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, 2012

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. 25, 2013, 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 2013 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	5
Public Utility Regulation	5
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	10
Fuel Sources	10
Renewable Energy Sources	11
Wholesale Commodity Marketing Operations	12
Summary of Recent Federal Regulatory Developments	12
Electric Operating Statistics	13
NATURAL GAS UTILITY OPERATIONS	14
Overview	14
Public Utility Regulation	15
Capability and Demand	15
Natural Gas Supply and Costs	15
Natural Gas Operating Statistics	16
GENERAL	16
ENVIRONMENTAL MATTERS	17
EMPLOYEES	17
Item 1A — Risk Factors	17
Item 1B — Unresolved Staff Comments	25
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	27
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
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	87
Item 9A — Controls and Procedures	87
Item 9B — Other Information	88
PART III	88
Item 10 — Directors, Executive Officers and Corporate Governance	88
Item 11 — Executive Compensation	88
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	88
Item 13 — Certain Relationships and Related Transactions, and Director Independence	88
Item 14 — Principal Accountant Fees and Services	88
PART IV	88
Item 15 — Exhibits, Financial Statement Schedules	88
SIGNATURES	92

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
DOI	United States Department of the Interior
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPCA	Minnesota Pollution Control Agency
MPSC 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
EPU	Extended power uprate
FCA	Fuel clause adjustment
GAP	Gas affordability program
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
CO2	Carbon dioxide
CON	Certificate of need
CPCN	Certificate of public convenience and necessity
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
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
MGP	Manufactured gas plant
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investor Services
MVP	Multi-value project
Native load	Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract.
NEI	Nuclear Energy Institute
NOL	Net operating loss
NOx	Nitrogen oxide
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PFS	Private Fuel Storage, LLC
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	Photovoltaic
REC	Renewable energy credit
ROE	Return on equity
RPS	Renewable portfolio standard
RSG	Revenue sufficiency guarantee
RTO	Regional Transmission Organization
SIP	State implementation plan
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 4 percent of its total KWh sold in 2012.  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 2012.  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, an inactive company.

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 core priority for NSP-Minnesota and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value.

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 been granted continued authorization from the FERC to make wholesale electric sales at market-based prices.  NSP-Minnesota is a transmission owning member of the MISO RTO.

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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 improvement projects.

· 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 recovers the cost of new renewable generation.

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

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

The MPUC approved NSP-Minnesota’s request that the recovery of the costs associated with the EIR and RES be included in base rates in the Minnesota electric rate case as part of the final rates effective Sept. 1, 2012.  No costs are being recovered through the EIR at this time.  NSP-Minnesota will continue to track PTCs associated with company-owned renewable projects and reflect the difference between the base rate amount and actual costs in the RES adjustment clause.

NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred 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 base 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.  NSP-Minnesota was in compliance with this standard in 2012 and expects to be in compliance in 2013.  These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

CIP Triennial Plan — In October 2012, the Department of Commerce approved NSP-Minnesota’s 2013 through 2015 CIP Triennial Plan, which increases the savings goals and budgets over the previous plan. The plan sets an electric goal of annually saving the equivalent of 1.5 percent of sales (calculated on a historical three-year average, excluding opt-out customers) and an annual natural gas goal of saving 1.0 percent of sales.  The combined electric and gas budgets average $104 million per year over the 2013 through 2015 period.

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2013, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2010		2011	2012		2013 Forecast
NSP System		9,131	9,792		9,475	9,215

The peak demand for the NSP System typically occurs in the summer.  The 2012 uninterrupted system peak demand for the NSP System occurred on July 2, 2012.  The 2011 peak demand occurred on a day with extremely high temperatures and humidity, which resulted in the highest uninterrupted system peak demand since July 31, 2006.  The 2012 peak demand occurred uninterrupted on a day with weather much closer to normal peak day conditions.  The forecast for 2013 assumes normal peak day weather and includes the impact of the termination of several firm wholesale contracts primarily at NSP-Wisconsin.  The 2013 forecast also reflects the impact of two large commercial and industrial customers that have ceased operations.  These customers represented 0.05 percent of 2012 sales.

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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 November 2012, the MPUC issued an order on NSP-Minnesota’s resource plan and required additional filings to determine the next resources needed for the NSP System generating capacity.  In December 2012, NSP-Minnesota filed its information indicating an estimated need of 150 MW in 2017 and increasing to 440 MW by 2019, with the size and timing to be determined by the MPUC.  A competitive acquisition process is anticipated to commence in March 2013 and result in the selection of a developer or developers by the MPUC in the fourth quarter of 2013.  See additional discussion within the Prairie Island Nuclear EPU section below.

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

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV transmission line

In May 2012, the MPUC issued a route permit for the Minnesota portion of the project.  Two parties have filed an appeal with the Minnesota Court of Appeals against the MPUC’s route permit decision.  A decision by the Court is anticipated in mid-2013.  In May 2012, the PSCW issued a CPCN for the Wisconsin portion of the project.  Subsequent legal challenges to the PSCW’s order by intervenors were unsuccessful, thereby rendering the PSCW’s decision final.  Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2015.

Monticello, Minn. to Fargo, N.D. 345 KV transmission line

In December 2011, the Monticello, Minn. to St. Cloud, Minn. portion of the Monticello, Minn. to Fargo, N.D. project was placed in service.  The MPUC issued a route permit for the Minnesota portion of the St. Cloud, Minn. to Fargo, N.D. section in June 2011.   The NDPSC granted a CPCN in January 2011 and a certificate of corridor compatibility and route permit for the portion of the line in North Dakota in September 2012.  In January 2013, construction started on the project in North Dakota.

Brookings County, S.D. to Hampton, Minn. 345 KV transmission line

The MPUC route permit approvals for the Minnesota segments were obtained in 2010 and 2011.  In June 2011, the SDPUC approved a facility permit for the South Dakota segment.  In December 2011, MISO granted the final approval of the project as a MVP.  In May 2012, construction started on the project in Minnesota.

Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line

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

Black Dog Repowering CON — In November 2012, the MPUC approved the termination of the Black Dog Repowering CON proceeding.

Nuclear Power Operations and Waste Disposal

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

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NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota.  Decisions by the NRC can significantly impact the operations of the nuclear generating plants.  The event at the nuclear generating plant in Fukushima, Japan in 2011 could impact the NRC’s deliberations on NSP-Minnesota’s Monticello power uprate request and could also result in additional regulation, which could require additional capital expenditures or operating expenses.  The NRC has created an internal task force that has developed recommendations 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 in a written report which recommends actions to enhance U.S. nuclear generating plant readiness to safely manage severe events.

In March 2012, the NRC issued three orders and a request for additional information to all licensees.  The orders included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant.  The request for additional information included requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards and to assess the emergency preparedness staffing and communications capabilities at each plant.  NSP-Minnesota expects that complying with these requirements will cost approximately $35 to $50 million at the Monticello and Prairie Island plants.  Based on current refueling outage plans specific to each nuclear facility, the dates of the required compliance to meet the orders is expected to begin in the second quarter of 2015 with all units expected to be fully compliant by December 2016.  Portions of the work that fall under the requests for additional information are expected to be completed by 2018.  NSP-Minnesota believes the costs associated with compliance would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

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

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

Nuclear Geologic Repository - Yucca Mountain Project

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

The DOE’s decision and the resulting stoppage of the NRC’s review has prompted multiple legal challenges, including the DOE’s authority to stop the project and withdraw the application, the DOE’s authority to continue to collect the nuclear waste fund fee and the NRC’s authority to stop their review of the DOE’s application.  The utility industry, including Xcel Energy, Inc. and NSP-Minnesota, are represented in these challenges by the NEI.  Currently, only the challenges to set the nuclear waste fund fee collection rate to zero and seeking the NRC to complete their review remain active and decisions are expected from the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in 2013.

