulating oil levels during the triennial compliance audit in the first quarter of 2011.  In July 2011, the NERC issued a preliminary findings report with three potential violations of NERC reliability standards, which NSP-Minnesota responded to in September 2011.  The final outcome of the compliance investigation and whether and to what extent penalties for alleged violations may be assessed is unknown at this time.

NERC Advisory Regarding Impact of Transmission Field Conditions on Facility Ratings — In 2010, the NERC issued an advisory requiring utilities to perform an assessment of field versus assumed “as built” transmission infrastructure conditions and allowed for affected entities to complete their initial assessment and corrective actions by 2013 and 2014, respectively.  The advisory compliance cost for NSP-Minnesota is estimated at $5.9 million.  NSP-Minnesota will seek recovery through applicable rate-making mechanisms.

Electric Transmission Rate Regulation — The FERC regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO.  The NSP System is a member 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.

MISO Transmission Pricing — Certain new higher voltage transmission facilities determined by MISO to meet RECB eligibility criteria in the MISO tariff are subject to an allocation of 20 percent of the facility costs to all loads in the 15 state MISO region.  Under specific FERC orders, certain new high voltage transmission facilities determined by MISO to meet MVP eligibility criteria are subject to an allocation of 100 percent of the facility costs to all loads on the MISO region.  The MISO independent board of directors must approve MVP eligibility before the costs of a specific project are eligible for regional rate recovery under the MISO tariff.  Certain parties have appealed the FERC MVP tariff orders to the Seventh Circuit Court of Appeals.

The MISO regional cost allocation methods require other customers in MISO to contribute to cost recovery for certain new transmission facilities constructed by the NSP System.  MISO approved the eligibility of the CapX2020 Fargo, N.D. and La Crosse, Wis. transmission expansion projects for 20 percent regional allocation.  In addition, in December 2011, the Brookings, S.D. CapX2020 transmission line was approved by MISO as an MVP, and thus eligible for 100 percent regional cost allocation.  The CapX2020 Bemidji, Minn. transmission expansion project is not eligible for regional cost allocation.  However, the NSP System also pays a share of the costs of projects constructed by other transmission-owning entities in the MISO region found to be eligible for regional cost allocation.  The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation are expected to be material in future periods.  The RECB and MVP cost allocation processes may be subject to future change to comply with FERC Order 1000.

MISO Wholesale Capacity Markets —In July 2011, MISO filed to implement a resource adequacy tariff to be effective Oct. 1, 2012.  The tariff would establish a MISO capacity market, which would allow the NSP System to purchase or sell short-term capacity in order to comply with regional reliability planning reserve requirements.  The MISO tariff proposal would allow utility capacity arrangements determined through state resource planning processes to be deemed compliant with the tariff.  The tariff proposal is pending FERC action.

Market-Based Rate Rules — The NSP System was granted market-based rate authority.  Under market-based rates, the NSP System was reauthorized to sell wholesale power at market-based rates in June 2009.  In December 2011, the NSP System filed for continued market-based rate authority, as required by FERC’s triennial market power review rules effective Jan. 1, 2012.  The request is pending FERC action.

RSG Charges — In August 2010, the FERC issued two orders relating to RSG charge exemptions and the allocation of the RSG costs among MISO participants.  MISO has since issued multiple related compliance filings with the FERC.  In recent RSG filings, MISO has proposed to allocate a greater portion of the RSG costs related to resources committed for voltage and local reliability requirements to the market participants with the loads that benefit from such commitments.  MISO has also proposed to mitigate the offers of resources committed for voltage regulation and local reliability requirements, which is expected to reduce RSG charges to other market participants under the current tariff.  NSP-Minnesota is permitted to recover the RSG costs through FCA mechanisms approved by the regulators in each jurisdiction.

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Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2011			2010			2009
Electric sales (Millions of KWh)
Residential		10,448			10,414			9,887
Large commercial and industrial		9,750			9,739			9,315
Small commercial and industrial		15,439			15,450			15,288
Public authorities and other		260			266			265
Total retail		35,897			35,869			34,755
Sales for resale		1,711			2,234			3,899
Total energy sold		37,608			38,103			38,654
Number of customers at end of period
Residential		1,245,413			1,240,509			1,231,752
Large commercial and industrial		500			502			484
Small commercial and industrial		151,144			150,392			148,703
Public authorities and other		6,470			6,291			6,055
Total retail		1,403,527			1,397,694			1,386,994
Wholesale		17			13			16
Total customers		1,403,544			1,397,707			1,387,010
Electric revenues (Thousands of Dollars)
Residential	$	1,140,598		$	1,095,862		$	1,006,380
Large commercial and industrial		660,083			627,774			588,058
Small commercial and industrial		1,270,757			1,240,979			1,151,934
Public authorities and other		34,211			33,329			31,981
Total retail		3,105,649			2,997,944			2,778,353
Wholesale		47,316			79,555			102,786
Interchange revenues from NSP-Wisconsin		440,519			416,076			389,023
Other electric revenues		179,144			131,140			137,111
Total electric revenues	$	3,772,628		$	3,624,715		$	3,407,273
KWh sales per retail customer		25,576			25,663			25,058
Revenue per retail customer	$	2,213		$	2,145		$	2,003
Residential revenue per KWh		10.92	¢		10.52	¢		10.18	¢
Large commercial and industrial revenue per KWh		6.77			6.45			6.31
Small commercial and industrial revenue per KWh		8.23			8.03			7.53
Wholesale revenue per KWh		2.76			3.56			2.64

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Energy Source Statistics

	Year Ended Dec. 31
	2011				2010				2009
NSP System	Millions of KWh		Percent of Generation		Millions of KWh	Percent of Generation			Millions of KWh	Percent of Generation
Coal		20,131	44	%	19,579		42	%	21,495		45	%
Nuclear		13,332	29		14,628		31		13,543		29
Wind (a)		4,312	9		3,760		8		3,703		8
Hydroelectric		3,444	8		3,487		7		4,395		9
Natural Gas		3,016	7		3,887		8		2,653		6
Other (b)		1,453	3		1,494		4		1,389		3
Total		45,688	100	%	46,835		100	%	47,178		100	%
Owned generation		31,668	69	%	33,758		72	%	32,975		70	%
Purchased generation		14,020	31		13,077		28		14,203		30
Total		45,688	100	%	46,835		100	%	47,178		100	%

(a) This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  The NSP System uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b) Includes energy from other sources, including solar, biomass, oil and waste.  Distributed generation from the Solar*Rewards program is not included.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of NSP-Minnesota are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small commercial and industrial (C&I) customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 2000 to 2011, average annual sales to the typical residential customer declined from 107 MMBtu per year to 86 MMBtu per year, and to the typical small C&I customer declined from 376 MMBtu to 348 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 retail natural gas operations are regulated by the MPUC and the NDPSC within their respective states.  The MPUC has regulatory authority over security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates.  In addition, the MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting customers’ future energy needs.  NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce.  NSP-Minnesota is subject to the DOT, the Minnesota Office of Pipeline Safety, the NDPSC and the SDPUC for pipeline safety compliance, including pipeline facilities used in electric utility operations for fuel deliveries.

Purchased Gas and Conservation Cost-Recovery Mechanisms—NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas.  The annual difference between the natural gas cost revenues collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period.  The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

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

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Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law on Jan. 3, 2012 (“Pipeline Safety Act”) requires, among other things, additional verification of pipeline infrastructure records by intrastate and interstate pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. Where records are inadequate to confirm the maximum allowable operating pressure, the DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure, a process that could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and/or, if appropriate, develop new regulations, addressing a variety of subjects, including: requiring use of automatic or remote-controlled shut-off valves in certain circumstances; requiring testing of previously untested transmission lines located within high consequence areas operating at a pressure greater than 30 percent of specified minimum yield stress; and expanding integrity management requirements beyond high consequence areas. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $0.2 million per violation per day up to $2 million for a related series of violations. While NSP-Minnesota cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, NSP-Minnesota is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

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 751,985 MMBtu, which occurred on Jan. 20, 2011, and 689,223 MMBtu, which occurred on Dec. 13, 2010.

NSP-Minnesota purchases natural gas from independent suppliers, generally based on market indices that reflect current prices.  The natural gas is delivered under transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of 587,811 MMBtu per day.  In addition, NSP-Minnesota contracts with providers of underground natural gas storage services.  These agreements provide storage for approximately 26 percent of winter natural gas requirements and 32 percent of peak day firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements.  These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 31 percent of peak day firm requirements.  LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another.  The 2009-2010, 2010-2011, and 2011-2012 entitlement levels are pending MPUC action.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates.  In addition, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC.  This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

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

2011	$	5.25
2010		5.43
2009		5.78

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 2012 through 2027.

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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, 2011, NSP-Minnesota was committed to approximately $394 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 32 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

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

Natural Gas Operating Statistics

	Year Ended Dec. 31
	2011		2010		2009
Natural gas deliveries (Thousands of MMBtu)
Residential		37,683		36,300		39,329
Commercial and industrial		39,878		38,609		40,408
Total retail		77,561		74,909		79,737
Transportation and other		10,797		9,455		6,784
Total deliveries		88,358		84,364		86,521
Number of customers at end of period
Residential		443,513		440,680		437,517
Commercial and industrial		41,190		40,772		40,468
Total retail		484,703		481,452		477,985
Transportation and other		17		19		15
Total customers		484,720		481,471		478,000
Natural gas revenues (Thousands of Dollars)
Residential	$	326,983	$	319,418	$	347,348
Commercial and industrial		266,258		258,943		283,953
Total retail		593,241		578,361		631,301
Transportation and other		11,482		10,683		9,022
Total natural gas revenues	$	604,723	$	589,044	$	640,323
MMBtu sales per retail customer		160.02		155.59		166.82
Revenue per retail customer	$	1,224	$	1,201	$	1,321
Residential revenue per MMBtu		8.68		8.80		8.83
Commercial and industrial revenue per MMBtu		6.68		6.71		7.03
Transportation and other revenue per MMBtu		1.06		1.13		1.33

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’s 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.  See Notes 10 and 11 to the consolidated financial statements for further discussion.

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There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.  While environmental regulations related to climate change and clean energy continue to evolve, NSP-Minnesota has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals.  Although the impact of these policies on NSP-Minnesota will depend on the specifics of state and federal policies, legislation, and regulation, we believe that, based on prior state commission practice, we would be granted the authority to recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2011, NSP-Minnesota had 3,704 full-time employees, 2,261 of which are covered under collective bargaining agreements.  See Note 7 to the consolidated financial statements for further discussion.

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, manage and, when possible, mitigate material risk; management is responsible for identifying and managing risks, while Xcel Energy Inc.’s Board of Directors oversees and holds management accountable.  As described more fully below, NSP-Minnesota is faced with a number of different types of risk.  We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2; 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 Inc.’s and NSP-Minnesota’s senior management.  Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.

Management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability.  Management broadly considers our business, the utility industry, the domestic and global economy and the environment to identify risks.  Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the 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 in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

Management seeks to mitigate the risks inherent in the implementation of Xcel Energy Inc.’s and NSP-Minnesota’s strategy.  The process for risk mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management.  At a threshold level, we have developed a robust compliance program and promote a culture of compliance, which further mitigates risk.  Building on this culture of compliance, we manage and mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services.  While 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.

Management also communicates with Xcel Energy Inc.’s Board and key stakeholders regarding risk.  Management provides information to Xcel Energy Inc.’s Board in presentations and communications over the course of the year.  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 Inc.’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.  Xcel Energy Inc.’s 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.  Xcel Energy Inc.’s 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.  The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.

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Risks Associated with Our Business

Environmental Risks

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

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.  These laws and regulations require us to obtain and comply with a wide variety of environmental 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, 2011, 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 PRP that sent hazardous materials and wastes.

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

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

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

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

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues.  We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

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

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

Financial Risks

Our profitability depends in part on 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.

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 and 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 an 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.

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 a material 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 purchased power contracts.  An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchased power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowing costs.  Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

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

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

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We are subject to credit risks.

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

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily.  The Dodd-Frank Wall Street Reform Act may require broad clearing of financial swap transactions through a central counterparty, which could lead to additional margin requirements that would impact our liquidity.  Also, in October 2010, the FERC finalized its Order 741 rulemaking addressing the credit policies of organized electric markets, such as MISO.   FERC Order 741 limits the amount of overall credit available to entities operating within organized markets and places restrictions on netting of transactions within organized markets unless certain market protocols are implemented by the RTO.  Various RTOs are in the process of filing their proposed market protocols to satisfy FERC Order 741 and these new market designs may lead to additional margin requirements that could impact our liquidity.

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 PJM and MISO, in which any credit losses are socialized to all market participants.

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

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

We have defined benefit pension and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  Therefore, our funding requirements and related contributions may change in the future.  Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

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

Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially in recent years.  Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position, and liquidity.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  Legislation related to health care could also significantly change our benefit programs and costs.

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Operational Risks

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

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products 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 or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such disruption, if significant, 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 our 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 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 use of radioactive material in the production of energy, the management, handling, storage and disposal of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

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

· Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of 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 or a substantial increase in operating expenses at our nuclear plants.  In addition, the Institute for Nuclear Power Operations reviews our nuclear operations and nuclear generation facilities.  Compliance with the Institute for Nuclear Power Operations’ recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

If an incident did occur, it could have a material effect on our results of operations or financial condition.  Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase our compliance costs and impact the results of operations of its facilities.  The events at the nuclear plant in Fukushima, Japan could result in increased regulation of the nuclear generation industry as a whole, and additional requirements with respect to emergency planning and demonstrated ability to operate nuclear facilities in the event of natural disasters or other events.  This increased regulation could increase our compliance costs and impact the results of operations of our nuclear facilities.  Furthermore, these events could cause increased regulatory review and scrutiny by the NRC which could lead to delays in the process for obtaining required regulatory reviews and approvals.

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.

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

There are inherent in our natural gas transmission and 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, and 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 effect on our financial position and results of operations.  For our natural gas transmission or distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of potential damages resulting from these risks is greater.

Additionally, the cost of potential regulations related to pipeline safety could be significant.

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

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

As of Dec. 31, 2011, Xcel Energy Inc. and its utility subsidiaries had approximately $8.8 billion of long-term debt and $1.3 billion of short-term debt and current maturities.  Xcel Energy Inc. provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy Inc.’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy Inc.’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2011, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $67.5 million and $18 million of exposure.  Xcel Energy also had additional guarantees of $31.2 million at Dec. 31, 2011 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time.  If Xcel Energy Inc. were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy Inc.’s ability to contribute equity or make loans to us, or may cause Xcel Energy Inc. to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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

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

We have historically paid quarterly dividends to Xcel Energy Inc.  In 2011, 2010 and 2009 we paid $232.5 million, $233.2 million and $232.7 million of dividends to Xcel Energy Inc., respectively.  If Xcel Energy Inc.’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy Inc. to help support Xcel Energy Inc.’s cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is limited to some extent by our indenture for our first mortgage bonds.

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Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs.  Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  In 2009, the U.S. submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord and negotiations continue under the United Nations Framework Convention on Climate Change.  Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities 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. In December 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 created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles.  In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold.  The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants, although the EPA announced in late September 2011 that this proposed rule will be delayed.

We are 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 11 to the consolidated financial statements.  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.

There are many uncertainties regarding when and in what form climate change legislation or regulations will be enacted.  The impact of legislation and regulations, 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 recognized as compliance options, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices.  While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations.  Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities.  These include, but are not limited to, rules associated with emissions of SO2and NOx, mercury, regional haze, ozone, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased 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, electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by regional entities, the NERC or the FERC for violations.  If a serious reliability incident did occur, it could have a material effect on our operations or financial results.

Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions.  The consequences of a prolonged economic recession and uncertainty of recovery may result in a sustained lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets.  A sustained lower level of economic activity may also 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.

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

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

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

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material effect on our business.  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 comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance 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.  For example, wildfire events, particularly in the geographic areas we serve, may cause insurance for wildfire losses to become difficult or expensive to obtain.

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 impact on our financial condition and results.

The degree to which we are able to maintain day-to-day operations in response to unforeseen events, potentially through the execution of our business continuity plans, will in part determine the financial impact of certain events on our financial condition and results.  It’s difficult to predict the magnitude of such events and associated impacts.

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

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets could be directly or indirectly affected by unintentional or deliberate cyber incidents.  Cyber intrusion or other similar events could harm our businesses by limiting our generating, transmitting and distributing capabilities or delay our development and construction of new facilities or capital improvement projects to existing facilities.  In addition, as generation and transmission systems as well as natural gas pipelines are part of an interconnected system, a disruption caused by the impact of a cyber security event of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources could also negatively impact our business. We are unable to quantify the potential impact of such cyber security threats. These events and corresponding regulatory action, if any, could result in a material decrease in revenues and may causesignificant additional costs (e.g., repairs/insurance) and potentially disrupt our supply and markets for natural gas, oil and other fuels. 

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  Despite our control environment and security measures, our technology systems may be vulnerable to disability, failures or unauthorized access due to cyber intrusion.  If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting.  In addition, confidential and other data, including sensitive customer or employee information, could be compromised exposing us to liability and business disruption.

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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 and/or increase bad debt expense, which could also have a material impact on our results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

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

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

Item 1B — Unresolved Staff Comments

None.

Item 2 — Properties

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

Electric Utility Generating Stations:			Summer 2011
			Net Dependable
Station, Location and Unit	Fuel	Installed	Capability (MW)
Steam:
A.S. King-Bayport, Minn.	Coal	1968		511
Sherco-Becker, Minn.
Unit 1	Coal	1976		680
Unit 2	Coal	1977		682
Unit 3	Coal	1987		507	(a)
Monticello-Monticello, Minn.	Nuclear	1971		554
Prairie Island-Welch, Minn.
Unit 1	Nuclear	1973		521
Unit 2	Nuclear	1974		519
Black Dog-Burnsville, Minn., 2 Units	Coal/Natural Gas	1955-1960		232
Various locations, 4 Units	Wood/Refuse-derived fuel	Various		36	(b)
Combustion Turbine:
Angus Anson-Sioux Falls, S.D., 3 Units	Natural Gas	1994-2005		338
Black Dog-Burnsville, Minn., 2 Units	Natural Gas	1987-2002		236
Blue Lake-Shakopee, Minn., 6 Units	Natural Gas	1974-2005		462
High Bridge-St. Paul, Minn., 3 Units	Natural Gas	2008		486
Inver Hills-Inver Grove Heights, Minn., 6 Units	Natural Gas	1972		282
Riverside-Minneapolis, Minn., 3 Units	Natural Gas	2009		470
Various locations, 18 Units	Natural Gas	Various		107
Wind:
Grand Meadow-Mower County, Minn., 67 Units	Wind	2008		101	(c)
Nobles-Nobles County, Minn., 134 Units	Wind	2010		201	(c)
		Total		6,925

(a) Based on NSP-Minnesota’s ownership of 59 percent.  In November 2011, Sherco Unit 3, jointly owned by NSP-Minnesota and Southern Minnesota Municipal Power Agency, experienced a significant failure of its turbine, generator, and exciter systems.  See Note 5 to the consolidated financial statements for further discussion.

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

(c) This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.  Therefore, the on-demand net dependable capacity is zero.

26

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2011:

Conductor Miles
500 KV	2,917
345 KV	6,388
230 KV	1,801
161 KV	275
115 KV	7,691
Less than 115 KV	82,706

NSP-Minnesota had 372 electric utility transmission and distribution substations at Dec. 31, 2011.

Natural gas utility mains at Dec. 31, 2011:

Miles
Transmission	137
Distribution	9,688

Item 3 — Legal Proceedings

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

Additional Information

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

Item 4 — Mine Safety Disclosures

None.

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 of Xcel Energy Inc. 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 Inc., the holder of its common stock.  Even with these restrictions, NSP-Minnesota could have paid more than $1.1 billion in additional cash dividends on common stock at Dec. 31, 2010, or $1.2 billion at Dec. 31, 2011.

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

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

· State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc. by requiring an equity-to-total capitalization ratio between 47.07 percent and 57.53 percent.  NSP-Minnesota’s equity-to-capitalization ratio was 52.1 percent at Dec. 31, 2011.  Total capitalization for NSP-Minnesota cannot exceed $8.25 billion.

See Note 4 to the consolidated financial statements for further discussion of NSP-Minnesota’s dividend policy.

27

The dividends declared during 2011 and 2010 were as follows:

(Thousands of Dollars)	2011		2010
First quarter	$	57,635	$	57,675
Second quarter		58,258		58,479
Third quarter		58,245		58,655
Fourth quarter		58,054		58,372

Item 6 — Selected Financial Data

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

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

Discussion of financial condition and liquidity for 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).

Financial Review

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

Forward-Looking 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 inflation rates, monetary fluctuations and their impact capital expenditures and the ability of NSP-Minnesota and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth recovery; actions of credit agencies; trade, fiscal, taxation and environmental polices in areas where NSP-Minnesota has a financial interest; customer business conditions; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota and its subsidiaries; 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; actions by regulatory bodies impacting NSP-Minnesota’s nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee workforce factors; 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 this Annual Report on Form 10-K and Exhibit 99.01 hereto.

Results of Operations

NSP-Minnesota’s net income was approximately $353 million for 2011, compared with approximately $274 million for 2010.  The increase was primarily due to higher interim electric rates effective in early 2011, subject to refund, in Minnesota and North Dakota, and conservation improvement program incentives partially offset by higher O&M expenses, depreciation expense (net of regulatory adjustments) and property taxes.

28

Electric Revenues and Margins

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin.  The following table details the electric revenues and margin:

(Millions of Dollars)	2011			2010
Electric revenues	$	3,773		$	3,625
Electric fuel and purchased power		(1,543	)		(1,536	)
Electric margin	$	2,230		$	2,089

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)	2011 vs. 2010
Retail rate increase (net of revenue subject to refund) (a)	$	70
Fuel and purchased power cost recovery		42
Conservation revenue (offset by expenses)		36
Interchange agreement billing with NSP-Wisconsin		24
Transmission revenue		17
Conservation incentive		11
Trading		(17	)
Non-fuel riders		(16	)
Firm wholesale		(15	)
Other, net		(4	)
Total increase in electric revenues	$	148

(a)  The retail rate increases include interim rates subject to refund in Minnesota and North Dakota.  The rate increases are net of a provision for refund of approximately $67 million for Minnesota and $2.3 million for North Dakota, based on settlements reached with various parties in both cases.  In addition, NSP-Minnesota reduced depreciation expense and revenues by approximately $30 million in the fourth quarter of 2011 to reflect the proposed settlement in the Minnesota electric rate case.  These settlements are pending commission decisions in both Minnesota and North Dakota.

Electric Margin

(Millions of Dollars)	2011 vs. 2010
Retail rate increase (net of revenue subject to refund) (a)	$	70
Conservation revenue (offset by expenses)		36
Deferred fuel adjustments		20
Interchange agreement billing with NSP-Wisconsin		14
Conservation incentive		11
Timing of fuel recovery		11
Non-fuel riders		(16	)
Other, net		(5	)
Total increase in electric margin	$	141

(a)  The retail rate increases include interim rates subject to refund in Minnesota and North Dakota.  The rate increases are net of a provision for refund of approximately $67 million for Minnesota and $2.3 million for North Dakota, based on settlements reached with various parties in both cases.  In addition, NSP-Minnesota reduced depreciation expense and revenues by approximately $30 million in the fourth quarter of 2011 to reflect the proposed settlement in the Minnesota electric rate case.  These settlements are pending commission decisions in both Minnesota and North Dakota.

29

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.  The following table details natural gas revenues and margin:

(Millions of Dollars)	2011			2010
Natural gas revenues	$	605		$	589
Cost of natural gas sold and transported		(394	)		(400	)
Natural gas margin	$	211		$	189

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)	2011 vs. 2010
Conservation revenue and incentive (partially offset by expenses)	$	16
Estimated impact of weather		3
Purchased natural gas adjustment clause recovery		(5	)
Other, net		2
Total increase in natural gas revenues	$	16

Natural Gas Margin

(Millions of Dollars)	2011 vs. 2010
Conservation revenue and incentive (partially offset by expenses)	$	16
Estimated impact of weather		3
Other, net		3
Total increase in natural gas margin	$	22

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $26.9 million, or 2.6 percent, for 2011 compared to 2010.  The following table summarizes the changes in O&M expenses for the year ended Dec. 31:

(Millions of Dollars)	2011 vs. 2010
Higher nuclear plant operation costs	$	12
Higher interchange costs		8
Higher plant generation costs		4
Higher insurance costs		4
Other, net		(1	)
Total increase in O&M expenses	$	27

· Higher nuclear plant operation costs were largely driven by outages.

· Higher interchange costs are due to increased fixed charges.

· Higher plant generation costs are attributable to a higher level of scheduled maintenance and overhaul work.

Conservation Program Expenses — Conservation program expenses increased $51.7 million for 2011, compared with 2010.  The higher expense was primarily attributable to the continued expansion of programs and regulatory commitments.  NSP-Minnesota has established conservation incentive programs designed to encourage its retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas and/or electric system.  This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers.  NSP-Minnesota generally recovers conservation program expenses concurrently through riders and base rates.

30

Depreciation and Amortization — Depreciation and amortization expense decreased by approximately $20.1 million, or 5.0 percent, for 2011, compared with 2010.  This decrease is primarily due to NSP-Minnesota reducing depreciation expense by approximately $30 million in the fourth quarter of 2011 to reflect the proposed settlement in the Minnesota electric rate case.  This was partially offset by several capital projects, including a portion of the Monticello extended power uprate going into service in May 2011 and the Nobles wind project commencing commercial operations in late 2010 and normal system expansion.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased by approximately $9.8 million, or 6.0 percent, for 2011, compared with 2010.  The increase was due to increased property taxes, primarily in Minnesota.

AFUDC — AFUDC increased by approximately $0.5 million, or 0.9 percent, for 2011 compared with 2010.  The increase was primarily due to construction projects related to the Monticello extended power uprate, partially offset by lower AFUDC rates.

Interest Charges — Interest charges increased by approximately $6.6 million, or 3.3 percent, for 2011, compared with 2010.  The increase is due to higher long-term debt levels to fund investments in utility operations, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $10.5 million for 2011, compared with 2010. The increase in income tax expense was primarily due to an increase in pretax income, partially offset by an increase in wind production tax credits in 2011, a decrease in state income taxes in 2011 and a write-off of tax benefits previously recorded for Medicare Part D subsidies in 2010. The effective tax rate was 35.2 percent for 2011, compared with 39.8 percent for 2010. The lower effective tax rate for 2011 was primarily due to higher wind production tax credits and decreased state income taxes in 2011.

The effective tax rates for 2011 and 2010 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 6 to the consolidated financial statements for further discussion.

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.  See Note 9 to the consolidated financial statements for further discussion of market risks associated with derivatives.

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

31

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)	2011			2010
Fair value of commodity trading net contract assets outstanding at Jan. 1	$	18,431		$	8,976
Contracts realized or settled during the period		(9,034	)		(8,261	)
Unrealized commodity trading transactions during the period		9,763			17,716
Fair value of commodity trading net contract assets outstanding at Dec. 31	$	19,160		$	18,431

At Dec. 31, 2011, 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

$

4,317

$

14,843

$

-

$

-

$

19,160

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

At Dec. 31, 2011, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.2 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.2 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, including transactions that are not recorded at fair value, 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 using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:

	Year Ended
(Millions of Dollars)	Dec. 31		VaR Limit		Average		High		Low
2011	$	0.09	$	3.00	$	0.14	$	0.33	$	0.04
2010		0.15		3.00		0.22		0.64		0.03

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, 2011, NSP-Minnesota had unsettled interest rate swaps outstanding with a notional amount of $225 million related to an expected 2012 debt issuance.

At Dec. 31, 2011, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense by approximately $0.9 million annually. See Note 9 to the consolidated financial statements for a discussion of NSP-Minnesota’s interest rate derivatives.

NSP-Minnesota also maintains a nuclear decommissioning fund as required by the NRC.  The nuclear decommissioning fund is subject to interest rate risk and equity price risk.  At Dec. 31, 2011, the fund was invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments.  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, 2011, a 10 percent increase in prices would have resulted in a decrease in credit exposure of $0.9 million, while a decrease of 10 percent in prices would have resulted in an increase in credit exposure of $5.1 million.