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

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Nuclear Spent Fuel Storage

NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear generating plants.  As of Dec. 31, 2012, there were 29 casks loaded and stored at the Prairie Island plant and 10 canisters loaded and stored at the Monticello plant.  An additional 35 casks for Prairie Island and 20 canisters for Monticello have been authorized by the State of Minnesota.  This currently authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the renewed operating licenses in 2030 for Monticello, 2033 for Prairie Island Unit 1, and 2034 for Prairie Island Unit 2.

PFS — The eight partners of PFS, including NSP-Minnesota, have agreed to dissolve the LLC.  PFS filed a letter with the NRC in December 2012 requesting to terminate the PFS license effective immediately.  PFS will be taking the appropriate actions to dissolve the LLC in 2013.

NRC Waste Confidence Decision (WCD) — In June 2012, the D.C. Circuit issued a ruling to vacate and remand the NRC’s WCD.  The WCD assesses how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available.  The D.C. Circuit remanded the WCD to the NRC and directed it to prepare an environmental impact statement (EIS) if there are significant impacts or an environmental assessment to support a finding of no significant impact.  In September 2012, the NRC Commissioners directed the NRC Staff to develop an EIS and a revised WCD and rule on the temporary storage of spent nuclear fuel.  The EIS and rule are to be completed within 24 months.  NSP-Minnesota does not believe that there will be an immediate impact on operations at the Prairie Island or Monticello nuclear generating plants.

See Notes 11 and 12 to the consolidated financial statements for further discussion regarding nuclear related items.

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 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.

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

Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a CON for an EPU project at the Prairie Island nuclear generating plant.  The total estimated cost of the EPU was $294 million, of which approximately $77.6 million has been incurred, including AFUDC of approximately $13.3 million.  Subsequently, NSP-Minnesota filed a resource plan update and a change of circumstances filing notifying the MPUC that there were changes in the size, timing and cost estimates for this project, revisions to economic and project design analysis and changes due to the estimated impact of revised scheduled outages.  The information indicated reductions to the estimated benefit of the uprate project.  As a result, NSP-Minnesota concluded that further investment in this project would not benefit customers.  In December 2012, the MPUC voted unanimously that no party had shown cause to prevent termination of the EPU CON.  The MPUC is expected to issue an order terminating the EPU CON in the first half of 2013.

NSP-Minnesota plans to address recovery of incurred costs in the next rate case for each of the NSP-Minnesota jurisdictions and to file a request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement.  NSP-Wisconsin plans to seek cost recovery in a future rate case.  Based on the outcome of the MPUC decision, EPU costs incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent, resulting in a $10.1 million pretax charge in December 2012 which is included in O&M expense.

Monticello Nuclear Plant EPU— In 2008, NSP-Minnesota filed for both state and federal approvals of an EPU of approximately 71 MW for NSP-Minnesota’s Monticello nuclear generating plant.  The MPUC approved the CON for the EPU in 2008.  The license amendment 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.  In September 2012, NSP-Minnesota made a supplemental filing to the NRC to address the containment accident pressure concern, as part of its application to amend the operating license to allow the power uprate.  NSP-Minnesota expects to receive approval of the EPU project by the NRC in the second half of 2013.  NSP-Minnesota is planning to complete implementation of the equipment changes needed to support the Monticello life extension and EPU projects in the planned spring 2013 refueling outage.

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Overall, NSP-Minnesota is nearing completion of its life cycle management and EPU project at the Monticello nuclear generating plant to help ensure continued safe and reliable operation through 2030, and to provide additional capacity of approximately 71 MW.  As a result of the licensing delays discussed above, as well as engineering design changes and emergent work discovered during implementation, both the cost and the projected in-service date exceed initial estimates, consistent with experience of other nuclear plant life extension and uprate projects.  In addition, despite the cancellation of the EPU project at the Prairie Island nuclear generating plant, NSP-Minnesota is implementing life cycle management improvements at the Prairie Island facilities to help ensure their safe and reliable operation through 2034.   The major capital investments for these activities at the Monticello and Prairie Island nuclear generating plants are expected to be completed in the years 2013 through 2017, with combined forecasted capital costs in that period of approximately $500 million.

Fuel Supply and Costs

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

																Weighted
	Coal*					Nuclear					Natural Gas					Average Owned
NSP System Generating Plants	Cost		Percent			Cost		Percent			Cost		Percent			Fuel Cost
2012	$	2.13		47	%	$	0.90		42	%	$	4.21		11	%	$	1.88
2011		2.06		55			0.89		40			6.56		5			1.82
2010		1.89		51			0.83		42			6.29		7			1.73

* Includes refuse-derived fuel and wood

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

Fuel Sources

Coal — The NSP System normally maintains approximately 41 days of coal inventory.  Coal supply inventories at Dec. 31, 2012 and 2011 were approximately 39 and 48 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 2012 and 2011, coal requirements for the NSP System’s major coal-fired generating plants were approximately 7.2 million tons and 9.5 million tons, respectively.  The estimated coal requirements for 2013 are approximately 8.6 million tons.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 97 percent of their coal requirements in 2013, 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 and 80 percent of their coal requirements in 2013 and 2014, respectively.  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 2018 and approximately 67 percent of the requirements for 2019 through 2025.

· Current contracts for conversion services cover 100 percent of the requirements through 2020 and approximately 67 percent of the requirements for 2021 through 2025.

· Current enrichment service contracts cover 99.7 percent of the requirements through 2022 and approximately 84 percent of the requirements for 2023 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.

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

Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers.  Natural gas supplies and associated transportation and storage services for power plants are procured under contracts with various terms to provide an adequate supply of fuel.  However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market.  Generally, natural gas supply contracts have pricing that is tied to various natural gas indices.  Most transportation contract pricing is based on FERC approved transportation tariff rates.  These transportation rates are subject to revision based upon FERC approval of changes in the timing or amount of allowable cost recovery by providers.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2012 and 2011, the NSP System did not have any commitments related to gas supply contracts; however, commitments related to gas transportation and storage contracts were approximately $384 million and $462 million, respectively.   Commitments related to gas transportation and storage contracts expire in various years from 2013 to 2028.

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

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass, and solar power from both owned generating facilities and PPAs.  As of Dec. 31, 2012, the NSP System was in compliance with mandated RPSs, which require generation from renewable resources of 18 percent and 8.89 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.  Renewable energy comprised 22.0 percent and 19.7 percent of the NSP System’s total owned and purchased energy for 2012 and 2011, respectively.  Wind energy comprised 11.9 percent and 9.4 percent of the total owned and purchased energy on the NSP System for 2012 and 2011, respectively.  Hydroelectric energy comprised 7.0 percent and 7.5 percent of the total owned and purchased energy on the NSP System for 2012 and 2011, respectively.  Biomass and solar power comprised approximately 3.1 percent and 2.8 percent of renewable energy for 2012 and 2011, respectively.

The NSP System also offers customer-focused renewable energy initiatives.  Windsource®, one of the nation’s largest voluntary renewable energy programs, allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources.  Approximately 24,000 and 23,000 customers purchased 184,000 MWh and 177,000 MWh of electricity under the Windsource program in 2012 and 2011, 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 561 PV systems with approximately 6.7 MW of aggregate capacity and over 300 PV systems with approximately 3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2012 and 2011, respectively.

Wind—The NSP System acquires the majority of its wind energy from PPAs 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 2012, the NSP System began purchasing wind from three new projects, which provided approximately 266 MW of capacity.  The largest of these projects, the Prairie Rose Wind Project began commercial operations in December 2012 and the NSP System will purchase the entire output from this 200 MW project.  In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements.  The average cost per MWh of wind energy under these contracts was approximately $41 and $39 for 2012 and 2011, 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 2012 benefited from improvements in technology, excess capacity among manufacturers, and motivation to complete new construction prior to the anticipated expiration of the Federal PTCs in 2012.  In January 2013, the Federal PTC was extended through 2013.