32

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

Commodity Derivatives — 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, 2011.  Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues when necessary.  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, 2011.

Commodity derivative 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 liabilities represent approximately 1.5 percent of total liabilities measured at fair value at Dec. 31, 2011.  Level 3 commodity derivative assets represent an immaterial percent of total assets measured at fair value at Dec. 31, 2011.

Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management’s forecasts for several of these inputs, these instruments have been assigned a Level 3.  Level 3 commodity derivatives assets and liabilities include $13.3 million and $0.9 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2011.

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 delivery 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.  There were no Level 3 commodity forwards or options held at Dec. 31, 2011.

Nuclear Decommissioning Fund — Nuclear decommissioning fund assets assigned to Level 3 consist of asset-backed and mortgage-backed securities, private equity investments and real estate investments.  To the extent appropriate, observable market inputs are utilized to estimate the fair value of asset-backed and mortgage-backed securities; however, less observable and subjective inputs are often significant to these valuations, including risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated prepayments of principal.  Measurement of private equity investments and real estate investments at net asset value requires significant use of unobservable inputs when determining the fair value of the underlying fund investments, including equity in non-publicly traded entities and real estate properties.  Therefore, estimated fair values for asset-backed and mortgage-backed securities, private equity investments and real estate investments totaling $130.8 million in the nuclear decommissioning fund at Dec. 31, 2011 (approximately 9.4 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 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 17 to the consolidated financial statements for summarized quarterly financial data.

33

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 Xcel Energy Inc.’s and NSP-Minnesota’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 NSP-Minnesota’s internal control over financial reporting as of Dec. 31, 2011.  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, 2011, NSP-Minnesota’s internal control over financial reporting is effective based on those criteria.

/S/ JUDY M. POFERL	/S/ TERESA S. MADDEN
Judy M. Poferl	Teresa S. Madden
President, Chief Executive Officer and Director	Senior Vice President, Chief Financial Officer and Director
Feb. 27, 2012	Feb. 27, 2012

34

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Northern States Power Company, a Minnesota corporation

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, 2011 and 2010, 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, 2011.  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.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

Feb. 27, 2012

35

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2011			2010			2009
Operating revenues
Electric	$	3,772,628		$	3,624,715		$	3,407,273
Natural gas		604,723			589,044			640,323
Other		21,170			20,557			19,093
Total operating revenues		4,398,521			4,234,316			4,066,689
Operating expenses
Electric fuel and purchased power		1,542,760			1,536,076			1,411,877
Cost of natural gas sold and transported		393,672			399,524			464,043
Cost of sales — other		12,737			12,405			11,076
Operating and maintenance expenses		1,064,665			1,037,752			968,370
Conservation program expenses		138,001			86,298			59,244
Depreciation and amortization		381,025			401,136			389,367
Taxes (other than income taxes)		172,726			162,901			147,193
Total operating expenses		3,705,586			3,636,092			3,451,170
Operating income		692,935			598,224			615,519
Other income, net		1,717			1,151			1,572
Allowance for funds used during construction — equity		37,164			38,341			28,848
Interest charges and financing costs
Interest charges — includes other financing costs of $6,264, $5,645, and $5,778, respectively		208,003			201,431			194,808
Allowance for funds used during construction — debt		(20,817	)		(19,131	)		(17,760	)
Total interest charges and financing costs		187,186			182,300			177,048
Income before income taxes		544,630			455,416			468,891
Income taxes		191,649			181,191			175,121
Net income	$	352,981		$	274,225		$	293,770

See Notes to Consolidated Financial Statements

36

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2011			2010			2009
Operating activities
Net income	$	352,981		$	274,225		$	293,770
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		386,310			401,602			394,712
Nuclear fuel amortization		100,902			105,369			80,104
Deferred income taxes		196,120			251,747			177,347
Amortization of investment tax credits		(2,694	)		(2,697	)		(3,120	)
Allowance for equity funds used during construction		(37,164	)		(38,341	)		(28,848	)
Provision for bad debts		15,936			15,213			19,408
Net derivative gains		(182	)		(8,784	)		(4,960	)
Changes in operating assets and liabilities:
Accounts receivable		(8,195	)		(24,216	)		74,818
Accrued unbilled revenues		18,090			(20,055	)		19,113
Inventories		(21,675	)		(24,254	)		89,984
Other current assets		(614	)		(858	)		(13,589	)
Accounts payable		(33,806	)		(70,715	)		39,229
Net regulatory assets and liabilities		75,390			18,575			(70,879	)
Other current liabilities		91,532			39,899			19,066
Pension and other employee benefit obligations		(39,925	)		(19,623	)		(8,111	)
Change in other noncurrent assets		(7,330	)		459			44
Change in other noncurrent liabilities		(36,345	)		(23,250	)		(17,011	)
Net cash provided by operating activities		1,049,331			874,296			1,061,077
Investing activities
Utility capital/construction expenditures		(1,028,831	)		(1,208,268	)		(835,262	)
Merricourt refund		101,261			-			-
Merricourt deposit		(90,833	)		(1,134	)		(9,294	)
Allowance for equity funds used during construction		37,164			38,341			28,848
Purchases of investments in external decommissioning fund		(2,098,642	)		(3,781,438	)		(1,644,278	)
Proceeds from the sales of investments in external decommissioning fund		2,098,642			3,786,373			1,664,957
Investments in utility money pool arrangement		(432,000	)		(246,000	)		(132,500	)
Repayments from utility money pool arrangement		432,000			253,000			125,500
Advances to affiliate		(111,300	)		(302,300	)		(62,500	)
Advances from affiliate		148,300			280,800			47,000
Change in restricted cash		(95,287	)		-			-
Other, net		(5,668	)		509			(6,415	)
Net cash used in investing activities		(1,045,194	)		(1,180,117	)		(823,944	)
Financing activities
Issuances (repayments) of short-term borrowings, net		26,000			-			(65,000	)
Borrowings under utility money pool arrangement		627,600			711,000			601,700
Repayments under utility money pool arrangement		(562,600	)		(711,000	)		(665,200	)
Proceeds from issuance of long-term debt		-			493,390			295,340
Repayment of long-term debt, including reacquisition premiums		(34	)		(175,034	)		(250,041	)
Capital contributions from parent		125,004			212,794			112,736
Dividends paid to parent		(232,510	)		(233,224	)		(232,708	)
Net cash (used in) provided by financing activities		(16,540	)		297,926			(203,173	)
Net change in cash and cash equivalents		(12,403	)		(7,895	)		33,960
Cash and cash equivalents at beginning of period		38,408			46,303			12,343
Cash and cash equivalents at end of period	$	26,005		$	38,408		$	46,303
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(181,121	)	$	(172,463	)	$	(178,017	)
Cash (paid) received for income taxes, net		(15,964	)		81,836			24,719
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	35,058		$	59,836		$	34,172

See Notes to Consolidated Financial Statements

37

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands, except share and per share data)

	Dec. 31
Assets	2011			2010
Current assets
Cash and cash equivalents	$	26,005		$	38,408
Restricted cash		95,287			-
Notes receivable from affiliates		-			37,000
Accounts receivable, net		314,577			313,485
Accounts receivable from affiliates		18,033			26,866
Accrued unbilled revenues		231,303			249,393
Inventories		301,848			280,173
Regulatory assets		141,709			164,943
Derivative instruments		51,517			39,892
Prepayments and other		45,219			39,229
Total current assets		1,225,498			1,189,389
Property, plant and equipment, net		8,982,834			7,822,220
Other assets
Nuclear decommissioning fund and other investments		1,357,538			1,366,069
Regulatory assets		872,014			671,391
Derivative instruments		80,689			101,258
Other		36,638			31,333
Total other assets		2,346,879			2,170,051
Total assets	$	12,555,211		$	11,181,660
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	450,000		$	19
Short-term debt		26,000			-
Borrowings under utility money pool arrangement		65,000			-
Accounts payable		322,979			384,455
Accounts payable to affiliates		47,651			61,753
Taxes accrued		158,319			140,020
Accrued interest		68,362			66,641
Dividend payable to parent		58,054			58,372
Derivative instruments		65,781			27,311
Regulatory liabilities		132,574			42,122
Other		164,736			103,525
Total current liabilities		1,559,456			884,218
Deferred credits and other liabilities
Deferred income taxes		1,666,005			1,449,082
Deferred investment tax credits		31,743			34,437
Asset retirement obligations		1,581,896			875,361
Regulatory liabilities		439,029			462,574
Pension and employee benefit obligations		413,755			351,130
Derivative instruments		184,190			197,771
Other		65,464			93,025
Total deferred credits and other liabilities		4,382,082			3,463,380
Commitments and contingencies
Capitalization
Long-term debt		2,888,897			3,337,893
Common stock – 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2011 and 2010		10			10
Additional paid in capital		2,366,391			2,241,387
Retained earnings		1,372,727			1,251,938
Accumulated other comprehensive (loss) income		(14,352	)		2,834
Total common stockholder's equity		3,724,776			3,496,169
Total liabilities and equity	$	12,555,211		$	11,181,660

See Notes to Consolidated Financial Statements

38

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(amounts in thousands, except share data)

	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, 2008		1,000,000	$	10	$	1,915,857	$	1,149,833		$	205		$	3,065,905
Net income								293,770						293,770
Pension and retiree medical benefit adjustments, net of tax of $143											208			208
Net derivative instrument changes, net of tax of $615											888			888
Unrealized loss - marketable securities, net of tax of $284											411			411
Comprehensive income for the period														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
Net income								274,225						274,225
Pension and retiree medical benefit adjustments, net of tax of $(30)											(43	)		(43	)
Net derivative instrument changes, net of tax of $717											1,036			1,036
Unrealized loss - marketable securities, net of tax of $89											129			129
Comprehensive income for the period														275,347
Common dividends declared to parent								(233,181	)					(233,181	)
Contribution of capital by parent						212,794								212,794
Balance at Dec. 31, 2010		1,000,000	$	10	$	2,241,387	$	1,251,938		$	2,834		$	3,496,169
Net income								352,981						352,981
Pension and retiree medical benefit adjustments, net of tax of $(262)											(388	)		(388	)
Net derivative instrument changes, net of tax of $(11,516)											(16,706	)		(16,706	)
Unrealized gain - marketable securities, net of tax of $(63)											(92	)		(92	)
Comprehensive income for the period														335,795
Common dividends declared to parent								(232,192	)					(232,192	)
Contribution of capital by parent						125,004								125,004
Balance at Dec. 31, 2011		1,000,000	$	10	$	2,366,391	$	1,372,727		$	(14,352	)	$	3,724,776

See Notes to Consolidated Financial Statements

39

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

(amounts in thousand, except share and per share data)

	Dec. 31
	2011			2010
Long-Term Debt
First Mortgage Bonds, Series due:
Aug. 28, 2012, 8%	$	450,000		$	450,000
Aug. 15, 2015, 1.95%		250,000			250,000
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			300,000
Aug. 15, 2040, 4.85%		250,000			250,000
Other		8			32
Unamortized discount		(8,011	)		(9,020	)
Total		3,338,897			3,337,912
Less current maturities		450,000			19
Total long-term debt	$	2,888,897		$	3,337,893
Common Stockholder’s Equity
Common stock — 5,000,000 authorized shares of $0.01 par value, 1,000,000 shares outstanding at Dec. 31, 2011 and 2010, respectively	$	10		$	10
Additional paid in capital		2,366,391			2,241,387
Retained earnings		1,372,727			1,251,938
Accumulated other comprehensive (loss) income		(14,352	)		2,834
Total common stockholder’s equity	$	3,724,776		$	3,496,169

(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 regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  NSP-Minnesota’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of NSP-Minnesota’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation— NSP-Minnesota’s consolidated financial statements include its wholly-owned subsidiaries.  In the consolidation process, all intercompany transactions and balances are eliminated.  NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.  NSP-Minnesota’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and NSP-Minnesota’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.  See Note 5 for further discussion of jointly owned generation and transmission facilities and related ownership percentages.

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

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

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

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

· Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

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

If restructuring or other changes in the regulatory environment occur, 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 financial condition, results of operations and cash flows in the period the write-offs are recorded.  See Note 13 for further discussion of regulatory assets and liabilities.

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

NSP-Minnesota participates in MISO.  The revenues and charges from MISO related to serving retail and wholesale electric customers comprising the native load of NSP-Minnesota are recorded on a net basis within cost of sales.   Revenues and charges for short term wholesale sales of excess energy transacted through MISO are recorded on a gross basis in electric revenues and cost of sales.

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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 cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Conservation Programs — NSP-Minnesota has implemented programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems.  These programs include, but are not limited to, commercial process efficiency and lighting updates, and residential rebates for participation in air conditioning interruption and energy-efficient appliances.

The costs incurred for CIP programs are deferred if it is probable that future revenue, in an amount at least equal to the deferred amount, will be provided to permit recovery of the previously incurred cost, rather than to provide for expected future amounts of similar programs.  For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned.

NSP-Minnesota’s CIP program costs are recovered through a combination of base rate revenue and rider mechanisms.  The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage NSP-Minnesota’s achievement of energy conservation goals and to compensate for related lost sales margin.  NSP-Minnesota recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

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.  Amounts recovered in rates for future removal costs are recorded as regulatory liabilities.  Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.  Maintenance and replacement of items determined to be less than 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.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.  Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable.

NSP-Minnesota records depreciation expense related to its plant 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, 2011, 2010 and 2009 was 3.2, 3.4 and 3.2 percent, respectively.

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

AFUDC— AFUDC represents the cost of capital used to finance utility construction activity.  AFUDC is computed by applying a composite pretax rate to qualified CWIP.  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, cost of capital 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.  However, in some cases, including for certain wind and transmission projects, the MPUC has approved a more current recovery of financing costs associated with large capital projects, through various riders, resulting in a lower recognition of AFUDC.

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

Nuclear Decommissioning – Nuclear decommissioning studies estimate NSP-Minnesota’s ultimate costs of decommissioning its nuclear power plants and are performed at least every three years and submitted to the MPUC for approval.  NSP-Minnesota filed its most recent triennial nuclear decommissioning studies with the MPUC in December 2011.  These studies reflect NSP-Minnesota’s plans, under the current operating licenses, for prompt dismantlement of the Monticello and Prairie Island facilities.  These studies assume that NSP-Minnesota will be storing spent fuel on site pending removal to a U.S. government facility.

For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants, including operating costs associated with spent fuel, over each facility’s expected service life based on the triennial decommissioning studies filed with the MPUC.  The costs are initially determined in nominal amounts prior to escalation adjustments, then future periods’ costs are escalated using decommissioning-specific cost escalators and finally discounted using risk-free interest rates.  See Note 12 for further discussion of the approved nuclear decommissioning obligation.

For financial reporting purposes, NSP-Minnesota recognizes decommissioning liabilities, excluding future operating costs associated with spent fuel, in accordance with accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred.  In accordance with regulatory accounting, any difference between expense recognized for financial reporting purposes and the amount recovered in rates is reported as a regulatory asset or liability.  Costs are initially determined in nominal amounts prior to escalation adjustments, then future periods’ costs are escalated using decommissioning-specific cost escalators and then discounted using weighted-average credit-adjusted risk-free interest rates.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota’s nuclear facilities are included in the nuclear decommissioning fund on the consolidated balance sheets.  See Note 9 for further discussion of the nuclear decommissioning fund.

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 and costs associated with the end-of-life fuel segments.

Nuclear Refueling Outage Costs —NSP-Minnesota uses a deferral and amortization method for nuclear refueling O&M costs.  This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates.

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 resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

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NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  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.

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

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments — 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 the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  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 as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

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

Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for the purchase and sale of commodities for use in its business operations.  Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting 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.

See Note 9 for further discussion of NSP-Minnesota’s risk management and derivative activities.

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 electric operating revenues in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of NSP-Minnesota’s commodity trading margins 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 and commodity trading results include the impact of all margin-sharing mechanisms.  For further information, see Note 9.

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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; money market funds are measured using quoted net asset values.  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.  For further information, see Note 9.

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.

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

Inventory— All inventory is recorded at average cost.

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 RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced.  Currently, NSP-Minnesota acquires RECs from the generation or purchase of renewable power.

When RECs are acquired in the course of generation or purchased as a result of meeting load obligations, they are recorded as inventory at cost.  The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.

Sales of RECs that are acquired in the course of generation or purchased as a result of meeting load obligations are recorded in electric utility operating revenues on a gross basis.  The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.  RECs acquired for trading purposes are recorded as other investments and are also recorded at cost.  The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms.

Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA, are recorded at cost plus associated broker commission fees.  NSP-Minnesota follows the inventory accounting model for all emission allowances.  The sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

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 are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates.  Otherwise, the costs are expensed.  If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded.  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 other participating PRPs exist and acknowledge their potential involvement with a site, 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.

See Note 11 for further discussion of environmental costs.

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

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

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

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

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

Reclassifications – Certain prior year amounts have been reclassified to conform to the current year presentation. Changes in pension and other employee benefit obligations were reclassified as a separate item from changes in other noncurrent liabilities within the consolidated statements of cash flows.  These reclassifications did not have an impact on net cash provided by operating activities.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2011 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2.        Accounting Pronouncements

Recently Adopted

Multiemployer Plans — In September 2011, the FASB issued Multiemployer Plans (Subtopic 715-80) — Disclosures about an Employer’s Participation in a Multiemployer Plan (ASU No. 2011-09), which updates the Codification to require certain disclosures about an entity’s involvement with multiemployer pension and other postretirement benefit plans.  These updates do not affect recognition and measurement guidance for an employer’s participation in multiemployer plans, but rather require additional disclosure such as the nature of multiemployer plans and the employer’s participation, contributions to the plans and details regarding any significant plans.  These updates to the Codification are effective for annual periods ending after Dec. 15, 2011.  NSP-Minnesota implemented the annual disclosure guidance effective Jan. 1, 2011, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures,

see Note 7.

Recently Issued

Fair Value Measurement — In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU No. 2011-04), which provides additional guidance for fair value measurements.  These updates to the Codification include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of OCI and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota does not expect the implementation of this presentation guidance to have a material impact on its consolidated financial statements.

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Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which updates the Codification to require disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  These updates to the disclosure requirements of the Codification do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those periods.  NSP-Minnesota does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

3.        Selected Balance Sheet Data

	Dec. 31
(Thousands of Dollars)	2011			2010
Accounts receivable, net
Accounts receivable	$	337,581		$	334,481
Less allowance for bad debts		(23,004	)		(20,996	)
	$	314,577		$	313,485
Inventories
Materials and supplies	$	124,961		$	122,706
Fuel		113,711			95,804
Natural gas		63,176			61,663
	$	301,848		$	280,173
Property, plant and equipment, net
Electric plant	$	11,948,041		$	10,563,424
Natural gas plant		1,006,163			979,256
Common and other property		525,139			510,577
Construction work in progress		639,246			695,292
Total property, plant and equipment		14,118,589			12,748,549
Less accumulated depreciation		(5,433,106	)		(5,222,980	)
Nuclear fuel		1,939,299			1,837,697
Less accumulated amortization		(1,641,948	)		(1,541,046	)
	$	8,982,834		$	7,822,220

4.       Borrowings and Other Financing Instruments

Short-Term Borrowings

Commercial Paper — NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.  Commercial paper outstanding for NSP-Minnesota was as follows:

	Three Months Ended
(Amounts in Millions, Except Interest Rates)	Dec. 31, 2011
Borrowing limit	$	500
Amount outstanding at period end		26
Average amount outstanding		1
Maximum amount outstanding		27
Weighted average interest rate, computed on a daily basis		0.43	%
Weighted average interest rate at end of period		0.45
	Twelve Months Ended			Twelve Months Ended			Twelve Months Ended
(Amounts in Millions, Except Interest Rates)	Dec. 31, 2011			Dec. 31, 2010			Dec. 31, 2009
Borrowing limit	$	500		$	482		$	482
Amount outstanding at period end		26			-			-
Average amount outstanding		7			35			59
Maximum amount outstanding		80			389			266
Weighted average interest rate, computed on a daily basis		0.34	%		0.37	%		0.73	%
Weighted average interest rate at end of period		0.45			N/A			N/A

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Credit Facilities — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under the credit agreement.

During 2011, NSP-Minnesota executed a new four-year credit agreement.  The total size of the credit facility is $500 million and terminates in March 2015. NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.  Other features of NSP-Minnesota’s credit facility include:

· The credit facility may be increased by up to $100 million.

· The credit facility has a 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 at Dec. 31, 2011.  If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

· The credit facility has a cross-default provision that provides NSP-Minnesota will be in default on its borrowings under the facility if NSP-Minnesota or any of its subsidiaries whose total assets exceed 15 percent of NSP-Minnesota’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

· The interest rates under the line of credit are based on the Eurodollar rate or an alternate base rate, plus a borrowing margin of 0 to 200 basis points per year based on the applicable credit ratings.

· The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the line of credit at a range of 10 to 35 basis points per year.

· NSP-Wisconsin’s intercompany borrowing arrangement with NSP-Minnesota was subsequently terminated.

At Dec. 31, 2011, NSP-Minnesota had the following committed credit facility available (in millions):

Credit Facility		Drawn (a)		Available
$	500.0	$	33.7	$	466.3

(a) Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Minnesota had no direct advances on the credit facility outstanding at Dec. 31, 2011 and 2010.

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, 2011 and 2010, there were $7.7 million and $5.3 million of letters of credit outstanding, respectively, under the credit facility.  An additional $1.1 million of letters of credit not issued under the credit facility were outstanding at Dec. 31, 2011 and 2010, respectively.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries.  Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.  Money pool borrowings outstanding for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended  Dec. 31, 2011
Borrowing limit	$	250
Amount outstandingat period end		65
Average amount outstanding		55
Maximum amount outstanding		80
Weighted average interest rate, computed on a daily basis		0.34	%
Weighted average interest rate at end of period		0.35

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(Amounts in Millions, Except Interest Rates)	Twelve Months Ended  Dec. 31, 2011			Twelve Months Ended Dec. 31, 2010			Twelve Months Ended Dec. 31, 2009
Borrowing limit	$	250		$	250		$	250
Amount outstandingat period end		65			-			7
Average amount outstanding		17			18			37
Maximum amount outstanding		80			142			132
Weighted average interest rate, computed on a daily basis		0.34	%		0.37	%		0.67	%
Weighted average interest rate at end of period		0.35			N/A			0.36

Long-Term Borrowings and Other Financing Instruments

Generally, all real and personal property of NSP-Minnesota is subject to the lien of its first mortgage indenture.  Additionally, 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.

In August 2010, NSP-Minnesota issued $250 million of 1.95 percent first mortgage bonds, due Aug. 15, 2015 and $250 million of 4.85 percent first mortgage bonds, due Aug. 15, 2040.

During the next five years, NSP-Minnesota has long-term debt maturities of $450 million and $250 million due in 2012 and 2015, respectively.  NSP-Minnesota plans to refinance the current portion of long-term debt coming due in 2012.

Deferred Financing Costs— Other assets included deferred financing costs of approximately $25.2 million and $27.2 million, net of amortization, at Dec. 31, 2011 and 2010, respectively.  NSP-Minnesota is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend and Other Capital-Restrictions — NSP-Minnesota’s 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. 

NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy Inc., the holder of its common stock.  Even with these restrictions, NSP-Minnesota could have paid more than $1.1 billion in additional cash dividends on common stock at Dec. 31, 2010, or $1.2 billion at Dec. 31, 2011.

NSP-Minnesota’s state regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc. by requiring an equity-to-total capitalization ratio between 47.07 percent and 57.53 percent.  NSP-Minnesota’s equity-to-total capitalization ratio was 52.1 percent at Dec. 31, 2011.  Total capitalization for NSP-Minnesota cannot exceed $8.25 billion.

5.        Joint Ownership of Generation and Transmission Facilities

Following are the investments by NSP-Minnesota in jointly owned generation and transmission facilities and the related ownership percentages as of Dec. 31, 2011:

					Construction
	Plant in		Accumulated		Work in
(Thousands of Dollars)	Service		Depreciation		Progress		Ownership %
Electric Generation:
Sherco Unit 3	$	565,832	$	358,907	$	3,731		59.0	%
Sherco Common Facilities Units 1, 2 and 3		138,790		82,229		531		80.0
Sherco Substation		4,790		2,621		-		59.0
Electric Transmission:
Grand Meadow Line and Substation		11,204		855		-		50.0
CapX2020		57,856		8,899		74,404		49.6
Total	$	778,472	$	453,511	$	78,666

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NSP-Minnesota has approximately 500 MW of jointly owned generating capacity. 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 providing its own financing.

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.  In November 2011, Sherco Unit 3 experienced a significant failure of its turbine, generator, and exciter systems.  The facility was immediately shut down and isolated for investigation of the cause of the failure, which is still uncertain.  It is unknown when Sherco Unit 3 will recommence operations.  NSP-Minnesota maintains insurance policies for the entire unit, inclusive of the other joint owner’s proportionate share.  Replacement and repair of damaged systems, and other significant costs of the failure in excess of a $1.5 million deductible are expected to be recovered through these insurance policies.  For its proportionate share of possible expenditures in excess of insurance recoveries for components of the jointly owned facility, NSP-Minnesota will recognize additions to property, plant and equipment and O&M.  Sherco Units 1 and 2, wholly owned by NSP-Minnesota, continue to operate.

6.        Income Taxes

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Based on this provision, NSP-Minnesota became subject to additional taxes and was required to reverse previously recorded tax benefits in the period of enactment. NSP-Minnesota expensed approximately $3.3 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  NSP-Minnesota does not expect the $3.3 million of additional tax expense to recur in future periods. 

Federal Audit — NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012.  The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010.  In December 2011, Xcel Energy finalized the Revenue Agent Report and signed the Waiver of Assessment for tax years 2008 and 2009.  The total assessment for these tax years was $1.4 million, including tax and interest.

State Audits — NSP-Minnesotais a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Dec. 31, 2011, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2007.  As of Dec. 31, 2011, there were no state income tax audits in progress. 

Unrecognized Tax Benefits —The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR.  In addition, the unrecognized tax benefit balance includes temporary tax positions 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 ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Dec. 31, 2011		Dec. 31, 2010
Unrecognized tax benefit - Permanent tax positions	$	3.3	$	4.0
Unrecognized tax benefit - Temporary tax positions		13.4		18.5
Unrecognized tax benefit balance	$	16.7	$	22.5

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A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2011			2010			2009
Balance at Jan. 1	$	22.5		$	12.5		$	20.2
Additions based on tax positions related to the current year		6.5			7.3			6.9
Reductions based on tax positions related to the current year		(0.8	)		(0.3	)		(1.4	)
Additions for tax positions of prior years		4.9			3.5			3.6
Reductions for tax positions of prior years		(0.9	)		(0.5	)		(1.5	)
Settlements with taxing authorities		(15.5	)		-			(15.3	)
Balance at Dec. 31	$	16.7		$	22.5		$	12.5

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryfowards are as follows:

(Millions of Dollars)	Dec. 31, 2011			Dec. 31, 2010
NOL and tax credit carryforwards	$	(18.1	)	$	(11.0	)

The decrease in the unrecognized tax benefit balance of $5.8 million in 2011 was due to the resolution of certain federal audit matters, partially offset by an increase due to the addition of uncertain tax positions related to current and prior years’ activity.  NSP-Minnesota’s amount of unrecognized tax benefits could change in the next 12 months as 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.  However, NSP-Minnesota does not anticipate total unrecognized tax benefits will significantly change within the next 12 months.

The payable for interest related to unrecognized tax benefits is offset by the interest benefit associated with NOL and tax credit carryforwards.  A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2011			2010			2009
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.9	)	$	(0.3	)	$	(1.3	)
Interest income (expense) related to unrecognized tax benefits		1.1			(0.6	)		1.0
Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31	$	0.2		$	(0.9	)	$	(0.3	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2011, 2010 or 2009. 

Other Income Tax Matters —NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset.  NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2011		2010
Federal NOL carryforward	$	564.7	$	407.7
Federal tax credit carryforwards		60.5		35.6
State tax credit carryforwards, net of federal detriment		1.9		1.8

The federal carryforward periods expire between 2021 and 2031.  The state carryforward periods expire between 2017 and 2024.