The NSP System also owns and operates two wind farms.  The 101 MW Grand Meadow Wind Farm and the 201 MW Nobles Wind Farm began generating electricity in 2008 and 2010, respectively.  Collectively, the NSP System had over 1,870 MW and over 1,600 MW of wind energy on its system at the end of 2012 and 2011, respectively.

Hydroelectric—The NSP System acquires its hydroelectric energy from both owned generation and PPAs.  The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 274 MW of capacity.  For most of 2012, there were nine PPAs in place which provided approximately 37 MW of hydroelectric capacity.  Additionally, the NSP System purchases approximately 850 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.

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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.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) —The FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation and development to be effective prospectively.  The requirements for transmission planning and cost allocation were addressed by revisions to the MISO Tariff for NSP-Minnesota as discussed below in MISO Transmission Pricing.

In 2012, Minnesota’s Governor signed legislation that preserves the rights of incumbent utilities to construct and own transmission interconnected to their systems.  This legislation is similar to the legislation previously passed in North Dakota and South Dakota.  Therefore, Order 1000 is expected to have limited impacts on future transmission development and ownership in the NSP System in Minnesota, North Dakota and South Dakota.

ATC vs. Xcel Energy Services Inc. and MISO (Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. Transmission Line) — In October 2012, American Transmission Company LLC (ATC) filed a complaint against MISO, Xcel Energy Services Inc., NSP-Minnesota and NSP-Wisconsin, alleging that, under the legal principles set forth in the July 2012 FERC ruling in the La Crosse to Madison transmission line complaint filed by Xcel Energy Services Inc. on behalf of its subsidiary NSP-Wisconsin against ATC, that the FERC should determine that MISO should have designated the Hampton to Rochester to La Crosse CapX2020 line and the La Crosse to Madison line as a single facility under the MISO Transmission Owners Agreement and Tariff.  Thus, ATC should have been designated as the owner of the La Crosse to Madison line portion of the purported single facility.  Xcel Energy filed an answer seeking dismissal of the ATC complaint in October 2012.  On Feb. 4, 2013, the FERC issued an order denying the ATC complaint.  The FERC found that MISO properly applied its planning process and that Hampton to La Crosse and the La Crosse to Madison lines are separate.  Therefore, MISO’s prior ownership decisions stand.

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 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.  NSP-Minnesota is exploring a pilot program that would expand existing retail CIP services to more fully interact with the MISO market.  The most recent filing in this open docket was in November 2012.

Electric Transmission Rate Regulation — The FERC regulates the rates and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control of their electric transmission assets for the sale of electric transmission services to an RTO.  NSP-Minnesota and NSP-Wisconsin are members of the MISO RTO.  Each RTO separately files regional transmission tariff rates for approval by the FERC.  All members within that RTO are then subjected to those rates.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments: some lower voltage projects are fully allocated to loads near the project vicinity, and other reliability projects are allocated 20 percent regionally and 80 percent to local loads.  If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region.  MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to provide multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving.  Certain parties have appealed the FERC MVP tariff orders to the U.S. Court of Appeals for the Seventh Circuit.

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In its Order 1000 compliance filing in October 2012, MISO proposed that all future reliability projects be fully allocated to the zones in which the project is located (rather than allocating costs more broadly) while MVP projects would continue to be eligible for regional cost allocation.   FERC action is anticipated in 2013.  The NSP System has certain new transmission facilities for which other customers in MISO contribute to cost recovery.  Likewise, the NSP System also pays a share of the costs of projects constructed by other transmission owning entities.  The transmission revenues received by the NSP System from MISO, and the transmission charges paid to MISO, associated with projects subject to regional cost allocation could be significant in future periods.

RSG Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy.  In August 2010, the FERC issued two orders relating to RSG charge exemptions and the allocation of the RSG costs among MISO participants.  In recent RSG filings, MISO has proposed, and the FERC has accepted, allocating 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.  NSP-Minnesota is permitted to recover the RSG costs through FCA mechanisms approved by the regulators in each jurisdiction.  Certain of the FERC’s orders remain pending on rehearing, and appeals of the FERC orders to the U.S. Court of Appeals for the D.C. Circuit have been held in abeyance, pending the FERC’s disposition of rehearing requests.

Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2012			2011			2010
Electric sales (Millions of KWh)
Residential		10,377			10,448			10,414
Large commercial and industrial		9,302			9,750			9,739
Small commercial and industrial		15,478			15,439			15,450
Public authorities and other		264			260			266
Total retail		35,421			35,897			35,869
Sales for resale		1,625			1,711			2,234
Total energy sold		37,046			37,608			38,103
Number of customers at end of period
Residential		1,252,589			1,245,413			1,240,509
Large commercial and industrial		496			500			502
Small commercial and industrial		151,978			151,144			150,392
Public authorities and other		6,699			6,470			6,291
Total retail		1,411,762			1,403,527			1,397,694
Wholesale		15			17			13
Total customers		1,411,777			1,403,544			1,397,707
Electric revenues (Thousands of Dollars)
Residential	$	1,165,413		$	1,140,598		$	1,095,862
Large commercial and industrial		632,831			660,083			627,774
Small commercial and industrial		1,324,989			1,270,757			1,240,979
Public authorities and other		34,444			34,211			33,329
Total retail		3,157,677			3,105,649			2,997,944
Wholesale		42,748			47,316			79,555
Interchange revenues from NSP-Wisconsin		449,958			440,519			416,076
Other electric revenues		192,146			179,144			131,140
Total electric revenues	$	3,842,529		$	3,772,628		$	3,624,715
KWh sales per retail customer		25,090			25,576			25,663
Revenue per retail customer	$	2,237		$	2,213		$	2,145
Residential revenue per KWh		11.23	¢		10.92	¢		10.52	¢
Large commercial and industrial revenue per KWh		6.80			6.77			6.45
Small commercial and industrial revenue per KWh		8.56			8.23			8.03
Wholesale revenue per KWh		2.63			2.76			3.56

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Energy Source Statistics

	Year Ended Dec. 31
	2012					2011					2010
NSP System	Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation			Millions of KWh		Percent of Generation
Coal		16,023		35	%		20,131		44	%		19,579		42	%
Nuclear		13,231		29			13,332		29			14,628		31
Natural Gas		6,200		13			3,016		7			3,887		8
Wind (a)		5,443		12			4,312		9			3,760		8
Hydroelectric		3,193		7			3,444		8			3,487		7
Other (b)		1,617		4			1,453		3			1,494		4
Total		45,707		100	%		45,688		100	%		46,835		100	%
Owned generation		31,365		69	%		31,668		69	%		33,758		72	%
Purchased generation		14,342		31			14,020		31			13,077		28
Total		45,707		100	%		45,688		100	%		46,835		100	%

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

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

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 2012, 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 per year to 348 MMBtu per year, on a weather-normalized basis.  Although wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires, among other things, additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. 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.  This process could cause temporary or permanent limitations on throughput for affected pipelines. In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations, addressing a variety of subjects, including: requiring use of automatic or remote-controlled shut-off valves in certain circumstances; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $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.

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Public Utility Regulation

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

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

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

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).  The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 732,135 MMBtu, which occurred on Jan. 19, 2012, and 751,985 MMBtu, which occurred on Jan. 20, 2011.

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 590,698 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, 2011-2012, and 2012-2013 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.

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:

2012	$	4.41
2011		5.25
2010		5.43

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2013 through 2033.

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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, 2012, NSP-Minnesota was committed to approximately $377 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 21 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
	2012		2011		2010
Natural gas deliveries (Thousands of MMBtu)
Residential		32,817		37,683		36,300
Commercial and industrial		35,054		39,878		38,609
Total retail		67,871		77,561		74,909
Transportation and other		10,943		10,797		9,455
Total deliveries		78,814		88,358		84,364
Number of customers at end of period
Residential		446,677		443,513		440,680
Commercial and industrial		41,542		41,190		40,772
Total retail		488,219		484,703		481,452
Transportation and other		21		17		19
Total customers		488,240		484,720		481,471
Natural gas revenues (Thousands of Dollars)
Residential	$	263,233	$	326,983	$	319,418
Commercial and industrial		199,097		266,258		258,943
Total retail		462,330		593,241		578,361
Transportation and other		9,435		11,482		10,683
Total natural gas revenues	$	471,765	$	604,723	$	589,044
MMBtu sales per retail customer		139.02		160.02		155.59
Revenue per retail customer	$	947	$	1,224	$	1,201
Residential revenue per MMBtu		8.02		8.68		8.80
Commercial and industrial revenue per MMBtu		5.68		6.68		6.71
Transportation and other revenue per MMBtu		0.86		1.06		1.13

GENERAL

Seasonality

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

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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 believes its rates are competitive with currently available alternatives.

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.

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 recover the cost of these initiatives through rates.

EMPLOYEES

As of Dec. 31, 2012, NSP-Minnesota had 3,670 full-time employees and ten part-time employees, of which 2,224 were covered under collective-bargaining agreements.  See Note 7 to the consolidated financial statements for further discussion.

Item 1A — Risk Factors

Like other companies in our industry, Xcel Energy, which includes NSP-Minnesota, is subject to a variety of risks, many of which are beyond our control.  Important risks that may adversely affect the business, financial condition, and results of operations are further described below.  These risks should be carefully considered together with the other information set forth in this report and in future reports that Xcel Energy files with the SEC.

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

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes NSP-Minnesota, is to understand, manage and, when possible, mitigate material risk.  Management is responsible for identifying and managing risks, while the Board of Directors oversees and holds management accountable.  As described more fully below, NSP-Minnesota is faced with a number of different types of risk.  Many of these risks are cross-cutting risks such that these risks are discussed and managed across business areas and coordinated by Xcel Energy 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 financial disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls.  Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing Xcel Energy’s strategy.  At the same time, the business planning process identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

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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.

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 including those for protected natural and cultural resources (such as wetlands, endangered species and other protected wildlife, and archeological and historical resources), licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, 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, 2012, 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, coal ash and cooling water intake systems. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

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

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk.  Physical risks from climate change include an increase in sea level and changes in weather conditions, such as 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.

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, in a continued low interest rate environment there could be pressure on ROE.  There can also 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 or climate change regulation, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

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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 our 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 concerns regarding European sovereign debt and management of the U.S. federal 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 or on incremental commercial paper issuances could also have an adverse effect on our operating results.  Changes in interest rates may also impact the fair value of the debt securities in the nuclear decommissioning fund and master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

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

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

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

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

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

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

We have defined benefit pension and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual stock and bond market performance, changes in interest rates and changes in governmental regulations.  In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008 with modifications to these funding requirements in 2012 that allowed additional flexibility in the timing of contributions.  Therefore, our funding requirements and related contributions may change in the future.  Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

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

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

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.

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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.

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

On a periodic basis 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, customer usage patterns, economic activity, costs, regulatory mechanisms, impact of technology on energy efficiency on sales and production, customer behavioral response and continuation of the existing utility business model.  Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide.  This could lead to under recovery of costs or insufficient resources to meet customer demand.

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

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

Our natural gas transmission and distribution activities include a variety of inherent hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, 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, 2012, Xcel Energy Inc. and its utility subsidiaries had approximately $10.1 billion of long-term debt and $0.9 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.

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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, 2012, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $69.5 million and $17.9 million of exposure.  Xcel Energy also had additional guarantees of $29.6 million at Dec. 31, 2012 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 2012, 2011 and 2010 we paid $234.1 million, $232.5 million and $233.2 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.

Public Policy Risks

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

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs.  Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  The U.S. continues to participate in international negotiations related to the United Nations Framework Convention on Climate Change.  Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities 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 it is not known when the EPA will initiate this rulemaking.

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.

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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 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.

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

Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions.  The consequences of a prolonged economic recession and uncertainty of recovery 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.

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, and 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 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.

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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.

We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure.  In addition, in the ordinary course of business, we use our systems and infrastructure to create, collect, use, disclose, store, dispose of and otherwise process sensitive information, including company data, customer energy usage data, and personal information regarding customers, employees and their dependents, contractors and other individuals.

Our generation, transmission, distribution and fuel storage facilities, information technology systems and other infrastructure or physical assets, as well as the information processed in our systems, infrastructure and assets could be directly or indirectly affected by unintentional or deliberate cyber security incidents, including those caused by human error.  Cyber security incidents could harm our businesses by limiting our generating, transmitting and distributing capabilities, delaying our development and construction of new facilities or capital improvement projects to existing facilities, disrupting our customer operations, or exposing us to liability.  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 incident of the regional electric transmission grid, natural gas pipeline infrastructure or other fuel sources or of our third party service providers’ operations,  could also negatively impact our business.  In addition, we also anticipate that such an event would receive regulatory scrutiny at both the Federal and State level.  We are unable to quantify the potential impact of such cyber security threats or subsequent related actions.  These potential cyber security incidents and corresponding regulatory action could result in a material decrease in revenues and may causesignificant additional costs (e.g., penalties, third party claims, repairs, insurance or compliance) and potentially disrupt our supply and markets for natural gas, oil and other fuels.

Although we maintain security measures designed to protect our information technology systems, network infrastructure and other assets, these assets as well as the information they process may be vulnerable to cyber security incidents, including the resulting disability, or failures of assets or unauthorized access to assets or information.   If our technology systems were to fail or be breached, or those of our third-party service providers, we may be unable to fulfill critical business functions, including effectively maintaining certain internal controls over financial reporting. We are unable to quantify the potential impact of cyber security incidents on our business.

Rising energy prices could negatively impact our business.

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

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

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

Item 1B — Unresolved Staff Comments

None.

25

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 2012
			Net Dependable
Station, Location and Unit	Fuel	Installed	Capability (MW)
Steam:
A.S. King-Bayport, Minn., 1 Unit	Coal	1968		511
Sherco-Becker, Minn.
Unit 1	Coal	1976		680
Unit 2	Coal	1977		682
Unit 3	Coal	1987		507	(a)
Monticello-Monticello, Minn., 1 Unit	Nuclear	1971		554
Prairie Island-Welch, Minn.
Unit 1	Nuclear	1973		521
Unit 2	Nuclear	1974		519
Black Dog-Burnsville, Minn., 2 Units	Coal/Natural Gas	1955-1960		232
Various locations, 4 Units	Wood/Refuse-derived fuel	Various		36	(b)
Combustion Turbine:
Angus Anson-Sioux Falls, S.D., 3 Units	Natural Gas	1994-2005		327
Black Dog-Burnsville, Minn., 2 Units	Natural Gas	1987-2002		271
Blue Lake-Shakopee, Minn., 6 Units	Natural Gas	1974-2005		453
High Bridge-St. Paul, Minn., 3 Units	Natural Gas	2008		534
Inver Hills-Inver Grove Heights, Minn., 6 Units	Natural Gas	1972		282
Riverside-Minneapolis, Minn., 3 Units	Natural Gas	2009		470
Various locations, 17 Units	Natural Gas	Various		101
Wind:
Grand Meadow-Mower County, Minn., 67 Units	Wind	2008		101	(c)
Nobles-Nobles County, Minn., 134 Units	Wind	2010		201	(c)
		Total		6,982

(a) Based on NSP-Minnesota’s ownership of 59 percent.  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.