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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:

	2011			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		7.2			9.2			6.2
Previously recognized Medicare Part D subsidies		0.1			0.7			-
Tax credits recognized, net of federal income tax expense		(5.0	)		(3.1	)		(2.7	)
Regulatory differences — utility plant items		(1.8	)		(2.0	)		(1.6	)
Life insurance policies		(0.2	)		(0.2	)		(0.3	)
Change in unrecognized tax benefits		(0.1	)		0.3			(1.0	)
Resolution of income tax audits and other		-			(0.2	)		1.4
Other, net		-			0.1			0.3
Effective income tax rate		35.2	%		39.8	%		37.3	%

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2011			2010			2009
Current federal tax expense (benefit)	$	8,059		$	(87,554	)	$	(12,136	)
Current state tax expense		3,055			18,789			19,195
Current change in unrecognized tax (benefit) expense		(12,891	)		1,850			(6,165	)
Current tax credits		-			(944	)		-
Deferred federal tax expense		152,806			215,892			154,858
Deferred state tax expense		55,658			47,092			30,364
Deferred change in unrecognized tax expense (benefit)		12,256			(577	)		1,667
Deferred tax credits		(24,600	)		(10,660	)		(9,542	)
Deferred investment tax credits		(2,694	)		(2,697	)		(3,120	)
Total income tax expense	$	191,649		$	181,191		$	175,121

The components of deferred income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2011			2010			2009
Deferred tax expense excluding items below	$	190,470		$	295,994		$	228,821
Tax benefit (expense) allocated to other comprehensive income and other		11,841			(776	)		(1,042	)
Amortization and adjustments to deferred income taxes onincome tax regulatory assets and liabilities		(6,191	)		(43,471	)		(50,432	)
Deferred tax expense	$	196,120		$	251,747		$	177,347

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

(Thousands of Dollars)	2011		2010
Deferred tax liabilities:
Difference between book and tax bases of property	$	1,892,655	$	1,635,323
Regulatory assets		121,300		116,787
Other		17,319		19,768
Total deferred tax liabilities	$	2,031,274	$	1,771,878
Deferred tax assets:
NOL carryforward	$	196,074	$	145,119
Tax credit carryforward		62,463		37,403
Rate refund		29,499		2,290
Employee benefits		18,280		56,068
Deferred investment tax credits		14,096		15,043
Regulatory liabilities		12,732		17,863
Bad debts		9,381		8,580
Other		11,512		2,745
Total deferred tax assets	$	354,037	$	285,111
Net deferred tax liability	$	1,677,237	$	1,486,767

7.        Benefit Plans and Other Postretirement Benefits

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Minnesota accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans.  NSP-Minnesota is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Minnesota accounts for it’s pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Minnesota employees.

Xcel Energy, which includes NSP-Minnesota, offers various benefit plans to its employees.  Approximately 61 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements.  At Dec. 31, 2011, NSP-Minnesota had 2,033 covered under a collective-bargaining agreement, which expires at the end of 2013.  NSP-Minnesota also had an additional 228 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2012 and 2013.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value.  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 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 private equity investments and real estate investments, for which the measurement of net asset value requires significant use of unobservable inputs when determining the fair value of the underlying fund investments, including equity in non-publicly traded entities and real estate properties.

53

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 Inc.’s and NSP-Minnesota’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Xcel Energy Inc. and NSP-Minnesota base the 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 pension cost determination assumes a forecasted mix of investment types over the long term.  Investment returns in 2011 were below the assumed level of 8.00 percent.  Investment returns in 2010 and 2009 were above the assumed level of 8.00 and 8.50 percent, respectively.  Xcel Energy Inc. and NSP-Minnesota continually review the pension assumptions.  In 2012, NSP-Minnesota’s estimated investment-return assumption is 7.50 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.’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 projected 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, as NSP-Minnesota has experienced in recent years, unusual market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocations for NSP-Minnesota:

	2011			2010
Domestic and international equity securities		31	%		31	%
Long-duration fixed income securities		26			28
Short-to-intermediate term fixed income securities		14			12
Alternative investments		26			22
Cash		3			7
Total		100	%		100	%

The ongoing investment strategy 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 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 projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

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Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets that are measured at fair value as of Dec. 31, 2011 and 2010:

	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	42,644	$	-		$	-	$	42,644
Derivatives		-		1,914			-		1,914
Government securities		-		48,925			-		48,925
Corporate bonds		-		164,355			-		164,355
Asset-backed securities		-		-			10,188		10,188
Mortgage-backed securities		-		-			24,413		24,413
Common stock		23,844		-			-		23,844
Private equity investments		-		-			54,499		54,499
Commingled funds		-		416,599			-		416,599
Real estate		-		-			12,967		12,967
Securities lending collateral obligation and other		-		(16,819	)		-		(16,819	)
Total	$	66,488	$	614,974		$	102,067	$	783,529

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	72,568	$	-		$	-	$	72,568
Derivatives		-		2,662			-		2,662
Government securities		-		43,596			-		43,596
Corporate bonds		-		170,520			-		170,520
Asset-backed securities		-		-			8,771		8,771
Mortgage-backed securities		-		-			38,403		38,403
Common stock		44,239		-			-		44,239
Private equity investments		-		-			43,027		43,027
Commingled funds		-		371,122			-		371,122
Real estate		-		-			24,041		24,041
Securities lending collateral obligation and other		-		(26,095	)		-		(26,095	)
Total	$	116,807	$	561,805		$	114,242	$	792,854

The following tables present the changes in NSP-Minnesota’s Level 3 pension plan assets for the years ended Dec. 31, 2011, 2010 and 2009:

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2011
Asset-backed securities	$	8,771	$	781		$	(805	)	$	1,441		$	10,188
Mortgage-backed securities		38,403		355			(1,894	)		(12,451	)		24,413
Real estate		24,041		(219	)		6,416			(17,271	)		12,967
Private equity investments		43,027		1,354			4,196			5,922			54,499
Total	$	114,242	$	2,271		$	7,913		$	(22,359	)	$	102,067

55

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	15,473	$	1,109		$	(910	)	$	(6,901	)	$	8,771
Mortgage-backed securities		47,823		4,539			(4,634	)		(9,325	)		38,403
Real estate		21,630		(13	)		2,182			242			24,041
Private equity investments		26,622		(355	)		5,269			11,491			43,027
Total	$	111,548	$	5,280		$	1,907		$	(4,493	)	$	114,242

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2009
Asset-backed securities	$	26,553	$	771		$	15,490		$	(27,341	)	$	15,473
Mortgage-backed securities		57,146		1,791			34,139			(45,253	)		47,823
Real estate		37,480		(185	)		(13,936	)		(1,729	)		21,630
Private equity investments		27,790		-			(4,802	)		3,634			26,622
Total	$	148,969	$	2,377		$	30,891		$	(70,689	)	$	111,548

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Minnesota is presented in the following table:

(Thousands of Dollars)	2011			2010
Accumulated Benefit Obligation at Dec. 31	$	976,227		$	926,227
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	989,277		$	926,684
Service cost		28,016			26,736
Interest cost		51,946			53,929
Plan amendments		-			14,484
Actuarial loss		59,195			60,307
Benefit payments		(96,840	)		(92,863	)
Obligation at Dec. 31	$	1,031,594		$	989,277
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	792,854		$	768,997
Actual return on plan assets		46,140			96,538
Employer contributions		41,375			20,182
Benefit payments		(96,840	)		(92,863	)
Fair value of plan assets at Dec. 31	$	783,529		$	792,854
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(248,065	)	$	(196,423	)
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	611,409		$	552,849
Prior service cost		24,085			37,254
Total	$	635,494		$	590,103
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	51,427		$	39,813
Noncurrent regulatory assets		584,067			550,290
Total	$	635,494		$	590,103
Measurement date	Dec. 31, 2011			Dec. 31, 2010

(a) Amounts are recognized in noncurrent liabilities on NSP-Minnesota’s consolidated balance sheet.

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(Thousands of Dollars)	2011		2010
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	5.00	%	5.50	%
Expected average long-term increase in compensation level	4.00		4.00
Mortality table	RP 2000		RP 2000

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 2008 through 2010 for Xcel Energy’s pension plans.  Required contributions were made in 2011 and 2012 to meet minimum funding requirements.

The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2010 through 2012:

· In January 2012, contributions of $190.5 million were made across four of Xcel Energy’s pension plans, of which $79.3 million was attributable to NSP-Minnesota;

· In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $41.4 million was attributable to NSP-Minnesota;

· In 2010, contributions of $34 million were made to the Xcel Energy Pension Plan, of which $20.2 million was attributable to NSP-Minnesota.

· For future years, we anticipate contributions will be made as necessary.

Plan Amendments — No amendments occurred during 2011 to the Xcel Energy pension plans.

Benefit Costs —The components of NSP-Minnesota’s net periodic pension cost were:

(Thousands of Dollars)	2011			2010			2009
Service cost	$	28,016		$	26,736		$	23,027
Interest cost		51,946			53,929			54,868
Expected return on plan assets		(74,241	)		(76,611	)		(86,730	)
Amortization of prior service cost		13,169			11,726			11,726
Amortization of net loss		28,736			17,728			-
Net periodic pension cost	$	47,626		$	33,508		$	2,891
Costs not recognized due to effects of regulation		(34,898	)		(27,027	)		(2,891	)
Net benefit cost recognized for financial reporting	$	12,728		$	6,481		$	-
Significant Assumptions Used to Measure Costs:
Discount rate		5.50	%		6.00	%		6.75	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term rate of return on assets		8.00			8.00			8.50

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Minnesota based on Xcel Energy Services Inc. employees’ labor costs.  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 2012 pension cost calculations will be 7.50 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.  As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

57

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 $8.6 million in 2011, $8.8 million in 2010 and $7.5 million in 2009.

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 certain Xcel Energy retirees.  The former NSP 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.

In 1993, Xcel Energy Inc. and NSP-Minnesota adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized 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.

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’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 Inc. 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 Inc.’s and NSP-Minnesota’s return, correlation, 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 projected 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 tables present, for each of the fair value hierarchy levels, NSP-Minnesota’s postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2011 and 2010:

	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	882	$	-		$	-	$	882
Derivatives		-		203			-		203
Government securities		-		1,007			-		1,007
Corporate bonds		-		939			-		939
Asset-backed securities		-		-			119		119
Mortgage-backed securities		-		-			415		415
Preferred stock		-		6			-		6
Commingled funds		-		3,091			-		3,091
Securities lending collateral obligation and other		-		(169	)		-		(169	)
Total	$	882	$	5,077		$	534	$	6,493

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	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	2,711	$	-	$	-	$	2,711
Derivatives		-		248		-		248
Government securities		-		62		-		62
Corporate bonds		-		1,288		-		1,288
Asset-backed securities		-		-		47		47
Mortgage-backed securities		-		-		350		350
Preferred stock		-		9		-		9
Commingled funds		-		1,874		-		1,874
Securities lending collateral obligation and other		-		1,087		-		1,087
Total	$	2,711	$	4,568	$	397	$	7,676

The following tables present the changes in NSP-Minnesota’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2011, 2010 and 2009:

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, net		Dec. 31, 2011
Asset-backed securities	$	47	$	-		$	(15	)	$	87	$	119
Mortgage-backed securities		350		(26	)		41			50		415

								Purchases,
			Net Realized			Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)		Settlements, net			Dec. 31, 2010
Asset-backed securities	$	232	$	(5	)	$	26	$	(206	)	$	47
Mortgage-backed securities		1,319		(17	)		131		(1,083	)		350

							Purchases,
			Net Realized		Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)		Gains (Losses)		Settlements, net			Dec. 31, 2009
Asset-backed securities	$	313	$	-	$	46	$	(127	)	$	232
Mortgage-backed securities		2,516		21		137		(1,355	)		1,319

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for NSP-Minnesota is presented in the following table:

(Thousands of Dollars)	2011			2010
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	134,996		$	135,434
Service cost		87			72
Interest cost		7,372			7,956
Medicare subsidy reimbursements		739			1,338
ERRP proceeds shared with retirees		2,120			-
Plan participants’ contributions		5,997			5,460
Actuarial loss		14,295			3,965
Benefit payments		(19,563	)		(19,229	)
Obligation at Dec. 31	$	146,043		$	134,996

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(Thousands of Dollars)	2011			2010
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	7,676		$	10,777
Actual (loss) return on plan assets		(69	)		831
Plan participants’ contributions		5,997			5,460
Employer contributions		12,452			9,837
Benefit payments		(19,563	)		(19,229	)
Fair value of plan assets at Dec. 31	$	6,493		$	7,676
Funded Status of Plans at Dec. 31:
Funded status	$	(139,550	)	$	(127,320	)
Current assets		332			-
Current liabilities		(5,448	)		(3,743	)
Noncurrent liabilities		(134,434	)		(123,577	)
Net postretirement amounts recognized on consolidated balance sheets	$	(139,550	)	$	(127,320	)
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	64,473		$	51,208
Prior service credit		(918	)		(1,035	)
Transition obligation		1,381			2,727
Total	$	64,936		$	52,900
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	4,426		$	3,276
Noncurrent regulatory assets		56,683			46,449
Deferred Income taxes		1,561			1,298
Net-of-tax accumulated comprehensive income		2,266			1,877
Total	$	64,936		$	52,900
Measurement date	Dec. 31, 2011			Dec. 31, 2010
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.00	%		5.50	%
Mortality table	RP 2000			RP 2000
Health care costs trend rate - initial		6.31	%		6.50	%

Effective Dec. 31, 2011, the ultimate trend assumption remained unchanged at 5.0 percent.  The period until the ultimate rate is reached remained unchanged at eight 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:

	One Percentage Point
(Thousands of Dollars)	Increase			Decrease
APBO		$	14,985		$	(12,256	)
Service and interest components			890			(708	)

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 $49.0 million and $48.4 million during 2011 and 2010, of which $12.5 million and $9.8 million were attributable to NSP-Minnesota.  Xcel Energy expects to contribute approximately $39.1 million during 2012, of which $12.0 million is attributable to NSP-Minnesota.

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Plan Amendments — No amendments affecting NSP-Minnesota occurred during 2011 to the Xcel Energy health and welfare benefit plan.

Benefit Costs — The components of NSP-Minnesota’s net periodic postretirement benefit cost were:

(Thousands of Dollars)	2011			2010			2009
Service cost	$	87		$	72		$	132
Interest cost		7,372			7,956			9,140
Expected return on plan assets		(576	)		(809	)		(757	)
Amortization of transition obligation		1,346			1,346			1,346
Amortization of prior service cost		(117	)		(117	)		-
Amortization of net loss		2,348			2,195			3,558
Net periodic postretirement benefit cost	$	10,460		$	10,643		$	13,419
Significant Assumptions Used to Measure Costs:
Discount rate		5.50	%		6.00	%		6.75	%
Expected average long-term rate of return on assets (before tax)		7.50			7.50			7.50

In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Minnesota based on Xcel Energy Services Inc. employees’ labor costs. 

Projected Benefit Payments

The following table lists NSP-Minnesota’s 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
2012	$	100,930	$	13,079	$	1,137	$	11,942
2013		98,095		13,123		1,200		11,923
2014		98,565		13,091		1,261		11,830
2015		96,641		13,066		1,317		11,749
2016		97,865		12,988		1,371		11,617
2017-2021		457,351		60,296		7,344		52,952

Multiemployer Plans

NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant.  These plans provide pension and postretirement health care benefits to certain union employees, including electrical workers, boilermakers, and other construction and facilities workers who may perform services for more than one employer during a given period and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans.  Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2011, 2010 and 2009. There were no significant changes to the nature or magnitude of the participation of NSP-Minnesota in multiemployer plans for the years presented:

(Thousands of Dollars)	2011		2010		2009
Multiemployer plan contributions:
Pension	$	17,811	$	13,461	$	11,348
Other postretirement benefits		336		153		140
Total	$	18,147	$	13,614	$	11,488

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8.        Other Income, Net

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

(Thousands of Dollars)	2011			2010			2009
Interest income	$	4,663		$	5,887		$	7,473
Other nonoperating income (expense)		969			(30	)		(6	)
Life insurance policy expense		(3,915	)		(4,706	)		(5,895	)
Other income, net	$	1,717		$	1,151		$	1,572

9.        Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosuresprovides a single definition of fair value and requires certain 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 is established by this guidance.  The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

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 and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.

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 valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Investments in equity securities and other funds— Equity securities are valued using quoted prices in active markets.  The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value.  The investments in commingled funds and international equity funds may be redeemed for net asset value.  Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion.  Unscheduled distributions from real estate investments may be redeemed with proper notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.  Given the limited observability of inputs to the valuation of the underlying fund investments of the private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities—  Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated principal prepayments.  Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.

Interest rate derivatives— The fair value of interest rate derivatives are based on broker quotes utilizing current market interest rate forecasts.

Commodity derivatives—  The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options.  Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers.  Electric commodity derivatives include FTRs, for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management’s forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.

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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.

Non-Derivative Instruments Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants.  Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants.  The fund contains cash equivalents, debt securities, equity securities, and other investments - all classified as available-for-sale.  NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs.  Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs.  Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $79.8 million and $82.5 million at Dec. 31, 2011 and 2010, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $87.5 million and $65.2 million at Dec. 31, 2011 and 2010, respectively.

The following tables present the cost and fair value of NSP-Minnesota’s non-derivative instruments with recurring fair value measurements, in the nuclear decommissioning fund, at Dec. 31, 2011 and 2010:

	Dec. 31, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	26,123	$	7,103	$	19,020	$	-	$	26,123
Commingled funds		320,798		-		311,105		-		311,105
International equity funds		63,781		-		58,508		-		58,508
Private equity investments		9,203		-		-		9,203		9,203
Real estate		24,768		-		-		26,395		26,395
Debt securities:
Government securities		116,490		-		117,256		-		117,256
US corporate bonds		187,083		-		193,516		-		193,516
International corporate bonds		35,198		-		35,804		-		35,804
Municipal bonds		60,469		-		64,731		-		64,731
Asset-backed securities		16,516		-		-		16,501		16,501
Mortgage-backed securities		75,627		-		-		78,664		78,664
Equity securities:
Common stock		408,122		398,625		-		-		398,625
Total	$	1,344,178	$	405,728	$	799,940	$	130,763	$	1,336,431

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $21.1 million of miscellaneous investments.

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	Dec. 31, 2010
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	83,837	$	76,281	$	7,556	$	-	$	83,837
Commingled funds		131,000		-		133,080		-		133,080
International equity funds		54,561		-		58,584		-		58,584
Debt securities:
Government securities		146,473		-		146,654		-		146,654
US corporate bonds		279,028		-		288,304		-		288,304
International corporate bonds		1,233		-		1,581		-		1,581
Municipal bonds		100,277		-		97,557		-		97,557
Asset-backed securities		32,558		-		-		33,174		33,174
Mortgage-backed securities		68,072		-		-		72,589		72,589
Equity securities:
Common stock		436,334		435,270		-		-		435,270
Total	$	1,333,373	$	511,551	$	733,316	$	105,763	$	1,350,630

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $15.4 million of miscellaneousinvestments.

The following tables present the changes in Level 3 nuclear decommissioning fund investments:

(Thousands of Dollars)	Jan. 1, 2011		Purchases		Settlements			Gains (Losses)  Recognized as  Regulatory Assets  and Liabilities			Dec. 31, 2011
Asset-backed securities	$	33,174	$	16,518	$	(32,560	)	$	(631	)	$	16,501
Mortgage-backed securities		72,589		168,688		(161,134	)		(1,479	)		78,664
Real estate		-		24,768		-			1,627			26,395
Private equity investments		-		9,203		-			-			9,203
Total	$	105,763	$	219,177	$	(193,694	)	$	(483	)	$	130,763

(Thousands of Dollars)	Jan. 1, 2010		Purchases		Settlements			Gains Recognized as Regulatory Assets  and Liabilities		Dec. 31, 2010
Asset-backed securities	$	11,918	$	38,871	$	(17,878	)	$	263	$	33,174
Mortgage-backed securities		81,189		63,497		(75,701	)		3,604		72,589
Total	$	93,107	$	102,368	$	(93,579	)	$	3,867	$	105,763

(Thousands of Dollars)	Jan. 1, 2009		Purchases		Settlements			Gains Recognized as  Regulatory Assets  and Liabilities		Dec. 31, 2009
Asset-backed securities	$	10,962	$	7,271	$	(7,755	)	$	1,440	$	11,918
Mortgage-backed securities		98,461		17,943		(45,815	)		10,600		81,189
Total	$	109,423	$	25,214	$	(53,570	)	$	12,040	$	93,107

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The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at Dec. 31, 2011:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year  or Less		Due in 1 to 5  Years		Due in 5 to 10  Years		Due after 10  Years		Total
Government securities	$	113,179	$	-	$	4,077	$	-	$	117,256
US corporate bonds		304		35,437		139,880		17,895		193,516
International corporate bonds		-		8,454		23,501		3,849		35,804
Municipal bonds		-		-		40,585		24,146		64,731
Asset-backed securities		-		9,907		6,594		-		16,501
Mortgage-backed securities		-		1,731		1,041		75,892		78,664
Debt securities	$	113,483	$	55,529	$	215,678	$	121,782	$	506,472

Derivative Instruments Fair Value Measurements

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.

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 an anticipated debt issuance for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Dec. 31, 2011, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At Dec. 31, 2011, NSP-Minnesota had unsettled interest rate swaps outstanding with a total notional amount of $225 million.  These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

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 this policy.

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, 2011, NSP-Minnesota had various vehicle fuel related contracts designated as cash flow hedges extending through December 2014.  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 OCI 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 years ended Dec. 31, 2011 and 2010.

At Dec. 31, 2011, accumulated OCI related to commodity derivative cash flow hedges included $0.1 million of net gains 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 electric operating revenue, net of amounts credited to customers under margin-sharing mechanisms.

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The following table details the gross notional amounts of commodity forwards, options, and FTRs at Dec. 31, 2011 and 2010:

(Amounts in Thousands) (a)(b)	Dec. 31, 2011		Dec. 31, 2010
MWh of electricity		37,522		44,376
MMBtu of natural gas		7,290		14,100
Gallons of vehicle fuel		330		440

(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

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

(Thousands of Dollars)	2011			2010			2009
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	4,977		$	3,941		$	3,053
After-tax net unrealized losses related to derivatives accounted for as hedges		(16,578	)		(80	)		(1,219	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(128	)		1,116			2,107
Accumulated other comprehensive (loss) income related to cash flow hedges at Dec. 31	$	(11,729	)	$	4,977		$	3,941

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2011 and 2010.

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2011 and 2010, on OCI, regulatory assets and liabilities, and income:

	Dec. 31, 2011
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into
	During the Period in:						Income During the Period from:
	Accumulated						Accumulated								Pre-Tax Gains
	Other			Regulatory			Other				Regulatory				Recognized
	Comprehensive			(Assets) and			Comprehensive				Assets and				During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss				(Liabilities)				in Income
Derivatives designated as cash flow hedges
Interest rate	$	(28,119	)	$	-		$	(109	)	(a)	$	-			$	-
Vehicle fuel and other commodity		119			-			(113	)	(e)		-				-
Total	$	(28,000	)	$	-		$	(222	)		$	-			$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-			$	-			$	6,330	(b)
Electric commodity		-			49,818			-				(40,492	)	(c)		-
Natural gas commodity		-			(22,581	)		-				18,021		(d)		-
Total	$	-		$	27,237		$	-			$	(22,471	)		$	6,330

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	Dec. 31, 2010
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into
	During the Period in:						Income During the Period from:
	Accumulated						Accumulated								Pre-Tax Gains
	Other			Regulatory			Other				Regulatory				Recognized
	Comprehensive			(Assets) and			Comprehensive				Assets and				During the Period
(Thousands of Dollars)	Income			Liabilities			Income				(Liabilities)				in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(108	)	(a)	$	-			$	-
Vehicle fuel and other commodity		(137	)		-			1,998		(e)		-				-
Total	$	(137	)	$	-		$	1,890			$	-			$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-			$	-			$	12,061	(b)
Electric commodity		-			3,969			-				(21,840	)	(c)		-
Natural gas commodity		-			(18,655	)		-				9,111		(d)		-
Total	$	-		$	(14,686	)	$	-			$	(12,729	)		$	12,061

(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 derivatives 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 O&M expenses.

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 ratings. If the credit ratings for NSP-Minnesota were downgraded below investment grade, contracts underlying $1.4 million of derivative liabilities in a gross liability position at Dec. 31, 2011 would have required NSP-Minnesota to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $0.1 million.  If the credit ratings for NSP-Minnesota were downgraded below investment grade, no contracts underlying NSP-Minnesota’s derivative liabilities at Dec. 31, 2010 would have required the posting of collateral or contract settlement.

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, 2011 and 2010, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

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Recurring Fair Value Measurements — The following table presents, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	93	$	-	$	93	$	-		$	93
Other derivative instruments:
Trading commodity		-		26,133		-		26,133		(9,679	)		16,454
Electric commodity		-		-		13,333		13,333		(1,471	)		11,862
Total current derivative assets	$	-	$	26,226	$	13,333	$	39,559	$	(11,150	)		28,409
Purchased power agreements (a)													23,108
Current derivative instruments												$	51,517
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	59	$	-	$	59	$	(59	)	$	-
Other derivative instruments:
Trading commodity		-		28,307		-		28,307		(2,234	)		26,073
Total noncurrent derivative assets	$	-	$	28,366	$	-	$	28,366	$	(2,293	)		26,073
Purchased power agreements (a)													54,616
Noncurrent derivative instruments												$	80,689
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	28,119	$	-	$	28,119	$	-		$	28,119
Other derivative instruments:
Trading commodity		-		21,816		-		21,816		(11,647	)		10,169
Electric commodity		-		698		916		1,614		(1,471	)		143
Natural gas commodity		-		13,499		-		13,499		-			13,499
Total current derivative liabilities	$	-	$	64,132	$	916	$	65,048	$	(13,118	)		51,930
Purchased power agreements (a)													13,851
Current derivative instruments												$	65,781
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,464	$	-	$	13,464	$	(2,293	)	$	11,171
Total noncurrent derivative liabilities	$	-	$	13,464	$	-	$	13,464	$	(2,293	)		11,171
Purchased power agreements (a)													173,019
Noncurrent derivative instruments												$	184,190

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, 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.

(b) The accounting guidance for 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 NSP-Minnesota 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.

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The following tables present, for each of the hierarchy levels, NSP-Minnesota’s derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2010:

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	70	$	-	$	70	$	-		$	70
Other derivative instruments:
Trading commodity		487		31,253		-		31,740		(18,719	)		13,021
Electric commodity		-		-		3,619		3,619		(1,226	)		2,393
Natural gas commodity		-		187		-		187		(187	)		-
Total current derivative assets	$	487	$	31,510	$	3,619	$	35,616	$	(20,132	)		15,484
Purchased power agreements (a)													24,408
Current derivative instruments												$	39,892
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	83	$	-	$	83	$	-		$	83
Other derivative instruments:
Trading commodity		-		25,850		-		25,850		(2,477	)		23,373
Natural gas commodity		-		125		-		125		(48	)		77
Total noncurrent derivative assets	$	-	$	26,058	$	-	$	26,058	$	(2,525	)		23,533
Purchased power agreements (a)													77,725
Noncurrent derivative instruments												$	101,258

Current derivative liabilities
Other derivative instruments:
Trading commodity	$	392	$	25,416	$	-	$	25,808	$	(21,337	)	$	4,471
Electric commodity		-		-		1,227		1,227		(1,227	)		-
Natural gas commodity		20		9,156		-		9,176		(187	)		8,989
Total current derivative liabilities	$	412	$	34,572	$	1,227	$	36,211	$	(22,751	)		13,460
Purchased power agreements (a)													13,851
Current derivative instruments												$	27,311
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,351	$	-	$	13,351	$	(2,478	)	$	10,873
Natural gas commodity		-		75		-		75		(48	)		27
Total noncurrent derivative liabilities	$	-	$	13,426	$	-	$	13,426	$	(2,526	)		10,900
Purchased power agreements (a)													186,871
Noncurrent derivative instruments												$	197,771

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, 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.

(b) The accounting guidance for derivatives and hedgingpermits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota 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.

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The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2011, 2010 and 2009:

	Year Ended Dec. 31
(Thousands of Dollars)	2011			2010			2009
Balance at Jan. 1	$	2,392		$	27,237		$	23,247
Purchases		33,609			10,948			9,077
Settlements		(36,552	)		(24,960	)		(14,648	)
Transfers out of Level 3		-			(11,638	)		700
Net transactions recorded during the period:
Gains recognized in earnings (a)		66			4,719			5,693
Gains (losses) recognized as regulatory assets and liabilities		12,902			(3,914	)		3,168
Balance at Dec. 31	$	12,417		$	2,392		$	27,237

(a) These amounts relate to commodity derivatives held at the end of the period.

NSP-Minnesota recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for the year ended Dec. 31, 2011.  The following table presents the transfers that occurred from Level 3 to Level 2 during the year ended Dec. 31, 2010:

	Year Ended
(Thousands of Dollars)	Dec. 31, 2010
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	5,384
Noncurrent assets		21,450
Current liabilities		(2,851	)
Noncurrent liabilities		(12,345	)
Total	$	11,638

There were no transfers of amounts from Level 2 to Level 3, or any transfers to or from Level 1 for the year ended Dec. 31, 2010.  The transfer of amounts from Level 3 to Level 2 in the year ended Dec. 31, 2010 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

Fair Value of Long-Term Debt

As of Dec. 31, 2011 and 2010, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2011				2010
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,338,897	$	4,066,367	$	3,337,912	$	3,673,214

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, 2011 and 2010.  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.

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10.     Rate Matters

NSP-Minnesota

Pending Regulatory Proceedings — MPUC

Base Rate

NSP-Minnesota - Minnesota Electric Rate Case— In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012.  The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent.  The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.

In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments.  The DOER revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent.  The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation were associated with ROE and compensation related issues.

In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million.  The revisions were due to delays in the Monticello nuclear plant extended power uprate.

In November 2011, NSP-Minnesota reached a settlement agreement with the Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group and Verso Paper Corp., which settled all financial issues and several rate design issues between the signing parties.  The settlement includes a rate increase of approximately $58.0 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent.  The settlement agreement reflects a reduction to depreciation expense and NSP-Minnesota’s rate request by $30 million with an additional adjustment of $7.5 million related to employee compensation.  The settlement also provides NSP-Minnesota the ability to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012, which is currently projected to increase by approximately $28 million.  NSP-Minnesota also agreed to not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement and the property tax filing are approved by the MPUC.  NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $67.4 million for 2011 and has reduced depreciation expense by $30 million.

In February 2012, the ALJ recommended MPUC approval of the settlement agreement.  In addition, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  A decision is expected by the MPUC in the first half of 2012.

Pending Regulatory Proceedings — NDPSC

NSP-Minnesota – North Dakota Electric Rate Case — In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012.  The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011.  NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $2.4 million for 2011.  The interim rates will remain in effect until the NDPSC makes its final decision on the case.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012, due to the termination of the Merricourt wind project.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff.  If approved by the NDPSC, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues.  To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.

An NDPSC decision is expected in March 2012.

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Pending Regulatory Proceedings — SDPUC

NSP-Minnesota – South Dakota Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012.  The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms.  The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.

As a result of delays in the rate case process, interim rates of $12.7 million were implemented Jan. 2, 2012.  A final decision is expected in the first half of 2012.

Electric, Purchased Gas and Resource Adjustment Incentive Clauses

NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates.  At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows:

CIP Rider — CIP expenses are recovered through base rates and a rider that is adjusted annually.  Under the 2010 electric CIP rider request approved by the MPUC in October 2010, NSP-Minnesota recovered $84.4 million through the rider during November 2010 to December 2011.  This is in addition to $60.9 million recovered through base rates.  During December 2010 to December 2011, NSP-Minnesota recovered $27.4 million through the natural gas CIP rider approved in November 2010.  This is in addition to $4.4 million recovered in base rates.

In January 2012, the MPUC approved NSP-Minnesota’s annual electric rider petition requesting recovery of $74.7 million of electric CIP expenses and financial incentives to be recovered during February 2012 through December 2012.  In December 2011, the MPUC approved NSP-Minnesota’s annual gas rider petition requesting $10.6 million of natural gas CIP expenses and financial incentives to be recovered during January 2012 through December 2012.  This proposed recovery through the riders is in addition to an estimated $48.3 million and $3.8 million through electric and gas base rates, respectively.

11.     Commitments and Contingent Liabilities

Commitments

Capital Commitments — NSP-Minnesota has made commitments in connection with a portion of its projected capital expenditures.  NSP-Minnesota’s capital commitments primarily relate to the following major projects:

Nuclear Lifecycle Management and  Extended Power Uprates — NSP-Minnesota is pursuing improvements to make sure the plants operate safely until the end of their extended licensed life and is making capacity increases of the Monticello and Prairie Island generating plants that could total up to approximately 188 MW.  The MPUC approved the CON for the extended power uprate for Monticello in 2008.  The license amendment application was filed with the NRC in November 2008, but a concern was raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance.  In October 2011, the Advisory Committee recommended that all licensing actions that credit the use of containment accident pressure be suspended until the causes and risks of Japan’s Fukushima incident are better understood.  NSP-Minnesota has rescheduled the remaining equipment changes needed to complete the Monticello power uprate projects during the planned spring 2013 refueling outage. 

The MPUC approved an extended power uprate for the Prairie Island Units in 2009.  Analysis of recent extended power uprate submittals to the NRC concluded that significant additional design work beyond current schedule and cost plan estimates are now being required to submit a successful application.  As a result, NSP-Minnesota is completing an economic and new project design analysis to determine project impacts and anticipates submitting a Change in Circumstances filing with the MPUC in the first quarter of 2012.

CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy that have proposed several groups of transmission projects to be complete by 2020.  Group 1 project investments consist of four transmission lines.  Major construction began in 2010 on the Group 1 transmission lines with an expected completion date in 2015.  NSP System’s investment depends on the routes and configurations approved by affected state commissions.  The remainder of the costs will be born by other utilities in the upper Midwest.

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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 2012 and 2028.  In addition, NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.  NSP-Minnesota’s 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 to customers.

The estimated minimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2011, are as follows:

(Millions of Dollars)	Dec. 31, 2011
Coal (a)	$	1,548
Nuclear fuel (a)		1,546
Natural gas supply		23
Natural gas storage and transportation (a)		833

(a) Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Estimated coal requirements at Dec. 31, 2011 have been adjusted to account for Sherco Unit 3, which was shut down in November 2011 after experiencing a significant failure of its turbine, generator and exciter systems.  It is uncertain when Sherco Unit 3 will recommence operations.  See Note 5 for further discussion.

Purchased Power Agreements — NSP-Minnesota has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

NSP-Minnesota has various pay-for-performance contracts with expiration dates through 2033.  In general, these contracts provide for energy payments based on actual power taken under the contracts, as well as capacity payments.  Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for purchased power agreements were payments for capacity of $106.8 million, $109.3 million and $109.3 million in 2011, 2010 and 2009, respectively.  At Dec. 31, 2011, the estimated future payments for capacity that NSP-Minnesota is obligated to purchase, subject to availability, are as follows:

(Millions of Dollars)
2012	$	106.1
2013		108.4
2014		110.7
2015		83.4
2016		57.4
Thereafter		171.8
Total (a)	$	637.8

(a) Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — Under certain purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases.  These specific purchased power agreements create a variable interest in the associated independent power producing entity.

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NSP-Minnesota has determined that certain independent power producing entities are variable interest entities.  NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in the purchased power agreements.

NSP-Minnesota has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.  NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.  NSP-Minnesota had approximately 1,064 MW of capacity under long-term purchased power agreements as of Dec. 31, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities.  These agreements have expiration dates through the year 2028.

Leases— NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business.  These leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases.  Total expenses under operating lease obligations were approximately $72.9 million, $73.0 million and $76.2 million for 2011, 2010 and 2009, respectively.  These expenses include payments for capacity recorded to electric fuel and purchased power expenses for purchase power agreements accounted for as operating leases of $58.2 million, $57.1 million and $56.2 million in 2011, 2010 and 2009, respectively.

Included in the future commitments under operating leases are estimated future payments under purchased power agreements that have been accounted for as operating leases in accordance with the applicable accounting guidance.  Future commitments under operating leases are:

	Other		Purchased		Total
	Operating		Power Agreement		Operating
(Millions of Dollars)	Leases		Operating Leases (a) (b)		Leases
2012	$	8.2	$	55.0	$	63.2
2013		7.0		55.9		62.9
2014		6.2		56.8		63.0
2015		5.3		57.8		63.1
2016		3.6		58.7		62.3
Thereafter		19.9		557.6		577.5

(a) Amounts do not include purchased power agreements accounted for as other commitments, which are recorded to O&M as executed.

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

Guarantees and Indemnifications

In connection with the acquisition of the 201 MW Nobles wind project, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  NSP-Minnesota’s indemnification obligation is capped at $20 million, in the aggregate.  The indemnification obligation expires in March 2013.  NSP-Minnesota has not recorded a liability related to this indemnity and it has no assets held as collateral related to this agreement at Dec. 31, 2011.

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 regulated rate process.  New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate 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 — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and other comparable federal and state environmental laws impose liability, without regard to the legality of the original conduct, on certain classes of persons where hazardous substances or other regulated materials have been released to the environment.  NSP-Minnesota may sometimes 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 MGPs operated by NSP-Minnesota, its predecessors, or other entities; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes to that site. 

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MGP Sites — NSP-Minnesota is currently involved in investigating and/or remediating several MGP sites where hazardous or other regulated materials may have been deposited.  NSP-Minnesota has identified 3 sites, where former MGP activities have or may have resulted in actual site contamination and are under current investigation and/or remediation.  At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any ultimate remediation that may be conducted.  NSP-Minnesota anticipates that the majority of the remediation at these sites will continue through at least 2014.  For these sites, NSP-Minnesota had accrued $0.1 million and $0.3 million at Dec. 31, 2011 and Dec. 31, 2010, respectively.  There may be insurance recovery and/or recovery from other PRPs that will offset any costs actually incurred at these sites.  NSP-Minnesota anticipates that any amounts actually spent will be fully recovered from customers.

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 not expected to be material 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 Regulation — In December 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare.  In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold.   NSP-Minnesota is unable to determine what the cost of compliance with these new EPA requirements will be as it is not clear whether these requirements will apply to futures changes at NSP-Minnesota’s power plants.

GHG New Source Performance Standard Proposal — The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the CAA.  The EPA had planned to release its proposal in September 2011, but has delayed it without establishing a new proposal date.

CSAPR — In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S., including Minnesota.  The CSAPR sets more stringent requirements than the proposed CATR.  The rule also creates an emissions trading program.  NSP-Minnesota intends to comply by reducing emissions and/or purchasing allowances. 

On Dec. 30, 2011, the U.S. Court of Appeals for the D.C. Circuit issued a stay of the CSAPR, pending completion of judicial review.  The Court is expected to hear the case in April 2012.  NSP-Minnesota anticipates that the court may rule on the challenges to the CSAPR in the second half of 2012.  It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future Court decision.

If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at NSP-Minnesota’s Sherco plant, which is estimated to cost a total of $10 million through 2014, and system operating changes to the Black Dog and the Sherco plants.  If available, NSP-Minnesota would also consider allowance purchases.  In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota.  NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas.  If successful, additional allowances would reduce NSP-Minnesota’s costs to comply with the reductions that may be imposed by the CSAPR.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions.  The CAIR does not currently apply in Minnesota because the Court specifically found that the EPA had not adequately justified the application of the CAIR to Minnesota.  In granting the stay of the CSAPR, the Court specifically noted that the CAIR would remain in place during its pending review of the CSAPR.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — In December 2011, the EPA issued the final EGU MATS rule to replace the proposed EGU MACT rule.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and will require coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years.  NSP-Minnesota believes these costs would be recoverable through regulatory mechanisms and it does not expect a material impact on its results of operations, financial position or cash flows.

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Minnesota Mercury Legislation — Under the 2006 mercury legislation, NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King generating plants, with project costs collected through the MCR rider in 2010.  Subsequently, in the 2010 Minnesota electric rate case, the costs of these projects were moved into base rates as part of the interim rates effective Jan. 2, 2011.  NSP-Minnesota has also obtained MPUC approval to install mercury controls on Sherco Units 1 and 2 by the end of 2014.

For Sherco Units 1 and 2, NSP-Minnesota has incurred $1.5 million in study costs to date and spent $0.6 million through Dec. 31, 2011 for testing and studying of technologies.  At Dec. 31, 2011, the estimated annual testing and study cost is $0.5 million.  NSP-Minnesota projects installation costs of $12.0 million for the mercury controls on the units and O&M expense of $10.0 million per year beginning in 2014.  NSP-Minnesota believes these costs would be recoverable through regulatory mechanisms.

Regional Haze Rules — In December 2009, the MPCA Citizens Board approved the Regional Haze SIP, which has been submitted to the EPA for approval.  The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks.  The MPCA concluded selective catalytic reductions (SCR) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA’s BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2.  The combustion controls have been installed on Sherco Units 1 and 2, and the scrubber upgrades are scheduled to be installed by 2015.  At this time, the estimated cost for meeting the BART and other CAA requirements is approximately $50 million of which $20 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2.  NSP-Minnesota anticipates that all costs associated with BART compliance will be fully recoverable.

In June 2011, the EPA provided comments to the MPCA on the SIP, stating the EPA’s preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2.  The MPCA has since proposed that the CSAPR should be considered BART for EGUs and the EPA has proposed that states be allowed to find that CSAPR compliance meets BART requirements for EGUs, and specifically that Minnesota’s proposal to find the CSAPR to meet BART requirements should be approved, if finalized by the state.  It is not yet known what the final requirements will be.  NSP-Minnesota does not expect that a finding that the CSAPR meets BART requirements would result in changes to the control equipment plans described above, and has requested that the MPCA retain its 2009 BART determination.

In October 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by the MPCA is appropriate.  In its Jan. 25, 2012 notice concerning its review of Minnesota’s Regional Haze SIP, the EPA noted that it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the Reasonably Attributable Visibility Impairment (RAVI) program.  It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.

Federal Clean Water Act (CWA) Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species.  In April 2011, the EPA published the proposed rule that sets prescriptive standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office.  NSP-Minnesota provided comments to the proposed rule, which is expected to be finalized in late 2012.  Due to the uncertainty of the final regulatory requirements, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

As part of NSP-Minnesota’s 2009 CWA permit renewal for the Black Dog plant, the MPCA required the submission of a plan for compliance with the CWA.  The compliance plan was submitted for MPCA review and approval in April 2010.  The MPCA is currently reviewing the proposal in consultation with the EPA.

Proposed Coal Ash Regulation — NSP-Minnesota’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste.  In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste.  Coal ash is currently exempt from hazardous waste regulation.  If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, NSP-Minnesota’s costs associated with the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted.  The EPA has not announced a planned date for a final rule.  The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

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NSP-Minnesota Notice of Violation (NOV) — In June 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota.  The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid 2000s should have required a permit under the NSR process.  NSP-Minnesota believes it has acted in full compliance with the CAA and NSR process.  NSP-Minnesota also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements.  NSP-Minnesota disagrees with the assertions contained in the NOV and intends to vigorously defend its position.  It is not known whether any costs would be incurred as a result of this NOV.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for plant related to nuclear production, steam production, wind production, electric transmission and distribution, gas transmission and distribution and office buildings.  The steam production obligation includes asbestos, ash containment facilities, and radiation sources.  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 and the origination dates were the in-service date of the 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 AROs 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 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 AROs associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originated with the in-service date of the facility.  See Note 12 for further discussion of nuclear obligations.

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota’s AROs is shown in the table below for the years ended Dec. 31, 2011 and 2010, respectively:

	Beginning								Revisions		Ending
	Balance		Liabilities		Liabilities				to Prior		Balance
(Thousands of Dollars)	Jan. 1, 2011		Recognized		Settled		Accretion		Estimates		Dec. 31, 2011
Electric plant
Steam production asbestos	$	10,041	$	-	$	-	$	438	$	-		$	10,479
Steam production ash containment		12,814		-		-		508		17,667			30,989
Steam production radiation sources		37		-		-		3		2			42
Nuclear production decommissioning		809,474		-		-		57,641		615,626	(a)		1,482,741
Wind production		38,553		-		-		1,962		-			40,515
Electric transmission and distribution		3,087		-		-		153		12,460			15,700
Natural gas plant
Gas transmission and distribution		278		-		-		17		-			295
Common and other property
Common general plant asbestos		1,077		-		-		58		-			1,135
Total liability	$	875,361	$	-	$	-	$	60,780	$	645,755		$	1,581,896

(a) The increase is primarily due to the completion of NSP-Minnesota’s triennial nuclear decommissioning study, which reflects an increase in the estimated cost of retirement, increase in the escalation rates for each nuclear unit and a decrease in the discount rate used to calculate the net present value of the future cash flows.

The fair value of NSP-Minnesota’s legally restricted assets, for purposes of settling the nuclear ARO, was $1.3 billion as of Dec. 31, 2011, including external nuclear decommissioning investment funds and internally funded amounts.

In 2011, NSP-Minnesota incurred revisions for nuclear decommissioning, radiation sources, ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

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	Beginning									Revisions			Ending
	Balance		Liabilities		Liabilities					to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2010		Recognized		Settled			Accretion		Estimates			Dec. 31, 2010
Electric plant
Steam production asbestos	$	16,776	$	3,771	$	(2,330	)	$	858	$	(9,034	)	$	10,041
Steam production ash containment		12,547		-		-			611		(344	)		12,814
Steam production radiation sources		57		-		-			3		(23	)		37
Nuclear production decommissioning		758,923		-		-			50,551		-			809,474
Wind production		7,751		25,671		-			592		4,539			38,553
Electric transmission and distribution		140		-		-			7		2,940			3,087
Natural gas plant
Gas transmission and distribution		261		-		-			17		-			278
Common and other property
Common general plant asbestos		1,021		-		-			56		-			1,077
Total liability	$	797,476	$	29,442	$	(2,330	)	$	52,695	$	(1,922	)	$	875,361

The fair value of NSP-Minnesota’s legally restricted assets, for purposes of settling the nuclear ARO, was $1.4 billion as of Dec. 31, 2010, including external nuclear decommissioning investment funds and internally funded amounts.

In 2010, NSP-Minnesota incurred revisions for asbestos, radiation sources, wind turbines, ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

Removal Costs— NSP-Minnesota records a regulatory liability for the plant removal costs of 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 time periods over which the amounts were accrued and the changing of rates over 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.  Removal costs as of Dec. 31, 2011 and 2010 were $382 million and $400 million, respectively.

Nuclear Insurance

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $12.6 billion under the Price-Anderson amendment to the Atomic Energy Act.  NSP-Minnesota has secured $375 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 April 2010.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL).  The coverage limits are $2.25 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 $15.7 million for business interruption insurance and $33.6 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.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material effect on NSP-Minnesota’s financial position and results of operations.

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Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against the following utilities, including Xcel Energy Inc., the parent company of NSP-Minnesota, to force reductions in CO2 emissions:  American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority.  The lawsuits alleged that CO2 emitted by each company is a public nuisance and asked the court to order each utility to cap and reduce its CO2 emissions.  The lawsuits did not demand monetary damages.  In December 2011, the U.S. District Court entered an order dismissing this lawsuit, bringing a close to this litigation.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 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 Inc., the parent company of NSP-Minnesota, and 23 other utility, 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 Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit.  In November 2011, oral arguments were presented.  It is unknown when the Ninth Circuit will render a final opinion.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — On May 27, 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe  this lawsuit is without merit and have filed a motion to dismiss the lawsuit.  It is uncertain when the court will rule on this motion.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — On April 1, 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota.  NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact.  NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011.  As a result, NSP-Minnesota recorded a $101 million deposit in the first quarter 2011, which was collected in April 2011.  On May 5, 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements.  On that same day, enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco’s lawsuit is without merit and has filed a motion to dismiss.  On Sept. 16, 2011, the U.S. District Court denied the motion to dismiss.  The trial is set to begin in late 2012 or early 2013.  While NSP-Minnesota believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on NSP-Minnesota’s consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Other Contingencies

See Note 10 for further discussion.

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12.      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 $11 million in 2011, $13 million in 2010 and $12 million 2009.  In total, NSP-Minnesota had paid approximately $422.3 million to the DOE through Dec. 31, 2011.  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.  In 2011, NSP-Minnesota received from the DOE pursuant to a settlement with the DOE, an initial payment of approximately $100 million to cover damages through the end of 2008.  As of Dec. 31, 2011, NSP-Minnesota has recorded the payment as restricted cash and a regulatory liability.

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 renewed licenses terms in 2033 for Unit 1 and 2034 for Unit 2 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 at least 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 the applicable accounting guidance.

Monticello received its initial operating license in 1970 and began commercial operation in 1971.  With its renewed operating license and CON for spent fuel capacity to support 20 years of extended operation, Monticello 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 received their initial operating license and began commercial operations in 1973 and 1974.  In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island that allowed for operation for an additional 20 years until 2033 and 2034, respectively.  The NRC approved Prairie Island’s license renewal application in 2011.  Based on the NRC approval, a full life extension for Prairie Island’s depreciation life was approved by the MPUC in September 2011, bringing the depreciation remaining life in line with the NRC approved operating license.  The Prairie Island dry-cask storage facility currently stores 29 casks, with MPUC approval for the use of 35 additional casks, to support operations until the end of the renewed operating licenses in 2033 and 2034.

The total obligation for decommissioning currently is expected to be funded 100 percent by the external decommissioning trust fund, 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.  An updated nuclear decommissioning study was submitted to the MPUC in both November and December 2011.  Due to new state statute requirements, five decommissioning scenarios were presented, which each reflected a different timeline for the removal of spent nuclear fuel from the sites.  A decision on this filing is expected either in late 2012 or the beginning of 2013.

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 the external decommissioning trust fund, 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 6.3 percent, net of tax.  The net unrealized gain or loss on nuclear decommissioning investments is deferred as a regulatory asset or liability respectively.

The external funds are held in trust and in escrow.  The portion in escrow is subject to refund if approved by the various commissions.  The MPUC authorized the return of funds associated with the Monticello plant for the Minnesota retail jurisdictions in 2009, with refunds made on customers’ bills in 2010.  An amount of approximately $5.9 million was also withdrawn from the Monticello plant portion of the escrow fund in March 2010 in preparation for a refund to Wisconsin and Michigan retail customers.  The funds have not yet been refunded as of Dec. 31, 2011, and the timing of the refunds will be determined in future rate cases in each jurisdiction.

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At Dec. 31, 2011, NSP-Minnesota 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 from the most recently approved decommissioning study.  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.

	Regulatory Basis
(Thousands of Dollars)	2011			2010
Estimated decommissioning cost obligation (2008 dollars)	$	2,308,196		$	2,308,196
Effect of escalating costs (to 2011 and 2010 dollars, respectively, at 2.89 percent per year)		205,960			135,342
Estimated decommissioning cost obligation (in current dollars)		2,514,156			2,443,538
Effect of escalating costs to payment date (2.89 percent per year)		2,602,207			2,672,825
Estimated future decommissioning costs (undiscounted)		5,116,363			5,116,363
Effect of discounting obligation (using risk-free interest rate)		(3,187,914	)		(3,856,516	)
Discounted decommissioning cost obligation		1,928,449			1,259,847
Assets held in external decommissioning trust		1,336,431			1,350,630
Underfunding (overfunding) of external decommissioning fund compared to the discounted decommissioning obligation	$	592,018		$	(90,783	)

Decommissioning expenses recognized as a result of regulation include the following components:

(Thousands of Dollars)	2011			2010			2009
Annual decommissioning recorded as depreciation expense: (a)
Externally funded	$	-		$	934		$	2,849
Internally funded (including interest costs)		(456	)		(777	)		(884	)
Net decommissioning expense recorded	$	(456	)	$	157		$	1,965

(a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

Reductions to expense for internally-funded portions in 2011, 2010 and 2009 are a direct result of the 2008 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the previously licensed operating life of the unit (2010 for Monticello, 2013 for Prairie Island Unit 1 and 2014 for Prairie Island Unit 2).  The 2008 nuclear decommissioning filing approved in 2009 has been used for the regulatory presentation.

13.     Regulatory Assets and Liabilities

NSP-Minnesota’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1.  Under this guidance, regulatory assets and liabilities are 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 net income or OCI.

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The components of regulatory assets and liabilities shown on the consolidated balance sheets of NSP-Minnesota at Dec. 31, 2011 and 2010 are:

	See		Remaining
(Thousands of Dollars)	Note(s)		Amortization Period	Dec. 31, 2011				Dec. 31, 2010
Regulatory Assets				Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)		7	Various	$	20,836	$	312,260	$	43,289	$	198,173
Recoverable deferred taxeson AFUDC recorded in plant (b)		1	Plant lives		-		166,457		-		150,857
Net AROs (d)		1, 11, 12	Plant lives		-		136,941		-		88,804
Contract valuation adjustments (c)		1, 9	Term of related contract		13,498		118,403		-		107,526
Conservation programs (e)		1	One to two years		28,948		45,716		43,497		31,401
Nuclear refueling outage costs		1	One to two years		40,365		8,810		33,819		7,169
Renewable resources and environmental initiatives (b)		11	One to two years		19,922		10,082		25,365		10,268
Purchased power contracts costs		11	Term of related contract		-		30,905		-		25,915
Losses on reacquired debt		4	Term of related debt		1,566		17,411		2,110		18,978
Recoverable purchased natural gas costs		1	One to two years		6,157		9,867		7,475		9,907
Gas pipeline inspection and remediation costs			Pending rate case		-		7,822		-		4,276
State commission adjustments (b)		1	Plant lives		-		4,561		-		5,120
MISO Day 2 costs			One year		3,276		-		3,277		3,277
Nuclear fuel storage		12	One to five years		2,529		721		2,529		3,250
Other			Various		4,612		2,058		3,582		6,470
Total regulatory assets				$	141,709	$	872,014	$	164,943	$	671,391
Regulatory Liabilities
Plant removal costs		1, 11	Plant lives	$	-	$	382,089	$	-	$	400,233
DOE Settlement		12	Less than one year		80,249		-		-		-
Deferred income tax adjustment		1, 6	Various		-		31,518		-		29,814
Conservation programs (e)		1	Less than one year		5,382		-		-		-
Investment tax credit deferrals		1, 6	Various		-		23,802		-		25,438
Contract valuation adjustments (c)		1, 9	Term of related contract		20,976		-		2,393		-
Deferred electric energy costs		1	Less than one year		10,582		-		14,651		-
Renewable resources and environmental initiatives (b)		10, 11	Less than one year		4,358		-		14,752		-
Nuclear refueling outage costs		1	One year		3,441		-		3,441		3,441
Other			Various		7,586		1,620		6,885		3,648
Total regulatory liabilities				$	132,574	$	439,029	$	42,122	$	462,574

(a) Includes $365.2 million and $400.2 million for the regulatory recognition of pension expense at Dec. 31, 2011 and 2010, respectively.  These amounts are offset by $1.8 million of regulatory assets related to the non-qualified pension plan of which $0.2 million is included in the current asset at Dec. 31, 2011 and 2010.

(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 purchase power agreements used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

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

(e) Includes over- or under-recovered costs for conservation programs as well as incentives allowed in certain jurisdictions.

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14.     Segments and Related Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by the chief operating decision maker to evaluate the dual performance of NSP-Minnesota.  NSP-Minnesota’s performance is evaluated based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

Given the similarity of its regulated electric and regulated natural gas utility operations, NSP-Minnesota has the following reportable segments: regulated electric, regulated natural gas and all other.

· NSP-Minnesota’s regulated electric utility segment generates electricity which is transmitted and distributed 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.

· 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.

Asset and capital expenditure information is not provided for NSP-Minnesota’s reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from continuing operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

The accounting policies of the segments are the same as those described in Note 1.