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2012:

Conductor Miles
500 KV	2,917
345 KV	6,388
230 KV	1,801
161 KV	281
115 KV	7,129
Less than 115 KV	82,963

NSP-Minnesota had 349 electric utility transmission and distribution substations at Dec. 31, 2012.

Natural gas utility mains at Dec. 31, 2012:

Miles
Transmission	137
Distribution	9,732

26

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 $1.2 billion in additional cash dividends on common stock at Dec. 31, 2011, or $1.3 billion at Dec. 31, 2012.

In addition, NSP-Minnesota has 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.

· The most restrictive dividend limitation for NSP-Minnesota is imposed by its state regulatory commission.  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, 2012.  Total capitalization for NSP-Minnesota was $7.75 billion at Dec. 31, 2012, which did not exceed the limit of $8.25 billion.

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

The dividends declared during 2012 and 2011 were as follows:

(Thousands of Dollars)	2012		2011
First quarter	$	58,028	$	57,635
Second quarter		59,021		58,258
Third quarter		59,005		58,245
Fourth quarter		58,757		58,054

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).

27

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 on 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; trade, fiscal, taxation and environmental policies in areas where NSP-Minnesota has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota 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; and the other risk factors listed from time to time by NSP-Minnesota in reports filed with the SEC, including “Risk Factors” in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto.

Results of Operations

NSP-Minnesota’s net income was approximately $340 million for 2012, compared with approximately $353 million for 2011.  The decrease was primarily due to the unfavorable impact of warmer than normal winter weather during the first quarter, electric sales decline, higher property taxes, higher O&M expenses and depreciation expense.  These decreases were partially offset by the 2012 rate increase and a lower ETR.

Electric Revenues and Margin

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)	2012			2011
Electric revenues	$	3,843		$	3,773
Electric fuel and purchased power		(1,562	)		(1,543	)
Electric margin	$	2,281		$	2,230

28

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

Electric Revenues

(Millions of Dollars)	2012 vs. 2011
Retail rate increases (Minnesota, North Dakota and South Dakota)	$	26
Transmission revenue		22
Non-fuel riders		15
Interchange agreement billing with NSP-Wisconsin		9
Fuel and purchased power cost recovery		8
Conservation revenue (offset by expenses)		(11	)
Retail sales decrease, excluding weather impact		(8	)
Estimated impact of weather		(5	)
Other, net		14
Total increase in electric revenues	$	70

Electric Margin

(Millions of Dollars)	2012 vs. 2011
Retail rate increases (Minnesota, North Dakota and South Dakota)	$	26
Non-fuel riders		15
Transmission revenue, net of costs		10
Interchange agreement billing with NSP-Wisconsin		10
Trading		7
Conservation revenue (offset by expenses)		(11	)
Retail sales decrease, excluding weather impact		(8	)
Estimated impact of weather		(5	)
Other, net		7
Total increase in electric margin	$	51

Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases.  However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to 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)	2012			2011
Natural gas revenues	$	472		$	605
Cost of natural gas sold and transported		(287	)		(394	)
Natural gas margin	$	185		$	211

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

Natural Gas Revenues

(Millions of Dollars)	2012 vs. 2011
Purchased natural gas adjustment clause recovery	$	(105	)
Conservation revenue (offset by expenses)		(17	)
Estimated impact of weather		(11	)
Other, net		-
Total decrease in natural gas revenues	$	(133	)

29

Natural Gas Margin

(Millions of Dollars)	2012 vs. 2011
Conservation revenue (offset by expenses)	$	(17	)
Estimated impact of weather		(11	)
Other, net		2
Total decrease in natural gas margin	$	(26	)

Non-Fuel Operating Expenses and Other Items

O&M Expenses — O&M expenses increased $37.6 million, or 3.5 percent, for 2012 compared to 2011.  The following table summarizes the changes in O&M expenses for the year ended Dec. 31:

(Millions of Dollars)	2012 vs. 2011
Employee benefits	$	18
Prairie Island EPU		10
Consulting costs		6
Interchange agreement billing with NSP-Wisconsin		4
Information technology costs		3
Bad debt expense		(4	)
Other, net		1
Total increase in O&M expenses	$	38

· Higher employee benefits are mainly due to increased pension expense.

· See Item I – Business and Note 10 to the consolidated financial statements for further discussion of the Prairie Island EPU.

· Higher consulting costs are primarily due to outside legal services.

Conservation Program Expenses — Conservation program expenses decreased $28.0 million, or 20.3 percent, for 2012, compared with 2011.  The lower expenses are primarily attributable to lower gas rider rates, as well as the timing of recovery of electric CIP expenses.  Conservation program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.

Depreciation and Amortization — Depreciation and amortization increased $18.4 million, or 4.8 percent, for 2012, compared with 2011.  The increase is primarily due to a portion of the Monticello EPU going into service in May 2011 and normal system expansion.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $31.7 million, or 18.3 percent, for 2012, compared with 2011.  The increase was due to an increase in property taxes, primarily in Minnesota.

AFUDC — AFUDC decreased by $0.4 million for 2012 compared with 2011.  The decrease is primarily due to the Monticello EPU going into service in May 2011 and the Sherco Unit 3 uprate project, held for future service in 2011, partially offset by the life extension work at the Prairie Island nuclear generating plant.

Interest Charges — Interest charges decreased by $6.8 million, or 3.3 percent, for 2012, compared with 2011.  The decrease is due to lower interest rates, partially offset by higher long-term debt levels to fund investment in utility operations.

Income Taxes — Income tax expense decreased $16.1 million for 2012, compared with 2011. The decrease in income tax expense was primarily due to lower pretax earnings and a tax benefit associated with a carryback.   These were partially offset by increased state income taxes in 2012.   The ETR was 34.0 percent for 2012, compared with 35.2 percent for 2011. The lower ETR for 2012 was primarily due to the completion of an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result, NSP-Minnesota recognized a tax benefit of approximately $15 million.  This benefit was partially offset by higher state income taxes in 2012.

The ETR for 2012 differs from the statutory federal income tax rate, primarily due to state income tax expense partially offset by tax credits recognized, a tax benefit associated with a carryback, and tax benefit from plant-related regulatory differences.  The ETR for 2011 differs from the statutory federal income tax rate, 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.

30

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 that may occur as a result of adverse 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 adverse 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 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.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various 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.

At Dec. 31, 2012, the fair values by source for net commodity trading contract assets 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	$	7,207	$	16,207	$	1,251	$	1,201	$	25,866
		2		50		-		277		612		939
			$	7,257	$	16,207	$	1,528	$	1,813	$	26,805

Options

Maturity

Maturity

Source of

Less Than

Maturity

Maturity

Greater Than

Total Options

(Thousands of Dollars)

Fair Value

1 Year

1 to 3 Years

4 to 5 Years

5 Years

Fair Value

NSP-Minnesota

2

$

641

$

76

$

-

$

-

$

717

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

2 — Prices based on models and other valuation methods.

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)	2012			2011
Fair value of net commodity trading contract assets outstanding at Jan. 1	$	19,160		$	18,431
Contracts realized or settled during the period		(10,827	)		(9,034	)
Unrealized commodity trading transactions during the period		19,189			9,763
Fair value of net commodity trading contract assets outstanding at Dec. 31	$	27,522		$	19,160

31

At Dec. 31, 2012, a 10 percent increase in market prices for commodity trading contracts would increase pretax income from continuing operations by approximately $0.5 million, whereas a 10 percent decrease would decrease pretax income from continuing operations by approximately $0.5 million.  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 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
2012	$	0.45	$	3.00	$	0.36	$	1.56	$	0.06
2011		0.09		3.00		0.14		0.33		0.04

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.

In conjunction with the NSP-Minnesota debt issuance in August 2012, NSP-Minnesota settled interest rate hedging instruments with a notional amount of $225 million with cash payments of $45.0 million.  This loss is classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and is being reclassified to earnings over the term of the hedged interest payments.  See Note 4 for further discussion of long-term borrowings.

At Dec. 31, 2012 and 2011, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense annually by approximately $2.2 million and $0.9 million, respectively. 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, 2012, 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.  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.  Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, 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, 2012, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $10.2 million, while a decrease of 10 percent in prices would have resulted in an increase in credit exposure of $11.1 million.  At Dec. 31, 2011, a 10 percent increase in commodity 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.

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.

32

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 requires disclosure of the observability of the inputs used in these 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, 2012.  Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues.  Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.  NSP-Minnesota also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities.  The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2012.

Commodity derivative assets and liabilities assigned to Level 3 typically consist of FTRs, as well as forwards and options that are long-term in nature.  Level 3 commodity derivative assets and liabilities represent 1.1 percent and 3.9 percent of total assets and liabilities, respectively, measured at fair value at Dec. 31, 2012.

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 $17.5 million and $0.8 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2012.

Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility 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 immaterial Level 3 commodity forwards and no Level 3 options held at Dec. 31, 2012.

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 active market inputs are utilized to estimate the fair value of asset-backed and mortgage-backed securities.  However, less observable and subjective inputs that may be used in conjunction with available pricing of similar securities in active markets can be significant to these valuations.  These inputs include estimated principal prepayments and risk-based adjustments to the interest rate used to discount expected future cash flows in a discounted cash flow model.  Given the potential significant impacts that unobservable inputs may have on the valuations of asset-backed and mortgage-backed securities, and based on an evaluation of NSP-Minnesota’s ability to redeem private equity investments and real estate investment funds measured at net asset value, estimated fair values for these investments totaling $104.6 million in the nuclear decommissioning fund at Dec. 31, 2012 (approximately 6.7 percent of total assets measured at fair value), are assigned to Level 3.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a 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, 2012.  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, 2012, 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. 25, 2013	Feb. 25, 2013

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, 2012 and 2011, and the related consolidated statements of income, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012.  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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, 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

February 25, 2013

35

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2012			2011			2010
Operating revenues
Electric, non-affiliates	$	3,392,571		$	3,332,109		$	3,208,639
Electric, affiliates		449,958			440,519			416,076
Natural gas		471,765			604,723			589,044
Other		23,045			21,170			20,557
Total operating revenues		4,337,339			4,398,521			4,234,316
Operating expenses
Electric fuel and purchased power		1,562,286			1,542,760			1,536,076
Cost of natural gas sold and transported		287,152			393,672			399,524
Cost of sales — other		13,505			12,737			12,405
Operating and maintenance expenses		1,102,302			1,064,665			1,037,752
Conservation program expenses		109,989			138,001			86,298
Depreciation and amortization		399,432			381,025			401,136
Taxes (other than income taxes)		204,387			172,726			162,901
Total operating expenses		3,679,053			3,705,586			3,636,092
Operating income		658,286			692,935			598,224
Other income, net		979			1,717			1,151
Allowance for funds used during construction — equity		37,109			37,164			38,341
Interest charges and financing costs
Interest charges — includes other financing costs of
$5,972, $6,264, and $5,645, respectively		201,158			208,003			201,431
Allowance for funds used during construction — debt		(20,449	)		(20,817	)		(19,131	)
Total interest charges and financing costs		180,709			187,186			182,300
Income before income taxes		515,665			544,630			455,416
Income taxes		175,524			191,649			181,191
Net income	$	340,141		$	352,981		$	274,225

See Notes to Consolidated Financial Statements

36

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(amounts in thousands)

	Year Ended Dec. 31
	2012			2011			2010
Net income	$	340,141		$	352,981		$	274,225
Other comprehensive (loss) income
Pension and retiree medical benefits:
Net pension and retiree medical benefit gains arising during the period,
net of tax of $315, $97 and $68, respectively		460			140			99
Amortization of losses (gains) included in net periodic benefit cost,
net of tax of $106, $(362) and $(99), respectively		161			(528	)		(142	)
		621			(388	)		(43	)
Derivative instruments:
Net fair value decrease, net of tax of
$(6,885), $(11,422) and $(57), respectively		(9,889	)		(16,578	)		(80	)
Reclassification of losses (gains) to net income, net of tax of
$156, $(94) and $774, respectively		225			(128	)		1,116
		(9,664	)		(16,706	)		1,036
Marketable securities:
Net fair value increase (decrease), net of tax of
$135, $(63) and $89, respectively		196			(92	)		129
Other comprehensive (loss) income		(8,847	)		(17,186	)		1,122
Comprehensive income	$	331,294		$	335,795		$	275,347

See Notes to Consolidated Financial Statements

37

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(amounts in thousands)

	Year Ended Dec. 31
	2012			2011			2010
Operating activities
Net income	$	340,141		$	352,981		$	274,225
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		404,325			386,310			401,602
Nuclear fuel amortization		102,651			100,902			105,369
Deferred income taxes		239,981			196,120			251,747
Amortization of investment tax credits		(2,700	)		(2,694	)		(2,697	)
Allowance for equity funds used during construction		(37,109	)		(37,164	)		(38,341	)
Provision for bad debts		11,241			15,936			15,213
Prairie Island EPU		10,100			-			-
Net realized and unrealized hedging and derivative transactions		(53,881	)		(182	)		(8,784	)
Changes in operating assets and liabilities:
Accounts receivable		(214,886	)		(8,195	)		(24,216	)
Accrued unbilled revenues		1,639			18,090			(20,055	)
Inventories		41,090			(21,675	)		(24,254	)
Other current assets		(30,708	)		(614	)		(858	)
Accounts payable		(29,055	)		(33,806	)		(70,715	)
Net regulatory assets and liabilities		(15,416	)		75,390			18,575
Other current liabilities		33,727			91,532			39,899
Pension and other employee benefit obligations		(71,149	)		(39,925	)		(19,623	)
Change in other noncurrent assets		(14,465	)		(7,330	)		459
Change in other noncurrent liabilities		(552	)		(36,345	)		(23,250	)
Net cash provided by operating activities		714,974			1,049,331			874,296
Investing activities
Utility capital/construction expenditures		(1,172,403	)		(1,028,831	)		(1,208,268	)
Proceeds from insurance recoveries		97,835			-			-
Merricourt refund		-			101,261			-
Merricourt deposit		-			(90,833	)		(1,134	)
Allowance for equity funds used during construction		37,109			37,164			38,341
Purchases of investments in external decommissioning fund		(1,102,025	)		(2,098,642	)		(3,781,438	)
Proceeds from the sale of investments in external decommissioning fund		1,087,076			2,098,642			3,786,373
Investments in utility money pool arrangement		-			(432,000	)		(246,000	)
Repayments from utility money pool arrangement		-			432,000			253,000
Advances to affiliate		-			(111,300	)		(302,300	)
Advances from affiliate		-			148,300			280,800
Change in restricted cash		95,287			(95,287	)		-
Other, net		(3,507	)		(5,668	)		509
Net cash used in investing activities		(960,628	)		(1,045,194	)		(1,180,117	)
Financing activities
Issuances of short-term borrowings, net		195,000			26,000			-
Borrowings under utility money pool arrangement		1,147,000			627,600			711,000
Repayments under utility money pool arrangement		(1,212,000	)		(562,600	)		(711,000	)
Proceeds from issuance of long-term debt		786,363			-			493,390
Repayments of long-term debt, including reacquisition premiums		(648,874	)		(34	)		(175,034	)
Capital contributions from parent		215,110			125,004			212,794
Dividends paid to parent		(234,108	)		(232,510	)		(233,224	)
Net cash provided by (used in) financing activities		248,491			(16,540	)		297,926
Net change in cash and cash equivalents		2,837			(12,403	)		(7,895	)
Cash and cash equivalents at beginning of period		26,005			38,408			46,303
Cash and cash equivalents at end of period	$	28,842		$	26,005		$	38,408
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(187,671	)	$	(181,121	)	$	(172,463	)
Cash (paid) received for income taxes, net		(5,104	)		(15,964	)		81,836
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	125,948		$	35,058		$	59,836