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2011
Operating revenues from external customers	$	3,772,628	$	604,723	$	21,170		$	-		$	4,398,521
Intersegment revenues		547		535		-			(1,082	)		-
Total revenues	$	3,773,175	$	605,258	$	21,170		$	(1,082	)	$	4,398,521
Depreciation and amortization	$	342,570	$	38,056	$	399		$	-		$	381,025
Interest charges and financing cost		170,884		16,168		134			-			187,186
Income tax expense (benefit)		183,704		13,529		(5,584	)		-			191,649
Net income		317,458		25,447		10,076			-			352,981
2010
Operating revenues from external customers	$	3,624,715	$	589,044	$	20,557		$	-		$	4,234,316
Intersegment revenues		420		4,377		-			(4,797	)		-
Total revenues	$	3,625,135	$	593,421	$	20,557		$	(4,797	)	$	4,234,316
Depreciation and amortization	$	364,104	$	36,623	$	409		$	-		$	401,136
Interest charges and financing cost		165,099		17,090		111			-			182,300
Income tax expense		162,931		10,957		7,303			-			181,191
Net income		250,166		23,474		585			-			274,225

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	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			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		349			-			177,048
Income tax expense (benefit)		167,708		11,677		(4,264	)		-			175,121
Net income		261,556		21,881		10,333			-			293,770

15.     Related Party Transactions

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

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement.  See Note 4 for further discussion.

Additionally, during 2010, NSP-Wisconsin obtained short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements.  The borrowing arrangement terminated in the first quarter 2011.  At Dec. 31, 2010, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $37.0 million.

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)	2011		2010		2009
Operating revenues:
Electric	$	440,519	$	416,076	$	389,023
Gas		98		163		309
Operating expenses:
Purchased power		68,379		68,224		64,059
Transmission expense		55,955		48,088		45,192
Other operating expenses — paid to Xcel Energy Services Inc.		351,470		338,676		303,348
Interest expense		192		178		596
Interest income		92		69		50

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Accounts receivable and payable with affiliates at Dec. 31 were:

	2011				2010
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Wisconsin	$	18,003	$	-	$	26,864	$	-
PSCo		-		11,623		-		6,674
SPS		-		1,314		-		1,610
Other subsidiaries of Xcel Energy Inc.		30		34,714		2		53,469
	$	18,033	$	47,651	$	26,866	$	61,753

16.     Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2011		June 30, 2011		Sept. 30, 2011		Dec. 31, 2011
Operating revenues	$	1,192,892	$	1,010,526	$	1,168,138	$	1,026,965
Operating income		174,821		135,853		255,871		126,390
Net income		92,175		65,223		141,902		53,681

	Quarter Ended
(Thousands of Dollars)	March 31, 2010		June 30, 2010		Sept. 30, 2010		Dec. 31, 2010
Operating revenues	$	1,127,107	$	916,290	$	1,130,913	$	1,060,006
Operating income		142,000		107,362		217,674		131,188
Net income		64,139		44,040		109,787		56,259

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

None.

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, 2011, 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, 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, 2011 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 and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

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This annual report does not include an attestation report of NSP-Minnesota’s independent registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by NSP-Minnesota’s independent registered public accounting firm pursuant to the rules of the SEC that permit NSP-Minnesota to provide only management’s report in this annual report.

Item 9B — Other Information

None.

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 required under this Item is contained in Xcel Energy Inc.’s Proxy Statement for its 2012 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.	Consolidated Financial Statements:
	Management Report on Internal Controls Over Financial Reporting —For the year ended Dec. 31, 2011.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2011, 2010 and 2009.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2011, 2010 and 2009.
	Consolidated Balance Sheets — As of Dec. 31, 2011 and 2010.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2011, 2010 and 2009.
3.	Exhibits

* Indicates incorporation by reference

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

t Furnished, herewith, not filed.  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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 Northern Power Corp. as Amended on Aug. 1, 2000 and June 3, 2008 (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).

86

4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds (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 June 1, 1995, creating $250 million principal amount of 7.125 percent First Mortgage Bonds, Series due July 1, 2025 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995, Rider A). Supplemental Indenture dated April 1, 1997, creating $100 million principal amount of 8.5 percent First Mortgage Bonds, Series due Sept. 1, 2019 and $27.9 million principal amount of 8.5 percent First Mortgage Bonds, Series due March 1, 2019 (Exhibit 4.47 to Form 10-K (file no. 001-03034) dated Dec. 31, 1997.) Supplemental Indenture dated March 1, 1998, creating $150 million principal amount of 6.5 percent First Mortgage Bonds, Series due March 1, 2028 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998, Rider A).
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*	Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the issuance of Sr. Debt Securities. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.04*	Supplemental 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 (Assignment and Assumption of Indenture). (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.05*	Supplemental Indenture dated July 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $69 million principal amount of 8.5 percent First Mortgage Bonds, Series due April 1, 2030 (Exhibit 4.06 to NSP-Minnesota Current Report on Form 10-Q, (file no. 000-31387) dated Sept. 30, 2002).
4.06*	Supplemental Trust Indenture dated Aug. 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $450 million principal amount of 8.0 percent First Mortgage Bonds, Series due Aug. 28, 2012 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 000-31387) dated Aug. 22, 2002).
4.07*	Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250 million 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).
4.08*	Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400 million 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).
4.09*	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).
4.10*	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.
4.11*	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 million 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)).
4.12*	Supplemental Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250 million principal amount of 1.950 percent First Mortgage Bonds, Series due Aug. 15, 2015 and $250 million principal amount of 4.850 percent First Mortgage Bonds, Series due Aug. 15, 2040 (Exhibit 4.01 to Form 8-K dated Aug. 11, 2010 (file no. 001-31387)).
10.01*+	Xcel Energy 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).
10.02*+	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).
10.03*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.04*+	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).
10.05*+	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).
10.06*	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).

87

10.07*	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).
10.08*+	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).
10.09*+	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).
10.10*	Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.11*+	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).
10.12*+	Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.13*+	Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.14*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (as amended and restated effective Feb. 17, 2010) Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.15*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.16*+	Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.17*	Credit Agreement, dated as of March 17, 2011 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Capital, the investment banking division of Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Exhibit 99.02 to Form 8-K of Xcel Energy, file number 001-03034, dated March 23, 2011).
10.18*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed Apr. 5, 2011).
10.19+	Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (as amended and restated effective Nov. 29, 2011) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
10.20+	Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
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.
101 t	The following materials from NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2011 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Cash Flow, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statements of Stockholder’s Equity and Comprehensive Income, (v) Notes to Condensed Consolidated Financial Statements, and (vi) document and entity information

88

SCHEDULE II

NSP-MINNESOTA AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2011, 2010 AND 2009

(amounts in thousands)

			Additions
	Balance at Jan. 1		Charged to  Costs and Expenses		Charged  to Other  Accounts(a)		Deductions  from  Reserves(b)		Balance at  Dec. 31
Allowance for bad debts:
2011	$	20,996	$	15,936	$	5,833	$	19,761	$	23,004
2010		22,675		15,213		5,805		22,697		20,996
2009		25,699		19,408		5,521		27,953		22,675

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off or transferred.

89

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/ TERESA S. MADDEN
	Teresa S. Madden
	Senior Vice President, Chief Financial Officer and Director
	(Principal Financial Officer)
Feb. 27, 2012

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 on the date indicated above.

/s/ JUDY M. POFERL	/s/ BENJAMIN G.S. FOWKE III
Judy M. Poferl	Benjamin G.S. Fowke III
President, Chief Executive Officer and Director	Chairman and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN	/s/ JEFFREY S. SAVAGE
Teresa S. Madden	Jeffrey S. Savage
Senior Vice President, Chief Financial Officer and Director	Vice President and Controller
(Principal Financial Officer)	(Principal Accounting Officer)
/s/ DAVID M. SPARBY
David M. Sparby
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.

90

EX-12.1

Exhibit 12.01

NSP-MINNESOTA AND SUBSIDIARIES

STATEMENT OF COMPUTATION OF

RATIO OF EARNINGS TO FIXED CHARGES

(amounts in thousands, except ratio)

	Year Ended Dec. 31
	2011		2010		2009		2008		2007
Earnings, as defined:
Pretax income from operations	$	544,630	$	455,416	$	468,891	$	463,377	$	449,327
Add: Fixed charges		249,587		243,620		239,022		240,539		211,660
Total earnings, as defined	$	794,217	$	699,036	$	707,913	$	703,916	$	660,987
Fixed charges, as defined:
Interest charges	$	208,003	$	201,431	$	194,808	$	198,369	$	186,293
Interest component of leases		41,584		42,189		44,214		42,170		25,367
Total fixed charges, as defined	$	249,587	$	243,620	$	239,022	$	240,539	$	211,660
Ratio of earnings to fixed charges		3.2		2.9		3.0		2.9		3.1

EX-23.1

Exhibit 23.01

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-171732 on Form S-3 of our report dated February 27, 2012, relating to the consolidated financial statements and financial statement schedule of Northern States Power Company, a Minnesota corporation, and subsidiaries appearing in this Annual Report on Form 10-K of Northern States Power Company, a Minnesota corporation, for the year ended December 31, 2011.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

February 27, 2012

EX-31.1

Exhibit 31.01

CERTIFICATION

I, Judy M. Poferl, certify that:

1. I have reviewed this report on Form 10-K of Northern States Power Co. (a Minnesota corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions);

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ JUDY M. POFERL
	Judy M. Poferl
	President, Chief Executive Officer and Director
Date: Feb. 27, 2012

EX-31.2

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-K of Northern States Power Company (a Minnesota corporation);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions);

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Senior Vice President, Chief Financial Officer and Director
Date: Feb. 27, 2012

EX-32.1

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Northern States Power Company, a Minnesota corporation (NSP-Minnesota) on Form 10-K for the year 2011, as filed with the SEC on the date hereof (Form 10-K), each of the undersigned officers of NSP-Minnesota certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of NSP-Minnesota as of the dates and for the periods expressed in the Form 10-K.

Date: Feb. 27, 2012

/s/ JUDY M. POFERL

Judy M. Poferl

President, Chief Executive Officer and Director

/s/ TERESA S. MADDEN

Teresa S. Madden

Senior Vice President, Chief Financial Officer and Director

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to NSP-Minnesota and will be retained by NSP-Minnesota and furnished to the SEC or its staff upon request.

EX-99.1

Exhibit 99.01

NSP-MINNESOTA CAUTIONARY FACTORS

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of NSP-Minnesota, Xcel Energy Inc. or any of its other subsidiaries.  These statements are based on management’s beliefs as well as assumptions and information currently available to management.  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.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause NSP-Minnesota’s actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

· Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

· The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

· Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where NSP-Minnesota has a financial interest;

· Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

· Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

· Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, NSP-Minnesota, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

· Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

· Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

· Increased competition in the utility industry; or additional competition in the markets served by NSP-Minnesota, Xcel Energy Inc. and its other subsidiaries;

· State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

· Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance;

· Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

· Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;

· Social attitudes regarding the utility and power industries;

· Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

· Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

· Risks associated with implementations of new technologies; and

· Other business or investment considerations that may be disclosed from time to time in SEC filings, including “Risk Factors” in Item 1A of this Form 10-K, or in other publicly disseminated written documents.

NSP-Minnesota undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2011

Related Party Transactions [Abstract]

Related Party Transactions

15.     Related Party Transactions

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

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement.  See Note 4 for further discussion.

Additionally, during 2010, NSP-Wisconsin obtained short-term borrowings from NSP-Minnesota at NSP-Minnesota's average daily interest rate, including the cost of NSP-Minnesota's compensating balance requirements.  The borrowing arrangement terminated in the first quarter 2011.  At Dec. 31, 2010, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $37.0 million.

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)	2011		2010		2009
Operating revenues:
Electric	$	440,519	$	416,076	$	389,023
Gas		98		163		309
Operating expenses:
Purchased power		68,379		68,224		64,059
Transmission expense		55,955		48,088		45,192
Other operating expenses - paid to Xcel Energy Services Inc.		351,470		338,676		303,348
Interest expense		192		178		596
Interest income		92		69		50

Accounts receivable and payable with affiliates at Dec. 31 were:

	2011				2010
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Wisconsin	$	18,003	$	-	$	26,864	$	-
PSCo		-		11,623		-		6,674
SPS		-		1,314		-		1,610
Other subsidiaries of Xcel Energy Inc.		30		34,714		2		53,469
	$	18,033	$	47,651	$	26,866	$	61,753

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Long-Term Debt
Unamortized discount	$ (8,011)		$ (9,020)
Total long-term debt	3,338,897		3,337,912
Long-term debt, current maturities	450,000		19
Long-term debt, noncurrent	2,888,897		3,337,893
Common Stockholder's Equity
Common stock - 5,000,000 authorized shares of $0.01 par value, 1,000,000 shares outstanding at Dec. 31, 2011 and 2010, respectively	10		10
Additional paid in capital	2,366,391		2,241,387
Retained earnings	1,372,727		1,251,938
Accumulated other comprehensive (loss) income	(14,352)		2,834
Total common stockholder's equity	3,724,776		3,496,169
First Mortgage Bonds [Member] | Series Due Aug. 28, 2012 [Member]
Long-Term Debt
Long-term debt, gross	450,000		450,000
First Mortgage Bonds [Member] | Series Due Aug. 15, 2015 [Member]
Long-Term Debt
Long-term debt, gross	250,000		250,000
First Mortgage Bonds [Member] | Series Due March 1, 2018 [Member]
Long-Term Debt
Long-term debt, gross	500,000		500,000
First Mortgage Bonds [Member] | Series Due March 1, 2019 [Member]
Long-Term Debt
Long-term debt, gross	27,900	[1]	27,900	[1]
First Mortgage Bonds [Member] | Series Due Sept. 1, 2019 [Member]
Long-Term Debt
Long-term debt, gross	100,000	[1]	100,000	[1]
First Mortgage Bonds [Member] | Series Due July 1, 2025 [Member]
Long-Term Debt
Long-term debt, gross	250,000		250,000
First Mortgage Bonds [Member] | Series Due March 1, 2028 [Member]
Long-Term Debt
Long-term debt, gross	150,000		150,000
First Mortgage Bonds [Member] | Series Due April 1, 2030 [Member]
Long-Term Debt
Long-term debt, gross	69,000	[1]	69,000	[1]
First Mortgage Bonds [Member] | Series Due July 15, 2035 [Member]
Long-Term Debt
Long-term debt, gross	250,000		250,000
First Mortgage Bonds [Member] | Series Due June 1, 2036 [Member]
Long-Term Debt
Long-term debt, gross	400,000		400,000
First Mortgage Bonds [Member] | Series Due July 1, 2037 [Member]
Long-Term Debt
Long-term debt, gross	350,000		350,000
First Mortgage Bonds [Member] | Series Due Nov. 1, 2039 [Member]
Long-Term Debt
Long-term debt, gross	300,000		300,000
First Mortgage Bonds [Member] | Series Due Aug. 15, 2040 [Member]
Long-Term Debt
Long-term debt, gross	250,000		250,000
Other [Member]
Long-Term Debt
Long-term debt, gross	$ 8		$ 32

[1] Pollution control financing

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME [Abstract]
Pension and retiree medical benefit adjustments, tax	$ (262)	$ (30)	$ 143
Net derivative instrument changes during the period, tax	(11,516)	717	615
Unrealized gain (loss) - marketable securities, tax	$ (63)	$ 89	$ 284

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating revenues
Electric	$ 3,772,628	$ 3,624,715	$ 3,407,273
Natural gas	604,723	589,044	640,323
Other	21,170	20,557	19,093
Total operating revenues	4,398,521	4,234,316	4,066,689
Operating expenses
Electric fuel and purchased power	1,542,760	1,536,076	1,411,877
Cost of natural gas sold and transported	393,672	399,524	464,043
Cost of sales - other	12,737	12,405	11,076
Operating and maintenance expenses	1,064,665	1,037,752	968,370
Conservation program expenses	138,001	86,298	59,244
Depreciation and amortization	381,025	401,136	389,367
Taxes (other than income taxes)	172,726	162,901	147,193
Total operating expenses	3,705,586	3,636,092	3,451,170
Operating income	692,935	598,224	615,519
Other income, net	1,717	1,151	1,572
Allowance for funds used during construction - equity	37,164	38,341	28,848
Interest charges and financing costs
Interest charges - includes other financing costs of $6,264, $5,645, and $5,778, respectively	208,003	201,431	194,808
Allowance for funds used during construction - debt	(20,817)	(19,131)	(17,760)
Total interest charges and financing costs	187,186	182,300	177,048
Income before income taxes	544,630	455,416	468,891
Income taxes	191,649	181,191	175,121
Net income	$ 352,981	$ 274,225	$ 293,770

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2011	Dec. 31, 2010
Capitalization
Common stock, shares authorized (in shares)	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	1,000,000	1,000,000

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Nuclear Obligations

12 Months Ended

Dec. 31, 2011

Nuclear Obligations [Abstract]

Nuclear Obligations

12.      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 $11 million in 2011, $13 million in 2010 and $12 million 2009.  In total, NSP-Minnesota had paid approximately $422.3 million to the DOE through Dec. 31, 2011.  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.  In 2011, NSP-Minnesota received from the DOE pursuant to a settlement with the DOE, an initial payment of approximately $100 million to cover damages through the end of 2008.  As of Dec. 31, 2011, NSP-Minnesota has recorded the payment as restricted cash and a regulatory liability.

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 renewed licenses terms in 2033 for Unit 1 and 2034 for Unit 2 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 at least 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 the applicable accounting guidance.

Monticello received its initial operating license in 1970 and began commercial operation in 1971.  With its renewed operating license and CON for spent fuel capacity to support 20 years of extended operation, Monticello 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 received their initial operating license and began commercial operations in 1973 and 1974.  In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island that allowed for operation for an additional 20 years until 2033 and 2034, respectively.  The NRC approved Prairie Island's license renewal application in 2011.  Based on the NRC approval, a full life extension for Prairie Island's depreciation life was approved by the MPUC in September 2011, bringing the depreciation remaining life in line with the NRC approved operating license.  The Prairie Island dry-cask storage facility currently stores 29 casks, with MPUC approval for the use of 35 additional casks, to support operations until the end of the renewed operating licenses in 2033 and 2034.

The total obligation for decommissioning currently is expected to be funded 100 percent by the external decommissioning trust fund, 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.  An updated nuclear decommissioning study was submitted to the MPUC in both November and December 2011.  Due to new state statute requirements, five decommissioning scenarios were presented, which each reflected a different timeline for the removal of spent nuclear fuel from the sites.  A decision on this filing is expected either in late 2012 or the beginning of 2013.

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 the external decommissioning trust fund, 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 6.3 percent, net of tax.  The net unrealized gain or loss on nuclear decommissioning investments is deferred as a regulatory asset or liability respectively.

The external funds are held in trust and in escrow.  The portion in escrow is subject to refund if approved by the various commissions.  The MPUC authorized the return of funds associated with the Monticello plant for the Minnesota retail jurisdictions in 2009, with refunds made on customers' bills in 2010.  An amount of approximately $5.9 million was also withdrawn from the Monticello plant portion of the escrow fund in March 2010 in preparation for a refund to Wisconsin and Michigan retail customers.  The funds have not yet been refunded as of Dec. 31, 2011, and the timing of the refunds will be determined in future rate cases in each jurisdiction.

At Dec. 31, 2011, NSP-Minnesota 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 from the most recently approved decommissioning study.  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.

	Regulatory Basis
(Thousands of Dollars)	2011			2010
Estimated decommissioning cost obligation (2008 dollars)	$	2,308,196		$	2,308,196
Effect of escalating costs (to 2011 and 2010 dollars, respectively, at 2.89 percent per year)		205,960			135,342
Estimated decommissioning cost obligation (in current dollars)		2,514,156			2,443,538
Effect of escalating costs to payment date (2.89 percent per year)		2,602,207			2,672,825
Estimated future decommissioning costs (undiscounted)		5,116,363			5,116,363
Effect of discounting obligation (using risk-free interest rate)		(3,187,914	)		(3,856,516	)
Discounted decommissioning cost obligation		1,928,449			1,259,847
Assets held in external decommissioning trust		1,336,431			1,350,630
Underfunding (overfunding) of external decommissioning fund compared to the discounted decommissioning obligation	$	592,018		$	(90,783	)

Decommissioning expenses recognized as a result of regulation include the following components:

(Thousands of Dollars)	2011			2010			2009
Annual decommissioning recorded as depreciation expense: (a)
Externally funded	$	-		$	934		$	2,849
Internally funded (including interest costs)		(456	)		(777	)		(884	)
Net decommissioning expense recorded	$	(456	)	$	157		$	1,965

(a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

Reductions to expense for internally-funded portions in 2011, 2010 and 2009 are a direct result of the 2008 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the previously licensed operating life of the unit (2010 for Monticello, 2013 for Prairie Island Unit 1 and 2014 for Prairie Island Unit 2).  The 2008 nuclear decommissioning filing approved in 2009 has been used for the regulatory presentation.

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Segments and Related Information

12 Months Ended

Dec. 31, 2011

Segments and Related Information [Abstract]

Segments and Related Information

14.     Segments and Related Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by the chief operating decision maker to evaluate the dual performance of NSP-Minnesota.  NSP-Minnesota's performance is evaluated based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

Given the similarity of its regulated electric and regulated natural gas utility operations, NSP-Minnesota has the following reportable segments: regulated electric, regulated natural gas and all other.

· NSP-Minnesota's regulated electric utility segment generates electricity which is transmitted and distributed 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.

· 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.

Asset and capital expenditure information is not provided for NSP-Minnesota's reportable segments because as an integrated electric and natural gas utility, NSP-Minnesota operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from continuing operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment.  However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators.  A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

The accounting policies of the segments are the same as those described in Note 1.

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2011
Operating revenues from external customers	$	3,772,628	$	604,723	$	21,170		$	-		$	4,398,521
Intersegment revenues		547		535		-			(1,082	)		-
Total revenues	$	3,773,175	$	605,258	$	21,170		$	(1,082	)	$	4,398,521
Depreciation and amortization	$	342,570	$	38,056	$	399		$	-		$	381,025
Interest charges and financing cost		170,884		16,168		134			-			187,186
Income tax expense (benefit)		183,704		13,529		(5,584	)		-			191,649
Net income		317,458		25,447		10,076			-			352,981
2010
Operating revenues from external customers	$	3,624,715	$	589,044	$	20,557		$	-		$	4,234,316
Intersegment revenues		420		4,377		-			(4,797	)		-
Total revenues	$	3,625,135	$	593,421	$	20,557		$	(4,797	)	$	4,234,316
Depreciation and amortization	$	364,104	$	36,623	$	409		$	-		$	401,136
Interest charges and financing cost		165,099		17,090		111			-			182,300
Income tax expense		162,931		10,957		7,303			-			181,191
Net income		250,166		23,474		585			-			274,225

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			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		349			-			177,048
Income tax expense (benefit)		167,708		11,677		(4,264	)		-			175,121
Net income		261,556		21,881		10,333			-			293,770

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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY AND COMPREHENSIVE INCOME (USD $) In Thousands, except Share data	Common Stock [Member]	Additional Paid In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
Balance at Dec. 31, 2008	$ 10	$ 1,915,857	$ 1,149,833	$ 205	$ 3,065,905
Balance (in shares) at Dec. 31, 2008	1,000,000
Net income			293,770		293,770
Pension and retiree medical benefit adjustments, net of tax				208	208
Net derivative instrument changes during the period, net of tax				888	888
Unrealized loss (gain) - marketable securities, net of tax				411	411
Comprehensive income for the period					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	10	2,028,593	1,210,894	1,712	3,241,209
Balance (in shares) at Dec. 31, 2009	1,000,000
Net income			274,225		274,225
Pension and retiree medical benefit adjustments, net of tax				(43)	(43)
Net derivative instrument changes during the period, net of tax				1,036	1,036
Unrealized loss (gain) - marketable securities, net of tax				129	129
Comprehensive income for the period					275,347
Common dividends declared to parent			(233,181)		(233,181)
Contribution of capital by parent		212,794			212,794
Balance at Dec. 31, 2010	10	2,241,387	1,251,938	2,834	3,496,169
Balance (in shares) at Dec. 31, 2010	1,000,000				1,000,000
Net income			352,981		352,981
Pension and retiree medical benefit adjustments, net of tax				(388)	(388)
Net derivative instrument changes during the period, net of tax				(16,706)	(16,706)
Unrealized loss (gain) - marketable securities, net of tax				(92)	(92)
Comprehensive income for the period					335,795
Common dividends declared to parent			(232,192)		(232,192)
Contribution of capital by parent		125,004			125,004
Balance at Dec. 31, 2011	$ 10	$ 2,366,391	$ 1,372,727	$ (14,352)	$ 3,724,776
Balance (in shares) at Dec. 31, 2011	1,000,000				1,000,000

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Interest charges and financing costs
Other financing costs	$ 6,264	$ 5,645	$ 5,778

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Benefit Plans and Other Postretirement Benefits

12 Months Ended

Dec. 31, 2011

Benefit Plans and Other Postretirement Benefits [Abstract]

Benefit Plans and Other Postretirement Benefits

7.        Benefit Plans and Other Postretirement Benefits

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Minnesota accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans.  NSP-Minnesota is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Minnesota accounts for it's pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Minnesota employees.

Xcel Energy, which includes NSP-Minnesota, offers various benefit plans to its employees.  Approximately 61 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements.  At Dec. 31, 2011, NSP-Minnesota had 2,033 covered under a collective-bargaining agreement, which expires at the end of 2013.  NSP-Minnesota also had an additional 228 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2012 and 2013.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value.  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 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 private equity investments and real estate investments, for which the measurement of net asset value requires significant use of unobservable inputs when determining the fair value of the underlying fund investments, including equity in non-publicly traded entities and real estate properties.

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 Inc.'s and NSP-Minnesota's policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Xcel Energy Inc. and NSP-Minnesota base the 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 pension cost determination assumes a forecasted mix of investment types over the long term.  Investment returns in 2011 were below the assumed level of 8.00 percent.  Investment returns in 2010 and 2009 were above the assumed level of 8.00 and 8.50 percent, respectively.  Xcel Energy Inc. and NSP-Minnesota continually review the pension assumptions.  In 2012, NSP-Minnesota's estimated investment-return assumption is 7.50 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.'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 projected 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, as NSP-Minnesota has experienced in recent years, unusual market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocations for NSP-Minnesota:

	2011			2010
Domestic and international equity securities		31	%		31	%
Long-duration fixed income securities		26			28
Short-to-intermediate term fixed income securities		14			12
Alternative investments		26			22
Cash		3			7
Total		100	%		100	%

The ongoing investment strategy 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 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 projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, NSP-Minnesota's pension plan assets that are measured at fair value as of Dec. 31, 2011 and 2010:

	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	42,644	$	-		$	-	$	42,644
Derivatives		-		1,914			-		1,914
Government securities		-		48,925			-		48,925
Corporate bonds		-		164,355			-		164,355
Asset-backed securities		-		-			10,188		10,188
Mortgage-backed securities		-		-			24,413		24,413
Common stock		23,844		-			-		23,844
Private equity investments		-		-			54,499		54,499
Commingled funds		-		416,599			-		416,599
Real estate		-		-			12,967		12,967
Securities lending collateral obligation and other		-		(16,819	)		-		(16,819	)
Total	$	66,488	$	614,974		$	102,067	$	783,529

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	72,568	$	-		$	-	$	72,568
Derivatives		-		2,662			-		2,662
Government securities		-		43,596			-		43,596
Corporate bonds		-		170,520			-		170,520
Asset-backed securities		-		-			8,771		8,771
Mortgage-backed securities		-		-			38,403		38,403
Common stock		44,239		-			-		44,239
Private equity investments		-		-			43,027		43,027
Commingled funds		-		371,122			-		371,122
Real estate		-		-			24,041		24,041
Securities lending collateral obligation and other		-		(26,095	)		-		(26,095	)
Total	$	116,807	$	561,805		$	114,242	$	792,854

The following tables present the changes in NSP-Minnesota's Level 3 pension plan assets for the years ended Dec. 31, 2011, 2010 and 2009:

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2011
Asset-backed securities	$	8,771	$	781		$	(805	)	$	1,441		$	10,188
Mortgage-backed securities		38,403		355			(1,894	)		(12,451	)		24,413
Real estate		24,041		(219	)		6,416			(17,271	)		12,967
Private equity investments		43,027		1,354			4,196			5,922			54,499
Total	$	114,242	$	2,271		$	7,913		$	(22,359	)	$	102,067

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2010
Asset-backed securities	$	15,473	$	1,109		$	(910	)	$	(6,901	)	$	8,771
Mortgage-backed securities		47,823		4,539			(4,634	)		(9,325	)		38,403
Real estate		21,630		(13	)		2,182			242			24,041
Private equity investments		26,622		(355	)		5,269			11,491			43,027
Total	$	111,548	$	5,280		$	1,907		$	(4,493	)	$	114,242

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)			Gains (Losses)			Settlements, Net			Dec. 31, 2009
Asset-backed securities	$	26,553	$	771		$	15,490		$	(27,341	)	$	15,473
Mortgage-backed securities		57,146		1,791			34,139			(45,253	)		47,823
Real estate		37,480		(185	)		(13,936	)		(1,729	)		21,630
Private equity investments		27,790		-			(4,802	)		3,634			26,622
Total	$	148,969	$	2,377		$	30,891		$	(70,689	)	$	111,548

Benefit Obligations - A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Minnesota is presented in the following table:

(Thousands of Dollars)	2011			2010
Accumulated Benefit Obligation at Dec. 31	$	976,227		$	926,227
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	989,277		$	926,684
Service cost		28,016			26,736
Interest cost		51,946			53,929
Plan amendments		-			14,484
Actuarial loss		59,195			60,307
Benefit payments		(96,840	)		(92,863	)
Obligation at Dec. 31	$	1,031,594		$	989,277
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	792,854		$	768,997
Actual return on plan assets		46,140			96,538
Employer contributions		41,375			20,182
Benefit payments		(96,840	)		(92,863	)
Fair value of plan assets at Dec. 31	$	783,529		$	792,854
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(248,065	)	$	(196,423	)
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	611,409		$	552,849
Prior service cost		24,085			37,254
Total	$	635,494		$	590,103
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	51,427		$	39,813
Noncurrent regulatory assets		584,067			550,290
Total	$	635,494		$	590,103
Measurement date	Dec. 31, 2011			Dec. 31, 2010

(a) Amounts are recognized in noncurrent liabilities on NSP-Minnesota's consolidated balance sheet.

(Thousands of Dollars)	2011		2010
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	5.00	%	5.50	%
Expected average long-term increase in compensation level	4.00		4.00
Mortality table	RP 2000		RP 2000

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 2008 through 2010 for Xcel Energy's pension plans.  Required contributions were made in 2011 and 2012 to meet minimum funding requirements.

The Pension Protection Act changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2010 through 2012:

· In January 2012, contributions of $190.5 million were made across four of Xcel Energy's pension plans, of which $79.3 million was attributable to NSP-Minnesota;

· In 2011, contributions of $137.3 million were made across three of Xcel Energy's pension plans, of which $41.4 million was attributable to NSP-Minnesota;

· In 2010, contributions of $34 million were made to the Xcel Energy Pension Plan, of which $20.2 million was attributable to NSP-Minnesota.

· For future years, we anticipate contributions will be made as necessary.

Plan Amendments - No amendments occurred during 2011 to the Xcel Energy pension plans.

Benefit Costs -The components of NSP-Minnesota's net periodic pension cost were:

(Thousands of Dollars)	2011			2010			2009
Service cost	$	28,016		$	26,736		$	23,027
Interest cost		51,946			53,929			54,868
Expected return on plan assets		(74,241	)		(76,611	)		(86,730	)
Amortization of prior service cost		13,169			11,726			11,726
Amortization of net loss		28,736			17,728			-
Net periodic pension cost	$	47,626		$	33,508		$	2,891
Costs not recognized due to effects of regulation		(34,898	)		(27,027	)		(2,891	)
Net benefit cost recognized for financial reporting	$	12,728		$	6,481		$	-
Significant Assumptions Used to Measure Costs:
Discount rate		5.50	%		6.00	%		6.75	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term rate of return on assets		8.00			8.00			8.50

In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Minnesota based on Xcel Energy Services Inc. employees' labor costs.  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 2012 pension cost calculations will be 7.50 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.  As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

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 $8.6 million in 2011, $8.8 million in 2010 and $7.5 million in 2009.

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 certain Xcel Energy retirees.  The former NSP 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.

In 1993, Xcel Energy Inc. and NSP-Minnesota adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized 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.

Plan Assets - Certain state agencies that regulate Xcel Energy Inc.'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 Inc. 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 Inc.'s and NSP-Minnesota's return, correlation, 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 projected 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 tables present, for each of the fair value hierarchy levels, NSP-Minnesota's postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2011 and 2010:

	Dec. 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	882	$	-		$	-	$	882
Derivatives		-		203			-		203
Government securities		-		1,007			-		1,007
Corporate bonds		-		939			-		939
Asset-backed securities		-		-			119		119
Mortgage-backed securities		-		-			415		415
Preferred stock		-		6			-		6
Commingled funds		-		3,091			-		3,091
Securities lending collateral obligation and other		-		(169	)		-		(169	)
Total	$	882	$	5,077		$	534	$	6,493

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	2,711	$	-	$	-	$	2,711
Derivatives		-		248		-		248
Government securities		-		62		-		62
Corporate bonds		-		1,288		-		1,288
Asset-backed securities		-		-		47		47
Mortgage-backed securities		-		-		350		350
Preferred stock		-		9		-		9
Commingled funds		-		1,874		-		1,874
Securities lending collateral obligation and other		-		1,087		-		1,087
Total	$	2,711	$	4,568	$	397	$	7,676

The following tables present the changes in NSP-Minnesota's Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2011, 2010 and 2009:

									Purchases,
			Net Realized			Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2011		Gains (Losses)			Gains (Losses)			Settlements, net		Dec. 31, 2011
Asset-backed securities	$	47	$	-		$	(15	)	$	87	$	119
Mortgage-backed securities		350		(26	)		41			50		415

								Purchases,
			Net Realized			Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2010		Gains (Losses)			Gains (Losses)		Settlements, net			Dec. 31, 2010
Asset-backed securities	$	232	$	(5	)	$	26	$	(206	)	$	47
Mortgage-backed securities		1,319		(17	)		131		(1,083	)		350

							Purchases,
			Net Realized		Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2009		Gains (Losses)		Gains (Losses)		Settlements, net			Dec. 31, 2009
Asset-backed securities	$	313	$	-	$	46	$	(127	)	$	232
Mortgage-backed securities		2,516		21		137		(1,355	)		1,319

Benefit Obligations - A comparison of the actuarially computed benefit obligation and plan assets for NSP-Minnesota is presented in the following table:

(Thousands of Dollars)	2011			2010
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	134,996		$	135,434
Service cost		87			72
Interest cost		7,372			7,956
Medicare subsidy reimbursements		739			1,338
ERRP proceeds shared with retirees		2,120			-
Plan participants' contributions		5,997			5,460
Actuarial loss		14,295			3,965
Benefit payments		(19,563	)		(19,229	)
Obligation at Dec. 31	$	146,043		$	134,996

(Thousands of Dollars)	2011			2010
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	7,676		$	10,777
Actual (loss) return on plan assets		(69	)		831
Plan participants' contributions		5,997			5,460
Employer contributions		12,452			9,837
Benefit payments		(19,563	)		(19,229	)
Fair value of plan assets at Dec. 31	$	6,493		$	7,676
Funded Status of Plans at Dec. 31:
Funded status	$	(139,550	)	$	(127,320	)
Current assets		332			-
Current liabilities		(5,448	)		(3,743	)
Noncurrent liabilities		(134,434	)		(123,577	)
Net postretirement amounts recognized on consolidated balance sheets	$	(139,550	)	$	(127,320	)
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	64,473		$	51,208
Prior service credit		(918	)		(1,035	)
Transition obligation		1,381			2,727
Total	$	64,936		$	52,900
Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	4,426		$	3,276
Noncurrent regulatory assets		56,683			46,449
Deferred Income taxes		1,561			1,298
Net-of-tax accumulated comprehensive income		2,266			1,877
Total	$	64,936		$	52,900
Measurement date	Dec. 31, 2011			Dec. 31, 2010
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.00	%		5.50	%
Mortality table	RP 2000			RP 2000
Health care costs trend rate - initial		6.31	%		6.50	%

Effective Dec. 31, 2011, the ultimate trend assumption remained unchanged at 5.0 percent.  The period until the ultimate rate is reached remained unchanged at eight 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:

	One Percentage Point
(Thousands of Dollars)	Increase			Decrease
APBO		$	14,985		$	(12,256	)
Service and interest components			890			(708	)

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 $49.0 million and $48.4 million during 2011 and 2010, of which $12.5 million and $9.8 million were attributable to NSP-Minnesota.  Xcel Energy expects to contribute approximately $39.1 million during 2012, of which $12.0 million is attributable to NSP-Minnesota.

Plan Amendments - No amendments affecting NSP-Minnesota occurred during 2011 to the Xcel Energy health and welfare benefit plan.

Benefit Costs - The components of NSP-Minnesota's net periodic postretirement benefit cost were:

(Thousands of Dollars)	2011			2010			2009
Service cost	$	87		$	72		$	132
Interest cost		7,372			7,956			9,140
Expected return on plan assets		(576	)		(809	)		(757	)
Amortization of transition obligation		1,346			1,346			1,346
Amortization of prior service cost		(117	)		(117	)		-
Amortization of net loss		2,348			2,195			3,558
Net periodic postretirement benefit cost	$	10,460		$	10,643		$	13,419
Significant Assumptions Used to Measure Costs:
Discount rate		5.50	%		6.00	%		6.75	%
Expected average long-term rate of return on assets (before tax)		7.50			7.50			7.50

In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy, Inc., costs are allocated to NSP-Minnesota based on Xcel Energy Services Inc. employees' labor costs. 

Projected Benefit Payments

The following table lists NSP-Minnesota's 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
2012	$	100,930	$	13,079	$	1,137	$	11,942
2013		98,095		13,123		1,200		11,923
2014		98,565		13,091		1,261		11,830
2015		96,641		13,066		1,317		11,749
2016		97,865		12,988		1,371		11,617
2017-2021		457,351		60,296		7,344		52,952

Multiemployer Plans

NSP-Minnesota contributes to several union multiemployer pension and other postretirement benefit plans, none of which are individually significant.  These plans provide pension and postretirement health care benefits to certain union employees, including electrical workers, boilermakers, and other construction and facilities workers who may perform services for more than one employer during a given period and do not participate in the NSP-Minnesota sponsored pension and postretirement health care plans.  Contributing to these types of plans creates risk that differs from providing benefits under NSP-Minnesota sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2011, 2010 and 2009. There were no significant changes to the nature or magnitude of the participation of NSP-Minnesota in multiemployer plans for the years presented:

(Thousands of Dollars)	2011		2010		2009
Multiemployer plan contributions:
Pension	$	17,811	$	13,461	$	11,348
Other postretirement benefits		336		153		140
Total	$	18,147	$	13,614	$	11,488

XML

Document And Entity Information	12 Months Ended
	Dec. 31, 2011	Feb. 27, 2012
Entity Registrant Name	NORTHERN STATES POWER CO
Entity Central Index Key	0001123852
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,000,000
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2011

XML

Other Income, Net

12 Months Ended

Dec. 31, 2011

Other Income, Net [Abstract]

Other Income, Net

8.        Other Income, Net

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

(Thousands of Dollars)	2011			2010			2009
Interest income	$	4,663		$	5,887		$	7,473
Other nonoperating income (expense)		969			(30	)		(6	)
Life insurance policy expense		(3,915	)		(4,706	)		(5,895	)
Other income, net	$	1,717		$	1,151		$	1,572

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating activities
Net income	$ 352,981	$ 274,225	$ 293,770
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	386,310	401,602	394,712
Nuclear fuel amortization	100,902	105,369	80,104
Deferred income taxes	196,120	251,747	177,347
Amortization of investment tax credits	(2,694)	(2,697)	(3,120)
Allowance for equity funds used during construction	(37,164)	(38,341)	(28,848)
Provision for bad debts	15,936	15,213	19,408
Net derivative gains	(182)	(8,784)	(4,960)
Changes in operating assets and liabilities
Accounts receivable	(8,195)	(24,216)	74,818
Accrued unbilled revenues	18,090	(20,055)	19,113
Inventories	(21,675)	(24,254)	89,984
Other current assets	(614)	(858)	(13,589)
Accounts payable	(33,806)	(70,715)	39,229
Net regulatory assets and liabilities	75,390	18,575	(70,879)
Other current liabilities	91,532	39,899	19,066
Pension and other employee benefit obligations	(39,925)	(19,623)	(8,111)
Change in other noncurrent assets	(7,330)	459	44
Change in other noncurrent liabilities	(36,345)	(23,250)	(17,011)
Net cash provided by operating activities	1,049,331	874,296	1,061,077
Investing activities
Utility capital/construction expenditures	(1,028,831)	(1,208,268)	(835,262)
Merricourt refund	101,261	0	0
Merricourt deposit	(90,833)	(1,134)	(9,294)
Allowance for equity funds used during construction	37,164	38,341	28,848
Purchase of investments in external decommissioning fund	(2,098,642)	(3,781,438)	(1,644,278)
Proceeds from sale of investments in external decommissioning fund	2,098,642	3,786,373	1,664,957
Investments in utility money pool arrangement	(432,000)	(246,000)	(132,500)
Repayments from utility money pool arrangement	432,000	253,000	125,500
Advances to affiliate	(111,300)	(302,300)	(62,500)
Advances from affiliate	148,300	280,800	47,000
Change in restricted cash	(95,287)	0	0
Other, net	(5,668)	509	(6,415)
Net cash used in investing activities	(1,045,194)	(1,180,117)	(823,944)
Financing activities
Issuances (repayments) of short-term borrowings, net	26,000	0	(65,000)
Borrowings under utility money pool arrangement	627,600	711,000	601,700
Repayments under utility money pool arrangement	(562,600)	(711,000)	(665,200)
Proceeds from issuance of long-term debt	0	493,390	295,340
Repayment of long-term debt, including reacquisition premiums	(34)	(175,034)	(250,041)
Capital contributions from parent	125,004	212,794	112,736
Dividends paid to parent	(232,510)	(233,224)	(232,708)
Net cash (used in) provided by financing activities	(16,540)	297,926	(203,173)
Net change in cash and cash equivalents	(12,403)	(7,895)	33,960
Cash and cash equivalents at beginning of period	38,408	46,303	12,343
Cash and cash equivalents at end of period	26,005	38,408	46,303
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(181,121)	(172,463)	(178,017)
Cash (paid) received for income taxes, net	(15,964)	81,836	24,719
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 35,058	$ 59,836	$ 34,172

XML

Accounting Pronouncements

12 Months Ended

Dec. 31, 2011

Accounting Pronouncements [Abstract]

Accounting Pronouncements

2.        Accounting Pronouncements

Recently Adopted

Multiemployer Plans - In September 2011, the FASB issued Multiemployer Plans (Subtopic 715-80) - Disclosures about an Employer's Participation in a Multiemployer Plan (ASU No. 2011-09), which updates the Codification to require certain disclosures about an entity's involvement with multiemployer pension and other postretirement benefit plans.  These updates do not affect recognition and measurement guidance for an employer's participation in multiemployer plans, but rather require additional disclosure such as the nature of multiemployer plans and the employer's participation, contributions to the plans and details regarding any significant plans.  These updates to the Codification are effective for annual periods ending after Dec. 15, 2011.  NSP-Minnesota implemented the annual disclosure guidance effective Jan. 1, 2011, and the implementation did not have a material impact on its consolidated financial statements.  For further information and required disclosures,

see Note 7.

Recently Issued

Fair Value Measurement - In May 2011, the FASB issued Fair Value Measurement (Topic 820) - Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU No. 2011-04), which provides additional guidance for fair value measurements.  These updates to the Codification include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders' equity.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota does not expect the implementation of this guidance to have a material impact on its consolidated financial statements.

Comprehensive Income - In June 2011, the FASB issued Comprehensive Income (Topic 220) - Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of OCI and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income.  These updates do not affect the items reported in OCI or the guidance for reclassifying such items to net income.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota does not expect the implementation of this presentation guidance to have a material impact on its consolidated financial statements.

Balance Sheet Offsetting - In December 2011, the FASB issued Balance Sheet (Topic 210) - Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which updates the Codification to require disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity's financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  These updates to the disclosure requirements of the Codification do not affect the presentation of amounts in the consolidated balance sheets, and are effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those periods.  NSP-Minnesota does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

1.        Summary of Significant Accounting Policies

Business and System of Accounts- NSP-Minnesota is principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  NSP-Minnesota's consolidated financial statements and disclosures are presented in accordance with GAAP.  All of NSP-Minnesota's underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation- NSP-Minnesota's consolidated financial statements include its wholly-owned subsidiaries.  In the consolidation process, all intercompany transactions and balances are eliminated.  NSP-Minnesota has investments in certain plants and transmission facilities jointly owned with nonaffiliated utilities.  NSP-Minnesota's proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets, and NSP-Minnesota's proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income.  See Note 5 for further discussion of jointly owned generation and transmission facilities and related ownership percentages.

NSP-Minnesota evaluates its arrangements and contracts with other entities, including but not limited to, investments, purchased power agreements and fuel contracts to determine if the other party is a variable interest entity and if so, if NSP-Minnesota is the primary beneficiary.  NSP-Minnesota follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity's financial performance and power to direct those activities, when determining whether NSP-Minnesota is a variable interest entity's primary beneficiary.  See Note 11 for further discussion of variable interest entities.

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

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

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

· Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

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

If restructuring or other changes in the regulatory environment occur, 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 financial condition, results of operations and cash flows in the period the write-offs are recorded.  See Note 13 for further discussion of regulatory assets and liabilities.

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

NSP-Minnesota participates in MISO.  The revenues and charges from MISO related to serving retail and wholesale electric customers comprising the native load of NSP-Minnesota are recorded on a net basis within cost of sales.   Revenues and charges for short term wholesale sales of excess energy transacted through MISO are recorded on a gross basis in electric revenues and cost of sales.

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 cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.

Conservation Programs - NSP-Minnesota has implemented programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems.  These programs include, but are not limited to, commercial process efficiency and lighting updates, and residential rebates for participation in air conditioning interruption and energy-efficient appliances.

The costs incurred for CIP programs are deferred if it is probable that future revenue, in an amount at least equal to the deferred amount, will be provided to permit recovery of the previously incurred cost, rather than to provide for expected future amounts of similar programs.  For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned.

NSP-Minnesota's CIP program costs are recovered through a combination of base rate revenue and rider mechanisms.  The revenue billed to customers recovers incurred costs for conservation programs and also incentive amounts that are designed to encourage NSP-Minnesota's achievement of energy conservation goals and to compensate for related lost sales margin.  NSP-Minnesota recognizes regulatory assets to reflect the amount of costs or earned incentives that have not yet been collected from customers.

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.  Amounts recovered in rates for future removal costs are recorded as regulatory liabilities.  Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.  Maintenance and replacement of items determined to be less than 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.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.  Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable.

NSP-Minnesota records depreciation expense related to its plant 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, 2011, 2010 and 2009 was 3.2, 3.4 and 3.2 percent, respectively.

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

AFUDC- AFUDC represents the cost of capital used to finance utility construction activity.  AFUDC is computed by applying a composite pretax rate to qualified CWIP.  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, cost of capital 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.  However, in some cases, including for certain wind and transmission projects, the MPUC has approved a more current recovery of financing costs associated with large capital projects, through various riders, resulting in a lower recognition of AFUDC.

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

Nuclear Decommissioning – Nuclear decommissioning studies estimate NSP-Minnesota's ultimate costs of decommissioning its nuclear power plants and are performed at least every three years and submitted to the MPUC for approval.  NSP-Minnesota filed its most recent triennial nuclear decommissioning studies with the MPUC in December 2011.  These studies reflect NSP-Minnesota's plans, under the current operating licenses, for prompt dismantlement of the Monticello and Prairie Island facilities.  These studies assume that NSP-Minnesota will be storing spent fuel on site pending removal to a U.S. government facility.

For rate making purposes, NSP-Minnesota recovers the total decommissioning costs related to its nuclear power plants, including operating costs associated with spent fuel, over each facility's expected service life based on the triennial decommissioning studies filed with the MPUC.  The costs are initially determined in nominal amounts prior to escalation adjustments, then future periods' costs are escalated using decommissioning-specific cost escalators and finally discounted using risk-free interest rates.  See Note 12 for further discussion of the approved nuclear decommissioning obligation.

For financial reporting purposes, NSP-Minnesota recognizes decommissioning liabilities, excluding future operating costs associated with spent fuel, in accordance with accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred.  In accordance with regulatory accounting, any difference between expense recognized for financial reporting purposes and the amount recovered in rates is reported as a regulatory asset or liability.  Costs are initially determined in nominal amounts prior to escalation adjustments, then future periods' costs are escalated using decommissioning-specific cost escalators and then discounted using weighted-average credit-adjusted risk-free interest rates.

Restricted funds for the payment of future decommissioning expenditures for NSP-Minnesota's nuclear facilities are included in the nuclear decommissioning fund on the consolidated balance sheets.  See Note 9 for further discussion of the nuclear decommissioning fund.

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 and costs associated with the end-of-life fuel segments.

Nuclear Refueling Outage Costs -NSP-Minnesota uses a deferral and amortization method for nuclear refueling O&M costs.  This method amortizes refueling outage costs over the period between refueling outages consistent with how the costs are recovered ratably in electric rates.

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 resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13.

NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  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.

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

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments - 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 the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  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 as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

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

Normal Purchases and Normal Sales - NSP-Minnesota enters into contracts for the purchase and sale of commodities for use in its business operations.  Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting 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.

See Note 9 for further discussion of NSP-Minnesota's risk management and derivative activities.

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 electric operating revenues in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of NSP-Minnesota's commodity trading margins 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 and commodity trading results include the impact of all margin-sharing mechanisms.  For further information, see Note 9.

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; money market funds are measured using quoted net asset values.  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.  For further information, see Note 9.

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.

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

Inventory- All inventory is recorded at average cost.

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 RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced.  Currently, NSP-Minnesota acquires RECs from the generation or purchase of renewable power.

When RECs are acquired in the course of generation or purchased as a result of meeting load obligations, they are recorded as inventory at cost.  The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.

Sales of RECs that are acquired in the course of generation or purchased as a result of meeting load obligations are recorded in electric utility operating revenues on a gross basis.  The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.  RECs acquired for trading purposes are recorded as other investments and are also recorded at cost.  The sales of RECs for trading purposes are recorded in electric utility operating revenues, net of the cost of the RECs, transaction costs, and amounts credited to customers under margin-sharing mechanisms.

Emission Allowances - Emission allowances, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA, are recorded at cost plus associated broker commission fees.  NSP-Minnesota follows the inventory accounting model for all emission allowances.  The sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

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 are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates.  Otherwise, the costs are expensed.  If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded.  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 other participating PRPs exist and acknowledge their potential involvement with a site, 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.

See Note 11 for further discussion of environmental costs.

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

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

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

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

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

Reclassifications – Certain prior year amounts have been reclassified to conform to the current year presentation. Changes in pension and other employee benefit obligations were reclassified as a separate item from changes in other noncurrent liabilities within the consolidated statements of cash flows.  These reclassifications did not have an impact on net cash provided by operating activities.

Subsequent Events - Management has evaluated the impact of events occurring after Dec. 31, 2011 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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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities [Abstract]

Regulatory Assets and Liabilities

13.     Regulatory Assets and Liabilities

NSP-Minnesota's consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1.  Under this guidance, regulatory assets and liabilities are 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 net income or OCI.

The components of regulatory assets and liabilities shown on the consolidated balance sheets of NSP-Minnesota at Dec. 31, 2011 and 2010 are:

	See		Remaining
(Thousands of Dollars)	Note(s)		Amortization Period	Dec. 31, 2011				Dec. 31, 2010
Regulatory Assets				Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)		7	Various	$	20,836	$	312,260	$	43,289	$	198,173
Recoverable deferred taxeson AFUDC recorded in plant (b)		1	Plant lives		-		166,457		-		150,857
Net AROs (d)		1, 11, 12	Plant lives		-		136,941		-		88,804
Contract valuation adjustments (c)		1, 9	Term of related contract		13,498		118,403		-		107,526
Conservation programs (e)		1	One to two years		28,948		45,716		43,497		31,401
Nuclear refueling outage costs		1	One to two years		40,365		8,810		33,819		7,169
Renewable resources and environmental initiatives (b)		11	One to two years		19,922		10,082		25,365		10,268
Purchased power contracts costs		11	Term of related contract		-		30,905		-		25,915
Losses on reacquired debt		4	Term of related debt		1,566		17,411		2,110		18,978
Recoverable purchased natural gas costs		1	One to two years		6,157		9,867		7,475		9,907
Gas pipeline inspection and remediation costs			Pending rate case		-		7,822		-		4,276
State commission adjustments (b)		1	Plant lives		-		4,561		-		5,120
MISO Day 2 costs			One year		3,276		-		3,277		3,277
Nuclear fuel storage		12	One to five years		2,529		721		2,529		3,250
Other			Various		4,612		2,058		3,582		6,470
Total regulatory assets				$	141,709	$	872,014	$	164,943	$	671,391
Regulatory Liabilities
Plant removal costs		1, 11	Plant lives	$	-	$	382,089	$	-	$	400,233
DOE Settlement		12	Less than one year		80,249		-		-		-
Deferred income tax adjustment		1, 6	Various		-		31,518		-		29,814
Conservation programs (e)		1	Less than one year		5,382		-		-		-
Investment tax credit deferrals		1, 6	Various		-		23,802		-		25,438
Contract valuation adjustments (c)		1, 9	Term of related contract		20,976		-		2,393		-
Deferred electric energy costs		1	Less than one year		10,582		-		14,651		-
Renewable resources and environmental initiatives (b)		10, 11	Less than one year		4,358		-		14,752		-
Nuclear refueling outage costs		1	One year		3,441		-		3,441		3,441
Other			Various		7,586		1,620		6,885		3,648
Total regulatory liabilities				$	132,574	$	439,029	$	42,122	$	462,574

(a) Includes $365.2 million and $400.2 million for the regulatory recognition of pension expense at Dec. 31, 2011 and 2010, respectively.  These amounts are offset by $1.8 million of regulatory assets related to the non-qualified pension plan of which $0.2 million is included in the current asset at Dec. 31, 2011 and 2010.

(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 purchase power agreements used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

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

(e) Includes over- or under-recovered costs for conservation programs as well as incentives allowed in certain jurisdictions.

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Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2011

Fair Value of Financial Assets and Liabilities [Abstract]

Fair Value of Financial Assets and Liabilities

9.        Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosuresprovides a single definition of fair value and requires certain 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 is established by this guidance.  The three levels in the hierarchy are as follows:

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

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 and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with discounted cash flow or option pricing models using highly observable inputs.

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 valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents- The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Investments in equity securities and other funds- Equity securities are valued using quoted prices in active markets.  The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value.  The investments in commingled funds and international equity funds may be redeemed for net asset value.  Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion.  Unscheduled distributions from real estate investments may be redeemed with proper notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.  Given the limited observability of inputs to the valuation of the underlying fund investments of the private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

Investments in debt securities-  Debt securities are primarily priced using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, which also require significant, subjective risk-based adjustments to the interest rate used to discount expected future cash flows, which include estimated principal prepayments.  Therefore, fair value measurements for asset-backed and mortgage-backed securities have been assigned a Level 3.

Interest rate derivatives- The fair value of interest rate derivatives are based on broker quotes utilizing current market interest rate forecasts.

Commodity derivatives-  The methods utilized to measure the fair value of commodity derivatives include the use of forward prices and volatilities to value commodity forwards and options.  Levels are assigned to these fair value measurements based on the significance of the use of subjective forward price and volatility forecasts for commodities and delivery locations with limited observability, or the significance of contractual settlements that extend to periods beyond those readily observable on active exchanges or quoted by brokers.  Electric commodity derivatives include FTRs, for which fair value is determined using complex predictive models and inputs including forward commodity prices as well as subjective forecasts of retail and wholesale demand, generation and resulting transmission system congestion.  Given the limited observability of management's forecasts for several of these inputs, fair value measurements for FTRs have been assigned a Level 3.

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.

Non-Derivative Instruments Fair Value Measurements

The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants.  Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning the Monticello and Prairie Island nuclear generating plants.  The fund contains cash equivalents, debt securities, equity securities, and other investments - all classified as available-for-sale.  NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs.  Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs.  Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $79.8 million and $82.5 million at Dec. 31, 2011 and 2010, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $87.5 million and $65.2 million at Dec. 31, 2011 and 2010, respectively.