See Notes to Consolidated Financial Statements

38

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	Dec. 31
	2012			2011
Assets
Current assets
Cash and cash equivalents	$	28,842		$	26,005
Restricted cash		-			95,287
Accounts receivable, net		325,143			314,577
Accounts receivable from affiliates		26,660			18,033
Accrued unbilled revenues		229,664			231,303
Inventories		260,758			301,848
Regulatory assets		156,223			141,709
Derivative instruments		56,232			51,517
Prepayments and other		94,019			45,219
Total current assets		1,177,541			1,225,498
Property, plant and equipment, net		9,546,968			8,982,834
Other assets
Nuclear decommissioning fund and other investments		1,514,156			1,357,538
Regulatory assets		1,039,675			872,014
Derivative instruments		66,480			80,689
Other		56,438			36,638
Total other assets		2,676,749			2,346,879
Total assets	$	13,401,258		$	12,555,211
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	2		$	450,000
Short-term debt		221,000			26,000
Borrowings under utility money pool arrangement		-			65,000
Accounts payable		367,021			322,979
Accounts payable to affiliates		69,739			47,651
Taxes accrued		175,929			158,319
Accrued interest		58,135			68,362
Dividend payable to parent		58,757			58,054
Derivative instruments		20,117			65,781
Regulatory liabilities		53,159			132,574
Other		102,915			164,736
Total current liabilities		1,126,774			1,559,456
Deferred credits and other liabilities
Deferred income taxes		1,944,910			1,666,005
Deferred investment tax credits		30,304			31,743
Asset retirement obligations		1,655,402			1,581,896
Regulatory liabilities		432,471			439,029
Pension and employee benefit obligations		422,496			413,755
Derivative instruments		174,471			184,190
Other		89,423			65,464
Total deferred credits and other liabilities		4,749,477			4,382,082
Commitments and contingencies
Capitalization
Long-term debt		3,488,638			2,888,897
Common stock – 5,000,000 shares authorized of $0.01 par value;
1,000,000 shares outstanding at Dec. 31, 2012 and 2011		10			10
Additional paid in capital		2,581,501			2,366,391
Retained earnings		1,478,057			1,372,727
Accumulated other comprehensive loss		(23,199	)		(14,352	)
Total common stockholder’s equity		4,036,369			3,724,776
Total liabilities and equity	$	13,401,258		$	12,555,211

See Notes to Consolidated Financial Statements

39

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

(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, 2009		1,000,000	$	10	$	2,028,593	$	1,210,894		$	1,712		$	3,241,209
Comprehensive income:
Net income								274,225						274,225
Other comprehensive income											1,122			1,122
Comprehensive income for 2010														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
Comprehensive income:
Net income								352,981						352,981
Other comprehensive loss											(17,186	)		(17,186	)
Comprehensive income for 2011														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
Comprehensive income:
Net income								340,141						340,141
Other comprehensive loss											(8,847	)		(8,847	)
Comprehensive income for 2012														331,294
Common dividends declared to parent								(234,811	)					(234,811	)
Contribution of capital by parent						215,110								215,110
Balance at Dec. 31, 2012		1,000,000	$	10	$	2,581,501	$	1,478,057		$	(23,199	)	$	4,036,369

See Notes to Consolidated Financial Statements

40

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CAPITALIZATION

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

	Dec. 31
	2012			2011
Long-Term Debt
First Mortgage Bonds, Series due:
Aug. 28, 2012, 8%	$	-		$	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
Sept. 1, 2019, 8.5% (a)		-			100,000
Aug. 15, 2022, 2.15%		300,000			-
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
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
Aug. 15, 2042, 3.4%		500,000			-
Other		2			8
Unamortized discount		(11,362	)		(8,011	)
Total		3,488,640			3,338,897
Less current maturities		2			450,000
Total long-term debt	$	3,488,638		$	2,888,897
Common Stockholder’s Equity
Common stock — 5,000,000 authorized shares of $0.01 par value,
1,000,000 shares outstanding at Dec. 31, 2012 and 2011, respectively	$	10		$	10
Additional paid in capital		2,581,501			2,366,391
Retained earnings		1,478,057			1,372,727
Accumulated other comprehensive loss		(23,199	)		(14,352	)
Total common stockholder’s equity	$	4,036,369		$	3,724,776

(a) Pollution control financing

See Notes to Consolidated Financial Statements

41

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, PPAs and fuel contracts to determine if the other party is a variable interest entity, if NSP-Minnesota has a variable interest and 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, 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 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.  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.

42

NSP-Minnesota has various rate-adjustment mechanisms in place that provide for the recovery of natural gas, electric fuel and purchased energy costs.  These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing 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, as well as residential rebates for participation in air conditioning interruption and energy-efficient appliances.

The costs incurred for CIP programs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost.  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 AFUDC.  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 a unit 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 that is to be early decommissioned is reclassified as plant to be retired.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable.  Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period.  For investments in property, plant and equipment that are not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss on abandonment is recognized, if necessary.

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, was approximately 2.9, 3.2 and 3.4 percent for the years ended Dec. 31, 2012, 2011 and 2010, respectively.

Leases — NSP-Minnesota evaluates a variety of contracts for lease classification at inception, including PPAs 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 certain wind and transmission projects, the MPUC has approved a more current recovery of the cost of capital associated with large capital projects, through various riders, resulting in a lower recognition of AFUDC.

43

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 AROs.  The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability.  See Note 11 for further discussion of AROs.

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 and other state commissions for approval.  NSP-Minnesota filed its most recent triennial nuclear decommissioning studies with the MPUC in December 2011 and received approval in December 2012.  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 studies consider estimated future costs of decommissioning and the market value of investments in trust funds, and recommend annual funding amounts.  Amounts collected in rates are deposited in the trust funds.  See Note 12 for further discussion of the approved nuclear decommissioning studies and funded amounts.  For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO as described above.

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 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 evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, 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.

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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. 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 which are recorded directly in equity by the 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 commodity trading transactions are recorded as a component of electric operating revenues; 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.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.

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 if designated 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.

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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 instruments 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.  NSP-Minnesota acquires RECs from the generation or purchase of renewable power.

When RECs are purchased or acquired in the course of generation 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 purchased or acquired in the course of generation 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.  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 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.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2012 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

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2.  Accounting Pronouncements

Recently Adopted

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 IFRSs (ASU No. 2011-04), which provides 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 requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota implemented the accounting and disclosure guidance effective Jan. 1, 2012, and the implementation did not have a material impact on its consolidated financial statements.  For required fair value measurement disclosures, see Notes 7 and 9.

Presentation of Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which requires the presentation of the components of net income, the components of OCI and total comprehensive income in either a single continuous financial statement of comprehensive income or in two separate, but consecutive financial 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 requirements were effective for interim and annual periods beginning after Dec. 15, 2011.  NSP-Minnesota implemented the financial statement presentation guidance effective Jan. 1, 2012.

Recently Issued

Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires 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.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01) to clarify the specific instruments and activities that should be considered in these disclosures.  These disclosure requirements 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 annual reporting periods.  NSP-Minnesota does not expect the implementation of this disclosure guidance to have a material impact on its consolidated financial statements.