The following tables present the cost and fair value of NSP-Minnesota's non-derivative instruments with recurring fair value measurements, in the nuclear decommissioning fund, at Dec. 31, 2011 and 2010:

	Dec. 31, 2011
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	26,123	$	7,103	$	19,020	$	-	$	26,123
Commingled funds		320,798		-		311,105		-		311,105
International equity funds		63,781		-		58,508		-		58,508
Private equity investments		9,203		-		-		9,203		9,203
Real estate		24,768		-		-		26,395		26,395
Debt securities:
Government securities		116,490		-		117,256		-		117,256
US corporate bonds		187,083		-		193,516		-		193,516
International corporate bonds		35,198		-		35,804		-		35,804
Municipal bonds		60,469		-		64,731		-		64,731
Asset-backed securities		16,516		-		-		16,501		16,501
Mortgage-backed securities		75,627		-		-		78,664		78,664
Equity securities:
Common stock		408,122		398,625		-		-		398,625
Total	$	1,344,178	$	405,728	$	799,940	$	130,763	$	1,336,431

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $21.1 million of miscellaneous investments.

	Dec. 31, 2010
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	83,837	$	76,281	$	7,556	$	-	$	83,837
Commingled funds		131,000		-		133,080		-		133,080
International equity funds		54,561		-		58,584		-		58,584
Debt securities:
Government securities		146,473		-		146,654		-		146,654
US corporate bonds		279,028		-		288,304		-		288,304
International corporate bonds		1,233		-		1,581		-		1,581
Municipal bonds		100,277		-		97,557		-		97,557
Asset-backed securities		32,558		-		-		33,174		33,174
Mortgage-backed securities		68,072		-		-		72,589		72,589
Equity securities:
Common stock		436,334		435,270		-		-		435,270
Total	$	1,333,373	$	511,551	$	733,316	$	105,763	$	1,350,630

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $15.4 million of miscellaneousinvestments.

The following tables present the changes in Level 3 nuclear decommissioning fund investments:

(Thousands of Dollars)	Jan. 1, 2011		Purchases		Settlements			Gains (Losses)  Recognized as  Regulatory Assets  and Liabilities			Dec. 31, 2011
Asset-backed securities	$	33,174	$	16,518	$	(32,560	)	$	(631	)	$	16,501
Mortgage-backed securities		72,589		168,688		(161,134	)		(1,479	)		78,664
Real estate		-		24,768		-			1,627			26,395
Private equity investments		-		9,203		-			-			9,203
Total	$	105,763	$	219,177	$	(193,694	)	$	(483	)	$	130,763

(Thousands of Dollars)	Jan. 1, 2010		Purchases		Settlements			Gains Recognized as Regulatory Assets  and Liabilities		Dec. 31, 2010
Asset-backed securities	$	11,918	$	38,871	$	(17,878	)	$	263	$	33,174
Mortgage-backed securities		81,189		63,497		(75,701	)		3,604		72,589
Total	$	93,107	$	102,368	$	(93,579	)	$	3,867	$	105,763

(Thousands of Dollars)	Jan. 1, 2009		Purchases		Settlements			Gains Recognized as  Regulatory Assets  and Liabilities		Dec. 31, 2009
Asset-backed securities	$	10,962	$	7,271	$	(7,755	)	$	1,440	$	11,918
Mortgage-backed securities		98,461		17,943		(45,815	)		10,600		81,189
Total	$	109,423	$	25,214	$	(53,570	)	$	12,040	$	93,107

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at Dec. 31, 2011:

	Final Contractual Maturity
(Thousands of Dollars)	Due in 1 Year  or Less		Due in 1 to 5  Years		Due in 5 to 10  Years		Due after 10  Years		Total
Government securities	$	113,179	$	-	$	4,077	$	-	$	117,256
US corporate bonds		304		35,437		139,880		17,895		193,516
International corporate bonds		-		8,454		23,501		3,849		35,804
Municipal bonds		-		-		40,585		24,146		64,731
Asset-backed securities		-		9,907		6,594		-		16,501
Mortgage-backed securities		-		1,731		1,041		75,892		78,664
Debt securities	$	113,483	$	55,529	$	215,678	$	121,782	$	506,472

Derivative Instruments Fair Value Measurements

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.

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 an anticipated debt issuance for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Dec. 31, 2011, accumulated OCI related to interest rate derivatives included $0.1 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

At Dec. 31, 2011, NSP-Minnesota had unsettled interest rate swaps outstanding with a total notional amount of $225 million.  These interest rate swaps were designated as hedges, and as such, changes in fair value are recorded to OCI.

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 this policy.

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, 2011, NSP-Minnesota had various vehicle fuel related contracts designated as cash flow hedges extending through December 2014.  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 OCI 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 years ended Dec. 31, 2011 and 2010.

At Dec. 31, 2011, accumulated OCI related to commodity derivative cash flow hedges included $0.1 million of net gains 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 electric operating revenue, net of amounts credited to customers under margin-sharing mechanisms.

The following table details the gross notional amounts of commodity forwards, options, and FTRs at Dec. 31, 2011 and 2010:

(Amounts in Thousands) (a)(b)	Dec. 31, 2011		Dec. 31, 2010
MWh of electricity		37,522		44,376
MMBtu of natural gas		7,290		14,100
Gallons of vehicle fuel		330		440

(a) Amounts are not reflective of net positions in the underlying commodities.

(b) Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.

Financial Impact of Qualifying Cash Flow Hedges - The impact of qualifying interest rate and vehicle fuel cash flow hedges on NSP-Minnesota's accumulated OCI, included in the consolidated statements of common stockholder's equity and comprehensive income, is detailed in the following table:

(Thousands of Dollars)	2011			2010			2009
Accumulated other comprehensive income related to cash flow hedges at Jan. 1	$	4,977		$	3,941		$	3,053
After-tax net unrealized losses related to derivatives accounted for as hedges		(16,578	)		(80	)		(1,219	)
After-tax net realized (gains) losses on derivative transactions reclassified into earnings		(128	)		1,116			2,107
Accumulated other comprehensive (loss) income related to cash flow hedges at Dec. 31	$	(11,729	)	$	4,977		$	3,941

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2011 and 2010.

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2011 and 2010, on OCI, regulatory assets and liabilities, and income:

	Dec. 31, 2011
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into
	During the Period in:						Income During the Period from:
	Accumulated						Accumulated								Pre-Tax Gains
	Other			Regulatory			Other				Regulatory				Recognized
	Comprehensive			(Assets) and			Comprehensive				Assets and				During the Period
(Thousands of Dollars)	Loss			Liabilities			Loss				(Liabilities)				in Income
Derivatives designated as cash flow hedges
Interest rate	$	(28,119	)	$	-		$	(109	)	(a)	$	-			$	-
Vehicle fuel and other commodity		119			-			(113	)	(e)		-				-
Total	$	(28,000	)	$	-		$	(222	)		$	-			$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-			$	-			$	6,330	(b)
Electric commodity		-			49,818			-				(40,492	)	(c)		-
Natural gas commodity		-			(22,581	)		-				18,021		(d)		-
Total	$	-		$	27,237		$	-			$	(22,471	)		$	6,330

	Dec. 31, 2010
	Fair Value Changes Recognized						Pre-Tax Amounts Reclassified into
	During the Period in:						Income During the Period from:
	Accumulated						Accumulated								Pre-Tax Gains
	Other			Regulatory			Other				Regulatory				Recognized
	Comprehensive			(Assets) and			Comprehensive				Assets and				During the Period
(Thousands of Dollars)	Income			Liabilities			Income				(Liabilities)				in Income
Derivatives designated as cash flow hedges
Interest rate	$	-		$	-		$	(108	)	(a)	$	-			$	-
Vehicle fuel and other commodity		(137	)		-			1,998		(e)		-				-
Total	$	(137	)	$	-		$	1,890			$	-			$	-
Other derivative instruments
Trading commodity	$	-		$	-		$	-			$	-			$	12,061	(b)
Electric commodity		-			3,969			-				(21,840	)	(c)		-
Natural gas commodity		-			(18,655	)		-				9,111		(d)		-
Total	$	-		$	(14,686	)	$	-			$	(12,729	)		$	12,061

(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 derivatives 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 O&M expenses.

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 ratings. If the credit ratings for NSP-Minnesota were downgraded below investment grade, contracts underlying $1.4 million of derivative liabilities in a gross liability position at Dec. 31, 2011 would have required NSP-Minnesota to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $0.1 million.  If the credit ratings for NSP-Minnesota were downgraded below investment grade, no contracts underlying NSP-Minnesota's derivative liabilities at Dec. 31, 2010 would have required the posting of collateral or contract settlement.

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, 2011 and 2010, NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts.

Recurring Fair Value Measurements- The following table presents, for each of the hierarchy levels, NSP-Minnesota's derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2011:

	Dec. 31, 2011
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	93	$	-	$	93	$	-		$	93
Other derivative instruments:
Trading commodity		-		26,133		-		26,133		(9,679	)		16,454
Electric commodity		-		-		13,333		13,333		(1,471	)		11,862
Total current derivative assets	$	-	$	26,226	$	13,333	$	39,559	$	(11,150	)		28,409
Purchased power agreements (a)													23,108
Current derivative instruments												$	51,517
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	59	$	-	$	59	$	(59	)	$	-
Other derivative instruments:
Trading commodity		-		28,307		-		28,307		(2,234	)		26,073
Total noncurrent derivative assets	$	-	$	28,366	$	-	$	28,366	$	(2,293	)		26,073
Purchased power agreements (a)													54,616
Noncurrent derivative instruments												$	80,689
Current derivative liabilities
Derivatives designated as cash flow hedges:
Interest rate	$	-	$	28,119	$	-	$	28,119	$	-		$	28,119
Other derivative instruments:
Trading commodity		-		21,816		-		21,816		(11,647	)		10,169
Electric commodity		-		698		916		1,614		(1,471	)		143
Natural gas commodity		-		13,499		-		13,499		-			13,499
Total current derivative liabilities	$	-	$	64,132	$	916	$	65,048	$	(13,118	)		51,930
Purchased power agreements (a)													13,851
Current derivative instruments												$	65,781
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,464	$	-	$	13,464	$	(2,293	)	$	11,171
Total noncurrent derivative liabilities	$	-	$	13,464	$	-	$	13,464	$	(2,293	)		11,171
Purchased power agreements (a)													173,019
Noncurrent derivative instruments												$	184,190

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, 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.

(b) The accounting guidance for 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 NSP-Minnesota 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 tables present, for each of the hierarchy levels, NSP-Minnesota's derivative assets and liabilities that are measured at fair value on a recurring basis at Dec. 31, 2010:

	Dec. 31, 2010
	Fair Value
							Fair Value		Counterparty
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total		Netting (b)			Total
Current derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	70	$	-	$	70	$	-		$	70
Other derivative instruments:
Trading commodity		487		31,253		-		31,740		(18,719	)		13,021
Electric commodity		-		-		3,619		3,619		(1,226	)		2,393
Natural gas commodity		-		187		-		187		(187	)		-
Total current derivative assets	$	487	$	31,510	$	3,619	$	35,616	$	(20,132	)		15,484
Purchased power agreements (a)													24,408
Current derivative instruments												$	39,892
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	83	$	-	$	83	$	-		$	83
Other derivative instruments:
Trading commodity		-		25,850		-		25,850		(2,477	)		23,373
Natural gas commodity		-		125		-		125		(48	)		77
Total noncurrent derivative assets	$	-	$	26,058	$	-	$	26,058	$	(2,525	)		23,533
Purchased power agreements (a)													77,725
Noncurrent derivative instruments												$	101,258

Current derivative liabilities
Other derivative instruments:
Trading commodity	$	392	$	25,416	$	-	$	25,808	$	(21,337	)	$	4,471
Electric commodity		-		-		1,227		1,227		(1,227	)		-
Natural gas commodity		20		9,156		-		9,176		(187	)		8,989
Total current derivative liabilities	$	412	$	34,572	$	1,227	$	36,211	$	(22,751	)		13,460
Purchased power agreements (a)													13,851
Current derivative instruments												$	27,311
Noncurrent derivative liabilities
Other derivative instruments:
Trading commodity	$	-	$	13,351	$	-	$	13,351	$	(2,478	)	$	10,873
Natural gas commodity		-		75		-		75		(48	)		27
Total noncurrent derivative liabilities	$	-	$	13,426	$	-	$	13,426	$	(2,526	)		10,900
Purchased power agreements (a)													186,871
Noncurrent derivative instruments												$	197,771

(a) In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, 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.

(b) The accounting guidance for derivatives and hedgingpermits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota 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 presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2011, 2010 and 2009:

	Year Ended Dec. 31
(Thousands of Dollars)	2011			2010			2009
Balance at Jan. 1	$	2,392		$	27,237		$	23,247
Purchases		33,609			10,948			9,077
Settlements		(36,552	)		(24,960	)		(14,648	)
Transfers out of Level 3		-			(11,638	)		700
Net transactions recorded during the period:
Gains recognized in earnings (a)		66			4,719			5,693
Gains (losses) recognized as regulatory assets and liabilities		12,902			(3,914	)		3,168
Balance at Dec. 31	$	12,417		$	2,392		$	27,237

(a) These amounts relate to commodity derivatives held at the end of the period.

NSP-Minnesota recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for the year ended Dec. 31, 2011.  The following table presents the transfers that occurred from Level 3 to Level 2 during the year ended Dec. 31, 2010:

	Year Ended
(Thousands of Dollars)	Dec. 31, 2010
Trading commodity derivatives not designated as cash flow hedges:
Current assets	$	5,384
Noncurrent assets		21,450
Current liabilities		(2,851	)
Noncurrent liabilities		(12,345	)
Total	$	11,638

There were no transfers of amounts from Level 2 to Level 3, or any transfers to or from Level 1 for the year ended Dec. 31, 2010.  The transfer of amounts from Level 3 to Level 2 in the year ended Dec. 31, 2010 was due to the valuation of certain long-term derivative contracts for which observable commodity pricing forecasts became a more significant input during the period.

Fair Value of Long-Term Debt

As of Dec. 31, 2011 and 2010, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2011				2010
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,338,897	$	4,066,367	$	3,337,912	$	3,673,214

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, 2011 and 2010.  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.

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Joint Ownership of Generation and Transmission Facilities

12 Months Ended

Dec. 31, 2011

Joint Ownership of Generation and Transmission Facilities [Abstract]

Joint Ownership of Generation and Transmission Facilities

5.        Joint Ownership of Generation and Transmission Facilities

Following are the investments by NSP-Minnesota in jointly owned generation and transmission facilities and the related ownership percentages as of Dec. 31, 2011:

					Construction
	Plant in		Accumulated		Work in
(Thousands of Dollars)	Service		Depreciation		Progress		Ownership %
Electric Generation:
Sherco Unit 3	$	565,832	$	358,907	$	3,731		59.0	%
Sherco Common Facilities Units 1, 2 and 3		138,790		82,229		531		80.0
Sherco Substation		4,790		2,621		-		59.0
Electric Transmission:
Grand Meadow Line and Substation		11,204		855		-		50.0
CapX2020		57,856		8,899		74,404		49.6
Total	$	778,472	$	453,511	$	78,666

NSP-Minnesota has approximately 500 MW of jointly owned generating capacity. 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 providing its own financing.

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.  In November 2011, Sherco Unit 3 experienced a significant failure of its turbine, generator, and exciter systems.  The facility was immediately shut down and isolated for investigation of the cause of the failure, which is still uncertain.  It is unknown when Sherco Unit 3 will recommence operations.  NSP-Minnesota maintains insurance policies for the entire unit, inclusive of the other joint owner's proportionate share.  Replacement and repair of damaged systems, and other significant costs of the failure in excess of a $1.5 million deductible are expected to be recovered through these insurance policies.  For its proportionate share of possible expenditures in excess of insurance recoveries for components of the jointly owned facility, NSP-Minnesota will recognize additions to property, plant and equipment and O&M.  Sherco Units 1 and 2, wholly owned by NSP-Minnesota, continue to operate.

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Selected Balance Sheet Data

12 Months Ended

Dec. 31, 2011

Selected Balance Sheet Data [Abstract]

Selected Balance Sheet Data

3.        Selected Balance Sheet Data

	Dec. 31
(Thousands of Dollars)	2011			2010
Accounts receivable, net
Accounts receivable	$	337,581		$	334,481
Less allowance for bad debts		(23,004	)		(20,996	)
	$	314,577		$	313,485
Inventories
Materials and supplies	$	124,961		$	122,706
Fuel		113,711			95,804
Natural gas		63,176			61,663
	$	301,848		$	280,173
Property, plant and equipment, net
Electric plant	$	11,948,041		$	10,563,424
Natural gas plant		1,006,163			979,256
Common and other property		525,139			510,577
Construction work in progress		639,246			695,292
Total property, plant and equipment		14,118,589			12,748,549
Less accumulated depreciation		(5,433,106	)		(5,222,980	)
Nuclear fuel		1,939,299			1,837,697
Less accumulated amortization		(1,641,948	)		(1,541,046	)
	$	8,982,834		$	7,822,220

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Borrowings and Other Financing Instruments

12 Months Ended

Dec. 31, 2011

Borrowings and Other Financing Instruments [Abstract]

Borrowings and Other Financing Instruments

4.       Borrowings and Other Financing Instruments

Short-Term Borrowings

Commercial Paper - NSP-Minnesota meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.  Commercial paper outstanding for NSP-Minnesota was as follows:

	Three Months Ended
(Amounts in Millions, Except Interest Rates)	Dec. 31, 2011
Borrowing limit	$	500
Amount outstanding at period end		26
Average amount outstanding		1
Maximum amount outstanding		27
Weighted average interest rate, computed on a daily basis		0.43	%
Weighted average interest rate at end of period		0.45
	Twelve Months Ended			Twelve Months Ended			Twelve Months Ended
(Amounts in Millions, Except Interest Rates)	Dec. 31, 2011			Dec. 31, 2010			Dec. 31, 2009
Borrowing limit	$	500		$	482		$	482
Amount outstanding at period end		26			-			-
Average amount outstanding		7			35			59
Maximum amount outstanding		80			389			266
Weighted average interest rate, computed on a daily basis		0.34	%		0.37	%		0.73	%
Weighted average interest rate at end of period		0.45			N/A			N/A

Credit Facilities - In order to use its commercial paper program to fulfill short-term funding needs, NSP-Minnesota must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under the credit agreement.

During 2011, NSP-Minnesota executed a new four-year credit agreement.  The total size of the credit facility is $500 million and terminates in March 2015. NSP-Minnesota has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

The credit facility provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.  Other features of NSP-Minnesota's credit facility include:

· The credit facility may be increased by up to $100 million.

· The credit facility has a 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 at Dec. 31, 2011.  If NSP-Minnesota does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

· The credit facility has a cross-default provision that provides NSP-Minnesota will be in default on its borrowings under the facility if NSP-Minnesota or any of its subsidiaries whose total assets exceed 15 percent of NSP-Minnesota's consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

· The interest rates under the line of credit are based on the Eurodollar rate or an alternate base rate, plus a borrowing margin of 0 to 200 basis points per year based on the applicable credit ratings.

· The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the line of credit at a range of 10 to 35 basis points per year.

· NSP-Wisconsin's intercompany borrowing arrangement with NSP-Minnesota was subsequently terminated.

At Dec. 31, 2011, NSP-Minnesota had the following committed credit facility available (in millions):

Credit Facility		Drawn (a)		Available
$	500.0	$	33.7	$	466.3

(a) Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Minnesota had no direct advances on the credit facility outstanding at Dec. 31, 2011 and 2010.

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, 2011 and 2010, there were $7.7 million and $5.3 million of letters of credit outstanding, respectively, under the credit facility.  An additional $1.1 million of letters of credit not issued under the credit facility were outstanding at Dec. 31, 2011 and 2010, respectively.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

Money Pool - Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries.  Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.  Money pool borrowings outstanding for NSP-Minnesota were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended  Dec. 31, 2011
Borrowing limit	$	250
Amount outstandingat period end		65
Average amount outstanding		55
Maximum amount outstanding		80
Weighted average interest rate, computed on a daily basis		0.34	%
Weighted average interest rate at end of period		0.35

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended  Dec. 31, 2011			Twelve Months Ended Dec. 31, 2010			Twelve Months Ended Dec. 31, 2009
Borrowing limit	$	250		$	250		$	250
Amount outstandingat period end		65			-			7
Average amount outstanding		17			18			37
Maximum amount outstanding		80			142			132
Weighted average interest rate, computed on a daily basis		0.34	%		0.37	%		0.67	%
Weighted average interest rate at end of period		0.35			N/A			0.36

Long-Term Borrowings and Other Financing Instruments

Generally, all real and personal property of NSP-Minnesota is subject to the lien of its first mortgage indenture.  Additionally, 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.

In August 2010, NSP-Minnesota issued $250 million of 1.95 percent first mortgage bonds, due Aug. 15, 2015 and $250 million of 4.85 percent first mortgage bonds, due Aug. 15, 2040.

During the next five years, NSP-Minnesota has long-term debt maturities of $450 million and $250 million due in 2012 and 2015, respectively.  NSP-Minnesota plans to refinance the current portion of long-term debt coming due in 2012.

Deferred Financing Costs- Other assets included deferred financing costs of approximately $25.2 million and $27.2 million, net of amortization, at Dec. 31, 2011 and 2010, respectively.  NSP-Minnesota is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend and Other Capital-Restrictions - NSP-Minnesota's 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. 

NSP-Minnesota's first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy Inc., the holder of its common stock.  Even with these restrictions, NSP-Minnesota could have paid more than $1.1 billion in additional cash dividends on common stock at Dec. 31, 2010, or $1.2 billion at Dec. 31, 2011.

NSP-Minnesota's state regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy Inc. by requiring an equity-to-total capitalization ratio between 47.07 percent and 57.53 percent.  NSP-Minnesota's equity-to-total capitalization ratio was 52.1 percent at Dec. 31, 2011.  Total capitalization for NSP-Minnesota cannot exceed $8.25 billion.

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

6.        Income Taxes

Medicare Part D Subsidy Reimbursements - In March 2010, the Patient Protection and Affordable Care Act was signed into law.  The law includes provisions to generate tax revenue to help offset the cost of the new legislation.  One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013.  Based on this provision, NSP-Minnesota became subject to additional taxes and was required to reverse previously recorded tax benefits in the period of enactment. NSP-Minnesota expensed approximately $3.3 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010.  NSP-Minnesota does not expect the $3.3 million of additional tax expense to recur in future periods. 

Federal Audit - NSP-Minnesota is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy's 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy's 2008 federal income tax return expires in September 2012.  The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010.  In December 2011, Xcel Energy finalized the Revenue Agent Report and signed the Waiver of Assessment for tax years 2008 and 2009.  The total assessment for these tax years was $1.4 million, including tax and interest.

State Audits - NSP-Minnesotais a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Dec. 31, 2011, NSP-Minnesota's earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2007.  As of Dec. 31, 2011, there were no state income tax audits in progress. 

Unrecognized Tax Benefits -The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR.  In addition, the unrecognized tax benefit balance includes temporary tax positions 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 ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	Dec. 31, 2011		Dec. 31, 2010
Unrecognized tax benefit - Permanent tax positions	$	3.3	$	4.0
Unrecognized tax benefit - Temporary tax positions		13.4		18.5
Unrecognized tax benefit balance	$	16.7	$	22.5

A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2011			2010			2009
Balance at Jan. 1	$	22.5		$	12.5		$	20.2
Additions based on tax positions related to the current year		6.5			7.3			6.9
Reductions based on tax positions related to the current year		(0.8	)		(0.3	)		(1.4	)
Additions for tax positions of prior years		4.9			3.5			3.6
Reductions for tax positions of prior years		(0.9	)		(0.5	)		(1.5	)
Settlements with taxing authorities		(15.5	)		-			(15.3	)
Balance at Dec. 31	$	16.7		$	22.5		$	12.5

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryfowards are as follows:

(Millions of Dollars)	Dec. 31, 2011			Dec. 31, 2010
NOL and tax credit carryforwards	$	(18.1	)	$	(11.0	)

The decrease in the unrecognized tax benefit balance of $5.8 million in 2011 was due to the resolution of certain federal audit matters, partially offset by an increase due to the addition of uncertain tax positions related to current and prior years' activity.  NSP-Minnesota's amount of unrecognized tax benefits could change in the next 12 months as 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.  However, NSP-Minnesota does not anticipate total unrecognized tax benefits will significantly change within the next 12 months.

The payable for interest related to unrecognized tax benefits is offset by the interest benefit associated with NOL and tax credit carryforwards.  A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2011			2010			2009
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.9	)	$	(0.3	)	$	(1.3	)
Interest income (expense) related to unrecognized tax benefits		1.1			(0.6	)		1.0
Receivable (payable) for interest related to unrecognized tax benefits at Dec. 31	$	0.2		$	(0.9	)	$	(0.3	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2011, 2010 or 2009. 

Other Income Tax Matters -NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset.  NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2011		2010
Federal NOL carryforward	$	564.7	$	407.7
Federal tax credit carryforwards		60.5		35.6
State tax credit carryforwards, net of federal detriment		1.9		1.8

The federal carryforward periods expire between 2021 and 2031.  The state carryforward periods expire between 2017 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:

	2011			2010			2009
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit		7.2			9.2			6.2
Previously recognized Medicare Part D subsidies		0.1			0.7			-
Tax credits recognized, net of federal income tax expense		(5.0	)		(3.1	)		(2.7	)
Regulatory differences - utility plant items		(1.8	)		(2.0	)		(1.6	)
Life insurance policies		(0.2	)		(0.2	)		(0.3	)
Change in unrecognized tax benefits		(0.1	)		0.3			(1.0	)
Resolution of income tax audits and other		-			(0.2	)		1.4
Other, net		-			0.1			0.3
Effective income tax rate		35.2	%		39.8	%		37.3	%

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2011			2010			2009
Current federal tax expense (benefit)	$	8,059		$	(87,554	)	$	(12,136	)
Current state tax expense		3,055			18,789			19,195
Current change in unrecognized tax (benefit) expense		(12,891	)		1,850			(6,165	)
Current tax credits		-			(944	)		-
Deferred federal tax expense		152,806			215,892			154,858
Deferred state tax expense		55,658			47,092			30,364
Deferred change in unrecognized tax expense (benefit)		12,256			(577	)		1,667
Deferred tax credits		(24,600	)		(10,660	)		(9,542	)
Deferred investment tax credits		(2,694	)		(2,697	)		(3,120	)
Total income tax expense	$	191,649		$	181,191		$	175,121

The components of deferred income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2011			2010			2009
Deferred tax expense excluding items below	$	190,470		$	295,994		$	228,821
Tax benefit (expense) allocated to other comprehensive income and other		11,841			(776	)		(1,042	)
Amortization and adjustments to deferred income taxes onincome tax regulatory assets and liabilities		(6,191	)		(43,471	)		(50,432	)
Deferred tax expense	$	196,120		$	251,747		$	177,347

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

(Thousands of Dollars)	2011		2010
Deferred tax liabilities:
Difference between book and tax bases of property	$	1,892,655	$	1,635,323
Regulatory assets		121,300		116,787
Other		17,319		19,768
Total deferred tax liabilities	$	2,031,274	$	1,771,878
Deferred tax assets:
NOL carryforward	$	196,074	$	145,119
Tax credit carryforward		62,463		37,403
Rate refund		29,499		2,290
Employee benefits		18,280		56,068
Deferred investment tax credits		14,096		15,043
Regulatory liabilities		12,732		17,863
Bad debts		9,381		8,580
Other		11,512		2,745
Total deferred tax assets	$	354,037	$	285,111
Net deferred tax liability	$	1,677,237	$	1,486,767

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Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2011

Commitments and Contingent Liabilities [Abstract]

Commitments and Contingent Liabilities

11.     Commitments and Contingent Liabilities

Commitments

Capital Commitments - NSP-Minnesota has made commitments in connection with a portion of its projected capital expenditures.  NSP-Minnesota's capital commitments primarily relate to the following major projects:

Nuclear Lifecycle Management and  Extended Power Uprates - NSP-Minnesota is pursuing improvements to make sure the plants operate safely until the end of their extended licensed life and is making capacity increases of the Monticello and Prairie Island generating plants that could total up to approximately 188 MW.  The MPUC approved the CON for the extended power uprate for Monticello in 2008.  The license amendment application was filed with the NRC in November 2008, but a concern was raised by the Advisory Committee on Reactor Safeguards related to containment pressure associated with pump performance.  In October 2011, the Advisory Committee recommended that all licensing actions that credit the use of containment accident pressure be suspended until the causes and risks of Japan's Fukushima incident are better understood.  NSP-Minnesota has rescheduled the remaining equipment changes needed to complete the Monticello power uprate projects during the planned spring 2013 refueling outage. 

The MPUC approved an extended power uprate for the Prairie Island Units in 2009.  Analysis of recent extended power uprate submittals to the NRC concluded that significant additional design work beyond current schedule and cost plan estimates are now being required to submit a successful application.  As a result, NSP-Minnesota is completing an economic and new project design analysis to determine project impacts and anticipates submitting a Change in Circumstances filing with the MPUC in the first quarter of 2012.

CapX2020 - CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy that have proposed several groups of transmission projects to be complete by 2020.  Group 1 project investments consist of four transmission lines.  Major construction began in 2010 on the Group 1 transmission lines with an expected completion date in 2015.  NSP System's investment depends on the routes and configurations approved by affected state commissions.  The remainder of the costs will be born by other utilities in the upper Midwest.

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 2012 and 2028.  In addition, NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.  NSP-Minnesota's 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 to customers.

The estimated minimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2011, are as follows:

(Millions of Dollars)	Dec. 31, 2011
Coal (a)	$	1,548
Nuclear fuel (a)		1,546
Natural gas supply		23
Natural gas storage and transportation (a)		833

(a) Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Estimated coal requirements at Dec. 31, 2011 have been adjusted to account for Sherco Unit 3, which was shut down in November 2011 after experiencing a significant failure of its turbine, generator and exciter systems.  It is uncertain when Sherco Unit 3 will recommence operations.  See Note 5 for further discussion.

Purchased Power Agreements - NSP-Minnesota has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

NSP-Minnesota has various pay-for-performance contracts with expiration dates through 2033.  In general, these contracts provide for energy payments based on actual power taken under the contracts, as well as capacity payments.  Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for purchased power agreements were payments for capacity of $106.8 million, $109.3 million and $109.3 million in 2011, 2010 and 2009, respectively.  At Dec. 31, 2011, the estimated future payments for capacity that NSP-Minnesota is obligated to purchase, subject to availability, are as follows:

(Millions of Dollars)
2012	$	106.1
2013		108.4
2014		110.7
2015		83.4
2016		57.4
Thereafter		171.8
Total (a)	$	637.8

(a) Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Variable Interest Entities- The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity's financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity's primary beneficiary.

Purchased Power Agreements - Under certain purchased power agreements, NSP-Minnesota purchases power from independent power producing entities that own natural gas or biomass fueled power plants for which NSP-Minnesota is required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which NSP-Minnesota procures the natural gas required to produce the energy that it purchases.  These specific purchased power agreements create a variable interest in the associated independent power producing entity.

NSP-Minnesota has determined that certain independent power producing entities are variable interest entities.  NSP-Minnesota is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in the purchased power agreements.

NSP-Minnesota has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities.  NSP-Minnesota has concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities' economic performance.  NSP-Minnesota had approximately 1,064 MW of capacity under long-term purchased power agreements as of Dec. 31, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities.  These agreements have expiration dates through the year 2028.

Leases- NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business.  These leases, primarily for office space, railcars, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases.  Total expenses under operating lease obligations were approximately $72.9 million, $73.0 million and $76.2 million for 2011, 2010 and 2009, respectively.  These expenses include payments for capacity recorded to electric fuel and purchased power expenses for purchase power agreements accounted for as operating leases of $58.2 million, $57.1 million and $56.2 million in 2011, 2010 and 2009, respectively.

Included in the future commitments under operating leases are estimated future payments under purchased power agreements that have been accounted for as operating leases in accordance with the applicable accounting guidance.  Future commitments under operating leases are:

	Other		Purchased		Total
	Operating		Power Agreement		Operating
(Millions of Dollars)	Leases		Operating Leases(a) (b)		Leases
2012	$	8.2	$	55.0	$	63.2
2013		7.0		55.9		62.9
2014		6.2		56.8		63.0
2015		5.3		57.8		63.1
2016		3.6		58.7		62.3
Thereafter		19.9		557.6		577.5

(a) Amounts do not include purchased power agreements accounted for as other commitments, which are recorded to O&M as executed.

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

Guarantees and Indemnifications

In connection with the acquisition of the 201 MW Nobles wind project, NSP-Minnesota agreed to indemnify the seller for losses arising out of a breach of certain representations and warranties.  NSP-Minnesota's indemnification obligation is capped at $20 million, in the aggregate.  The indemnification obligation expires in March 2013.  NSP-Minnesota has not recorded a liability related to this indemnity and it has no assets held as collateral related to this agreement at Dec. 31, 2011.

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 regulated rate process.  New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the regulated rate 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- The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and other comparable federal and state environmental laws impose liability, without regard to the legality of the original conduct, on certain classes of persons where hazardous substances or other regulated materials have been released to the environment.  NSP-Minnesota may sometimes 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 MGPs operated by NSP-Minnesota, its predecessors, or other entities; and third-party sites, such as landfills, for which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes to that site. 

MGP Sites- NSP-Minnesota is currently involved in investigating and/or remediating several MGP sites where hazardous or other regulated materials may have been deposited.  NSP-Minnesota has identified 3 sites, where former MGP activities have or may have resulted in actual site contamination and are under current investigation and/or remediation.  At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any ultimate remediation that may be conducted.  NSP-Minnesota anticipates that the majority of the remediation at these sites will continue through at least 2014.  For these sites, NSP-Minnesota had accrued $0.1 million and $0.3 million at Dec. 31, 2011 and Dec. 31, 2010, respectively.  There may be insurance recovery and/or recovery from other PRPs that will offset any costs actually incurred at these sites.  NSP-Minnesota anticipates that any amounts actually spent will be fully recovered from customers.

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 not expected to be material 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 Regulation - In December 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare.  In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold.   NSP-Minnesota is unable to determine what the cost of compliance with these new EPA requirements will be as it is not clear whether these requirements will apply to futures changes at NSP-Minnesota's power plants.

GHG New Source Performance Standard Proposal - The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the CAA.  The EPA had planned to release its proposal in September 2011, but has delayed it without establishing a new proposal date.

CSAPR- In July 2011, the EPA issued its CSAPR to address long range transport of particulate matter and ozone by requiring reductions in SO2 and NOx from utilities located in the eastern half of the U.S., including Minnesota.  The CSAPR sets more stringent requirements than the proposed CATR.  The rule also creates an emissions trading program.  NSP-Minnesota intends to comply by reducing emissions and/or purchasing allowances. 

On Dec. 30, 2011, the U.S. Court of Appeals for the D.C. Circuit issued a stay of the CSAPR, pending completion of judicial review.  The Court is expected to hear the case in April 2012.  NSP-Minnesota anticipates that the court may rule on the challenges to the CSAPR in the second half of 2012.  It is not known at this time whether the CSAPR will be upheld, reversed or will require modifications pursuant to a future Court decision.

If the CSAPR is upheld and unmodified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at NSP-Minnesota's Sherco plant, which is estimated to cost a total of $10 million through 2014, and system operating changes to the Black Dog and the Sherco plants.  If available, NSP-Minnesota would also consider allowance purchases.  In addition, NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit seeking the allocation of additional emission allowances to NSP-Minnesota.  NSP-Minnesota contends that the EPA's method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas.  If successful, additional allowances would reduce NSP-Minnesota's costs to comply with the reductions that may be imposed by the CSAPR.

CAIR - In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions.  The CAIR does not currently apply in Minnesota because the Court specifically found that the EPA had not adequately justified the application of the CAIR to Minnesota.  In granting the stay of the CSAPR, the Court specifically noted that the CAIR would remain in place during its pending review of the CSAPR.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule - In December 2011, the EPA issued the final EGU MATS rule to replace the proposed EGU MACT rule.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and will require coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years.  NSP-Minnesota believes these costs would be recoverable through regulatory mechanisms and it does not expect a material impact on its results of operations, financial position or cash flows.

Minnesota Mercury Legislation - Under the 2006 mercury legislation, NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King generating plants, with project costs collected through the MCR rider in 2010.  Subsequently, in the 2010 Minnesota electric rate case, the costs of these projects were moved into base rates as part of the interim rates effective Jan. 2, 2011.  NSP-Minnesota has also obtained MPUC approval to install mercury controls on Sherco Units 1 and 2 by the end of 2014.

For Sherco Units 1 and 2, NSP-Minnesota has incurred $1.5 million in study costs to date and spent $0.6 million through Dec. 31, 2011 for testing and studying of technologies.  At Dec. 31, 2011, the estimated annual testing and study cost is $0.5 million.  NSP-Minnesota projects installation costs of $12.0 million for the mercury controls on the units and O&M expense of $10.0 million per year beginning in 2014.  NSP-Minnesota believes these costs would be recoverable through regulatory mechanisms.

Regional Haze Rules - In December 2009, the MPCA Citizens Board approved the Regional Haze SIP, which has been submitted to the EPA for approval.  The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks.  The MPCA concluded selective catalytic reductions (SCR) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA's BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2.  The combustion controls have been installed on Sherco Units 1 and 2, and the scrubber upgrades are scheduled to be installed by 2015.  At this time, the estimated cost for meeting the BART and other CAA requirements is approximately $50 million of which $20 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2.  NSP-Minnesota anticipates that all costs associated with BART compliance will be fully recoverable.

In June 2011, the EPA provided comments to the MPCA on the SIP, stating the EPA's preliminary review indicates that SCR controls should be added to Sherco Units 1 and 2.  The MPCA has since proposed that the CSAPR should be considered BART for EGUs and the EPA has proposed that states be allowed to find that CSAPR compliance meets BART requirements for EGUs, and specifically that Minnesota's proposal to find the CSAPR to meet BART requirements should be approved, if finalized by the state.  It is not yet known what the final requirements will be.  NSP-Minnesota does not expect that a finding that the CSAPR meets BART requirements would result in changes to the control equipment plans described above, and has requested that the MPCA retain its 2009 BART determination.

In October 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota's Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to visibility impairment and, if so, whether the level of controls proposed by the MPCA is appropriate.  In its Jan. 25, 2012 notice concerning its review of Minnesota's Regional Haze SIP, the EPA noted that it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the Reasonably Attributable Visibility Impairment (RAVI) program.  It is not yet known when the EPA will publish a proposal under RAVI, or what that proposal will entail.

Federal Clean Water Act (CWA) Section 316 (b) - The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species.  In April 2011, the EPA published the proposed rule that sets prescriptive standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office.  NSP-Minnesota provided comments to the proposed rule, which is expected to be finalized in late 2012.  Due to the uncertainty of the final regulatory requirements, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

As part of NSP-Minnesota's 2009 CWA permit renewal for the Black Dog plant, the MPCA required the submission of a plan for compliance with the CWA.  The compliance plan was submitted for MPCA review and approval in April 2010.  The MPCA is currently reviewing the proposal in consultation with the EPA.

Proposed Coal Ash Regulation - NSP-Minnesota's operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste.  In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste.  Coal ash is currently exempt from hazardous waste regulation.  If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, NSP-Minnesota's costs associated with the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted.  The EPA has not announced a planned date for a final rule.  The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

NSP-Minnesota Notice of Violation (NOV) - In June 2011, NSP-Minnesota received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Sherco plant and Black Dog plant in Minnesota.  The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid 2000s should have required a permit under the NSR process.  NSP-Minnesota believes it has acted in full compliance with the CAA and NSR process.  NSP-Minnesota also believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements.  NSP-Minnesota disagrees with the assertions contained in the NOV and intends to vigorously defend its position.  It is not known whether any costs would be incurred as a result of this NOV.

Asset Retirement Obligations

Recorded AROs - AROs have been recorded for plant related to nuclear production, steam production, wind production, electric transmission and distribution, gas transmission and distribution and office buildings.  The steam production obligation includes asbestos, ash containment facilities, and radiation sources.  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 and the origination dates were the in-service date of the 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 AROs 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 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 AROs associated with the decommissioning of the NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originated with the in-service date of the facility.  See Note 12 for further discussion of nuclear obligations.

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota's AROs is shown in the table below for the years ended Dec. 31, 2011 and 2010, respectively:

	Beginning								Revisions		Ending
	Balance		Liabilities		Liabilities				to Prior		Balance
(Thousands of Dollars)	Jan. 1, 2011		Recognized		Settled		Accretion		Estimates		Dec. 31, 2011
Electric plant
Steam production asbestos	$	10,041	$	-	$	-	$	438	$	-		$	10,479
Steam production ash containment		12,814		-		-		508		17,667			30,989
Steam production radiation sources		37		-		-		3		2			42
Nuclear production decommissioning		809,474		-		-		57,641		615,626	(a)		1,482,741
Wind production		38,553		-		-		1,962		-			40,515
Electric transmission and distribution		3,087		-		-		153		12,460			15,700
Natural gas plant
Gas transmission and distribution		278		-		-		17		-			295
Common and other property
Common general plant asbestos		1,077		-		-		58		-			1,135
Total liability	$	875,361	$	-	$	-	$	60,780	$	645,755		$	1,581,896

(a) The increase is primarily due to the completion of NSP-Minnesota's triennial nuclear decommissioning study, which reflects an increase in the estimated cost of retirement, increase in the escalation rates for each nuclear unit and a decrease in the discount rate used to calculate the net present value of the future cash flows.

The fair value of NSP-Minnesota's legally restricted assets, for purposes of settling the nuclear ARO, was $1.3 billion as of Dec. 31, 2011, including external nuclear decommissioning investment funds and internally funded amounts.

In 2011, NSP-Minnesota incurred revisions for nuclear decommissioning, radiation sources, ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

	Beginning									Revisions			Ending
	Balance		Liabilities		Liabilities					to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2010		Recognized		Settled			Accretion		Estimates			Dec. 31, 2010
Electric plant
Steam production asbestos	$	16,776	$	3,771	$	(2,330	)	$	858	$	(9,034	)	$	10,041
Steam production ash containment		12,547		-		-			611		(344	)		12,814
Steam production radiation sources		57		-		-			3		(23	)		37
Nuclear production decommissioning		758,923		-		-			50,551		-			809,474
Wind production		7,751		25,671		-			592		4,539			38,553
Electric transmission and distribution		140		-		-			7		2,940			3,087
Natural gas plant
Gas transmission and distribution		261		-		-			17		-			278
Common and other property
Common general plant asbestos		1,021		-		-			56		-			1,077
Total liability	$	797,476	$	29,442	$	(2,330	)	$	52,695	$	(1,922	)	$	875,361

The fair value of NSP-Minnesota's legally restricted assets, for purposes of settling the nuclear ARO, was $1.4 billion as of Dec. 31, 2010, including external nuclear decommissioning investment funds and internally funded amounts.

In 2010, NSP-Minnesota incurred revisions for asbestos, radiation sources, wind turbines, ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

Removal Costs- NSP-Minnesota records a regulatory liability for the plant removal costs of 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 time periods over which the amounts were accrued and the changing of rates over 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.  Removal costs as of Dec. 31, 2011 and 2010 were $382 million and $400 million, respectively.

Nuclear Insurance

NSP-Minnesota's public liability for claims resulting from any nuclear incident is limited to $12.6 billion under the Price-Anderson amendment to the Atomic Energy Act.  NSP-Minnesota has secured $375 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 April 2010.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL).  The coverage limits are $2.25 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 $15.7 million for business interruption insurance and $33.6 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.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material effect on NSP-Minnesota's financial position and results of operations.

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. - In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against the following utilities, including Xcel Energy Inc., the parent company of NSP-Minnesota, to force reductions in CO2 emissions:  American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority.  The lawsuits alleged that CO2 emitted by each company is a public nuisance and asked the court to order each utility to cap and reduce its CO2 emissions.  The lawsuits did not demand monetary damages.  In December 2011, the U.S. District Court entered an order dismissing this lawsuit, bringing a close to this litigation.

Native Village of Kivalina vs. Xcel Energy Inc. et al. - In February 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 Inc., the parent company of NSP-Minnesota, and 23 other utility, 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 Inc. believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit.  In November 2011, oral arguments were presented.  It is unknown when the Ninth Circuit will render a final opinion.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs' alleged relocation is estimated to cost between $95 million to $400 million.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on NSP-Minnesota's consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. - On May 27, 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi.  The complaint alleges defendants' CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants, including Xcel Energy Inc., believe  this lawsuit is without merit and have filed a motion to dismiss the lawsuit.  It is uncertain when the court will rule on this motion.  While Xcel Energy Inc. believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on NSP-Minnesota's consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation - On April 1, 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota.  NSP-Minnesota's decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact.  NSP-Minnesota also terminated the agreements due to enXco's nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011.  As a result, NSP-Minnesota recorded a $101 million deposit in the first quarter 2011, which was collected in April 2011.  On May 5, 2011, NSP-Minnesota filed a declaratory judgment action in U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements.  On that same day, enXco also filed a separate lawsuit in the same court seeking, among other things, in excess of $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco's lawsuit is without merit and has filed a motion to dismiss.  On Sept. 16, 2011, the U.S. District Court denied the motion to dismiss.  The trial is set to begin in late 2012 or early 2013.  While NSP-Minnesota believes the likelihood of loss is remote, given the nature of this case and any surrounding uncertainty, it may have a material impact on NSP-Minnesota's consolidated results of operations, cash flows or financial position.  No accrual has been recorded for this matter.

Other Contingencies

See Note 10 for further discussion.

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Summarized Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Summarized Quarterly Financial Data (Unaudited) [Abstract]

Summarized Quarterly Financial Data (Unaudited)

16.     Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2011		June 30, 2011		Sept. 30, 2011		Dec. 31, 2011
Operating revenues	$	1,192,892	$	1,010,526	$	1,168,138	$	1,026,965
Operating income		174,821		135,853		255,871		126,390
Net income		92,175		65,223		141,902		53,681

	Quarter Ended
(Thousands of Dollars)	March 31, 2010		June 30, 2010		Sept. 30, 2010		Dec. 31, 2010
Operating revenues	$	1,127,107	$	916,290	$	1,130,913	$	1,060,006
Operating income		142,000		107,362		217,674		131,188
Net income		64,139		44,040		109,787		56,259

XML

CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets
Cash and cash equivalents	$ 26,005	$ 38,408
Restricted cash	95,287	0
Notes receivable from affiliates	0	37,000
Accounts receivable, net	314,577	313,485
Accounts receivable from affiliates	18,033	26,866
Accrued unbilled revenues	231,303	249,393
Inventories	301,848	280,173
Regulatory assets	141,709	164,943
Derivative instruments	51,517	39,892
Prepayments and other	45,219	39,229
Total current assets	1,225,498	1,189,389
Property, plant and equipment, net	8,982,834	7,822,220
Other assets
Nuclear decommissioning fund and other investments	1,357,538	1,366,069
Regulatory assets	872,014	671,391
Derivative instruments	80,689	101,258
Other	36,638	31,333
Total other assets	2,346,879	2,170,051
Total assets	12,555,211	11,181,660
Current liabilities
Current portion of long-term debt	450,000	19
Short-term debt	26,000	0
Borrowings under utility money pool arrangement	65,000	0
Accounts payable	322,979	384,455
Accounts payable to affiliates	47,651	61,753
Taxes accrued	158,319	140,020
Accrued interest	68,362	66,641
Dividend payable to parent	58,054	58,372
Derivative instruments	65,781	27,311
Regulatory liabilities	132,574	42,122
Other	164,736	103,525
Total current liabilities	1,559,456	884,218
Deferred credits and other liabilities
Deferred income taxes	1,666,005	1,449,082
Deferred investment tax credits	31,743	34,437
Asset retirement obligations	1,581,896	875,361
Regulatory liabilities	439,029	462,574
Pension and employee benefit obligations	413,755	351,130
Derivative instruments	184,190	197,771
Other	65,464	93,025
Total deferred credits and other liabilities	4,382,082	3,463,380
Commitments and contingencies
Capitalization
Long-term debt	2,888,897	3,337,893
Common stock - 5,000,000 shares authorized of $0.01 par value; 1,000,000 shares outstanding at Dec. 31, 2011 and 2010	10	10
Additional paid-in capital	2,366,391	2,241,387
Retained earnings	1,372,727	1,251,938
Accumulated other comprehensive (loss) income	(14,352)	2,834
Total common stockholder's equity	3,724,776	3,496,169
Total liabilities and equity	$ 12,555,211	$ 11,181,660

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CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) (USD $)			12 Months Ended
	Dec. 31, 2011 Common Stock [Member]	Dec. 31, 2010 Common Stock [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due Aug. 28, 2012 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due Aug. 15, 2015 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due March 1, 2018 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due March 1, 2019 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due Sept. 1, 2019 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due July 1, 2025 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due March 1, 2028 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due April 1, 2030 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due July 15, 2035 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due June 1, 2036 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due July 1, 2037 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due Nov. 1, 2039 [Member]	Dec. 31, 2011 First Mortgage Bonds [Member] Series Due Aug. 15, 2040 [Member]
Long-Term Debt
Debt instrument, interest rate stated percentage (in hundredths)			8.00%	1.95%	5.25%	8.50%	8.50%	7.125%	6.50%	8.50%	5.25%	6.25%	6.20%	5.35%	4.85%
Debt instrument, maturity date			Aug. 28, 2012	Aug. 15, 2015	Mar. 01, 2018	Mar. 01, 2019	Sep. 01, 2019	Jul. 01, 2025	Mar. 01, 2028	Apr. 01, 2030	Jul. 15, 2035	Jun. 01, 2036	Jul. 01, 2037	Nov. 01, 2039	Aug. 15, 2040
Common Stockholder's Equity
Common stock, shares authorized (in shares)	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares outstanding (in shares)	1,000,000	1,000,000

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Schedule II Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS [Abstract]

SCHEDULE II- VALUATION AND QUALIFYING ACCOUNTS

SCHEDULE II

NSP-MINNESOTA AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2011, 2010 AND 2009

(amounts in thousands)

			Additions
	Balance at Jan. 1		Charged to  Costs and Expenses		Charged  to Other  Accounts(a)		Deductions  from  Reserves(b)		Balance at  Dec. 31
Allowance for bad debts:
2011	$	20,996	$	15,936	$	5,833	$	19,761	$	23,004
2010		22,675		15,213		5,805		22,697		20,996
2009		25,699		19,408		5,521		27,953		22,675

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off or transferred.

XML

Rate Matters

12 Months Ended

Dec. 31, 2011

Rate Matters [Abstract]

Rate Matters

10.     Rate Matters

NSP-Minnesota

Pending Regulatory Proceedings - MPUC

Base Rate

NSP-Minnesota - Minnesota Electric Rate Case- In November 2010, NSP-Minnesota filed a request with the MPUC to increase electric rates in Minnesota for 2011 by approximately $150 million, or an increase of 5.62 percent and an additional increase of $48.3 million, or 1.81 percent in 2012.  The rate filing was based on a 2011 forecast test year and included a requested ROE of 11.25 percent, an electric rate base of approximately $5.6 billion and an equity ratio of 52.56 percent.  The MPUC approved an interim rate increase of $123 million, subject to refund, effective Jan. 2, 2011.

In June 2011, NSP-Minnesota revised its requested rate increase to $122.8 million, reflecting a revised ROE of 10.85 percent and other adjustments.  The DOER revised its recommended rate increase to approximately $84.7 million in 2011 and an additional rate increase of $34 million in 2012, reflecting an ROE of 10.37 percent.  The primary differences between the NSP-Minnesota requested rate increase and the DOER updated recommendation were associated with ROE and compensation related issues.

In August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and a 2012 step increase of approximately $29 million.  The revisions were due to delays in the Monticello nuclear plant extended power uprate.

In November 2011, NSP-Minnesota reached a settlement agreement with the Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group and Verso Paper Corp., which settled all financial issues and several rate design issues between the signing parties.  The settlement includes a rate increase of approximately $58.0 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent.  The settlement agreement reflects a reduction to depreciation expense and NSP-Minnesota's rate request by $30 million with an additional adjustment of $7.5 million related to employee compensation.  The settlement also provides NSP-Minnesota the ability to seek deferred accounting for incremental property tax increases associated with electric and natural gas businesses in 2012, which is currently projected to increase by approximately $28 million.  NSP-Minnesota also agreed to not file an electric rate case prior to Nov. 1, 2012, provided that both the settlement and the property tax filing are approved by the MPUC.  NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $67.4 million for 2011 and has reduced depreciation expense by $30 million.

In February 2012, the ALJ recommended MPUC approval of the settlement agreement.  In addition, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  A decision is expected by the MPUC in the first half of 2012.

Pending Regulatory Proceedings - NDPSC

NSP-Minnesota – North Dakota Electric Rate Case - In December 2010, NSP-Minnesota filed a request with the NDPSC to increase 2011 electric rates in North Dakota by approximately $19.8 million, or an increase of 12 percent in 2011 and a step increase of $4.2 million, or 2.6 percent in 2012.  The rate filing is based on a 2011 forecast test year and includes a requested ROE of 11.25 percent, an electric rate base of approximately $328 million and an equity ratio of 52.56 percent.

The NDPSC approved an interim rate increase of approximately $17.4 million, subject to refund, effective Feb. 18, 2011.  NSP-Minnesota has recorded a provision for revenue subject to refund of approximately $2.4 million for 2011.  The interim rates will remain in effect until the NDPSC makes its final decision on the case.

In May 2011, NSP-Minnesota revised its rate request to approximately $18.0 million, or an increase of 11 percent, for 2011 and $2.4 million, or 1.4 percent, for the additional step increase in 2012, due to the termination of the Merricourt wind project.

In September 2011, NSP-Minnesota reached a settlement with the NDPSC Advocacy Staff.  If approved by the NDPSC, the settlement would result in a rate increase of $13.7 million in 2011 and an additional step increase of $2.0 million in 2012, based on a 10.4 percent ROE and black box settlement for all other issues.  To address 2011 sales coming in below test year projections, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.

An NDPSC decision is expected in March 2012.

Pending Regulatory Proceedings - SDPUC

NSP-Minnesota – South Dakota Electric Rate Case - In June 2011, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $14.6 million annually, effective in 2012.  The proposed increase included $0.7 million in revenues currently recovered through automatic recovery mechanisms.  The request is based on a 2010 historic test year adjusted for known and measurable changes, a requested ROE of 11 percent, a rate base of $323.4 million and an equity ratio of 52.48 percent.  NSP-Minnesota also requested approval of a nuclear cost recovery rider to recover the actual investment cost of the Monticello nuclear plant life cycle management and extended power uprate project that is not reflected in the test year.

As a result of delays in the rate case process, interim rates of $12.7 million were implemented Jan. 2, 2012.  A final decision is expected in the first half of 2012.

Electric, Purchased Gas and Resource Adjustment Incentive Clauses

NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy, other resource costs, lost margins and/or performance incentives, which are generally recovered concurrently through riders and base rates.  At Dec. 31, 2011, pending adjustment clauses, which contain amounts related to incentive programs were as follows:

CIP Rider - CIP expenses are recovered through base rates and a rider that is adjusted annually.  Under the 2010 electric CIP rider request approved by the MPUC in October 2010, NSP-Minnesota recovered $84.4 million through the rider during November 2010 to December 2011.  This is in addition to $60.9 million recovered through base rates.  During December 2010 to December 2011, NSP-Minnesota recovered $27.4 million through the natural gas CIP rider approved in November 2010.  This is in addition to $4.4 million recovered in base rates.

In January 2012, the MPUC approved NSP-Minnesota's annual electric rider petition requesting recovery of $74.7 million of electric CIP expenses and financial incentives to be recovered during February 2012 through December 2012.  In December 2011, the MPUC approved NSP-Minnesota's annual gas rider petition requesting $10.6 million of natural gas CIP expenses and financial incentives to be recovered during January 2012 through December 2012.  This proposed recovery through the riders is in addition to an estimated $48.3 million and $3.8 million through electric and gas base rates, respectively.