Comprehensive Income Disclosures— In February 2013, the FASB issued Comprehensive Income (Topic 220) -– Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures of the amounts reclassified out of accumulated other comprehensive income.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements are effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting 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

(Thousands of Dollars)	Dec. 31, 2012			Dec. 31, 2011
Accounts receivable, net
Accounts receivable	$	345,563		$	337,581
Less allowance for bad debts		(20,420	)		(23,004	)
	$	325,143		$	314,577

(Thousands of Dollars)	Dec. 31, 2012		Dec. 31, 2011
Inventories
Materials and supplies	$	134,952	$	124,961
Fuel		80,307		113,711
Natural gas		45,499		63,176
	$	260,758	$	301,848

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(Thousands of Dollars)	Dec. 31, 2012			Dec. 31, 2011
Property, plant and equipment, net
Electric plant	$	12,322,677		$	11,948,041
Natural gas plant		1,027,632			1,006,163
Common and other property		493,322			525,139
Construction work in progress		951,199			639,246
Total property, plant and equipment		14,794,830			14,118,589
Less accumulated depreciation		(5,594,064	)		(5,433,106	)
Nuclear fuel		2,090,801			1,939,299
Less accumulated amortization		(1,744,599	)		(1,641,948	)
	$	9,546,968		$	8,982,834

4. Borrowings and Other Financing Instruments

Short-Term Borrowings

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.  The following tables present money pool borrowings for NSP-Minnesota:

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2012
Borrowing limit	$	250
Amount outstandingat period end		-
Average amount outstanding		49
Maximum amount outstanding		125
Weighted average interest rate, computed on a daily basis		0.33	%
Weighted average interest rate at end of period		N/A

(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	250		$	250		$	250
Amount outstandingat period end		-			65			-
Average amount outstanding		56			17			18
Maximum amount outstanding		236			80			142
Weighted average interest rate, computed on a daily basis		0.33	%		0.34	%		0.37	%
Weighted average interest rate at end of period		N/A			0.35			N/A

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended Dec. 31, 2012
Borrowing limit	$	500
Amount outstandingat period end		221
Average amount outstanding		160
Maximum amount outstanding		302
Weighted average interest rate, computed on a daily basis		0.39	%
Weighted average interest rate at end of period		0.39

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(Amounts in Millions, Except Interest Rates)	Twelve Months Ended Dec. 31, 2012			Twelve Months Ended Dec. 31, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	500		$	500		$	482
Amount outstandingat period end		221			26			-
Average amount outstanding		59			7			35
Maximum amount outstanding		302			80			389
Weighted average interest rate, computed on a daily basis		0.39	%		0.34	%		0.37	%
Weighted average interest rate at end of period		0.39			0.45			N/A

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, 2012 and 2011, there were $10.2 million and $7.7 million of letters of credit outstanding under the credit facility, respectively.  There were no letters of credit outstanding that were not issued under the credit facility at Dec. 31, 2012.  There were $1.1 million of letters of credit outstanding at Dec. 31, 2011 that were not issued under the credit facility.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

Credit Facility — 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 amount exceeding available capacity under this credit facility.  The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At Dec. 31, 2012, NSP-Minnesota had the following committed credit facility available (in millions):

	Credit Facility	Drawn (a)		Available
$	500.0	$	231.2	$	268.8

(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, 2012 and 2011.

Amended Credit Agreement — In July 2012, NSP-Minnesota entered into an amended five-year credit agreement with a syndicate of banks, replacing the previous four-year credit agreement. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with an improvement in pricing and an extension of maturity from March 2015 to July 2017. The Eurodollar borrowing margin on the line of credit was reduced from a range of 100 to 200 basis points per year, to a range of 87.5 to 175 basis points per year based on applicable long-term credit ratings. The commitment fees, calculated on the unused portion of the line of credit, were reduced from a range of 10 to 35 basis points per year, to a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

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.

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, 2012.  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.

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 2012, NSP-Minnesota issued $300 million of 2.15 percent first mortgage bonds due Aug. 15, 2022 and $500 million of 3.40 percent first mortgage bonds, due Aug. 15, 2042.

During the next five years, NSP-Minnesota has long-term debt maturities of $250 million due in 2015.

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Deferred Financing Costs— Other assets included deferred financing costs of approximately $30.6 million and $25.2 million, net of amortization, at Dec. 31, 2012 and 2011, 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 $1.3 billion and $1.2 billion in additional cash dividends on common stock at Dec. 31, 2012 and Dec. 31, 2011, respectively.

The most restrictive dividend limitation for NSP-Minnesota is imposed by its state regulatory commission.  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, 2012.  Total capitalization for NSP-Minnesota was $7.75 billion at Dec. 31, 2012, which did not exceed the limit of $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, 2012:

					Construction
	Plant in		Accumulated		Work in
(Thousands of Dollars)	Service		Depreciation		Progress		Ownership %
Electric Generation:
Sherco Unit 3	$	572,357	$	367,703	$	14,753		59.0	%
Sherco Common Facilities Units 1, 2 and 3		140,368		85,607		1,076		80.0
Sherco Substation		4,790		2,743		-		59.0
Electric Transmission:
Grand Meadow Line and Substation		11,204		1,086		-		50.0
CapX2020		254,905		57,334		214,412		55.0
Total	$	983,624	$	514,473	$	230,241

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.  Repairs to Sherco Unit 3 are expected to be substantially complete in 2013, followed by an extended period of commissioning and testing.  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 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 — 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.

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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 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in September 2013.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011.  As of Dec. 31, 2012, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

State Audits — NSP-Minnesotais a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Dec. 31, 2012, NSP-Minnesota’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2008.  As of Dec. 31, 2012, 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, 2012		Dec. 31, 2011
Unrecognized tax benefit - Permanent tax positions	$	2.8	$	3.3
Unrecognized tax benefit - Temporary tax positions		16.7		13.4
Total unrecognized tax benefit	$	19.5	$	16.7

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

(Millions of Dollars)	2012			2011			2010
Balance at Jan. 1	$	16.7		$	22.5		$	12.5
Additions based on tax positions related to the current year		1.7			6.5			7.3
Reductions based on tax positions related to the current year		(2.2	)		(0.8	)		(0.3	)
Additions for tax positions of prior years		6.4			4.9			3.5
Reductions for tax positions of prior years		(3.1	)		(0.9	)		(0.5	)
Settlements with taxing authorities		-			(15.5	)		-
Balance at Dec. 31	$	19.5		$	16.7		$	22.5

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 carryforwards are as follows:

(Millions of Dollars)	Dec. 31, 2012			Dec. 31, 2011
NOL and tax credit carryforwards	$	(16.8	)	$	(18.1	)

It is reasonably possible that NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  At this time, due to the uncertain nature of the audit process, an overall range of possible change cannot be reasonably estimated.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits for Dec. 31, 2012, 2011, and 2010 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2012, 2011 or 2010.

Federal Tax Loss Carryback Claims — NSP-Minnesota completed an analysis in the first quarter of 2012 on the eligibility of certain expenses that qualified for an extended carryback beyond the typical two-year carryback period.  As a result of a higher tax rate in prior years, NSP-Minnesota recognized a discrete tax benefit of approximately $15 million in the first quarter of 2012.

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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)	2012		2011
Federal NOL carryforward	$	394.0	$	564.7
Federal tax credit carryforwards		70.9		60.5
State tax credit carryforwards, net of federal detriment		2.0		1.9

The federal carryforward periods expire between 2021 and 2032.  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:

	2012			2011			2010
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
Tax credits recognized, net of federal income tax expense		(4.6	)		(5.0	)		(3.1	)
NOL carryback		(2.9	)		-			-
Regulatory differences — utility plant items		(1.6	)		(1.8	)		(2.0	)
Change in unrecognized tax benefits		(0.1	)		(0.1	)		0.3
State income taxes, net of federal income tax benefit		8.5			7.0			9.4
Medicare Part D		-			0.1			0.7
Other, net		(0.3	)		-			(0.5	)
Effective income tax rate		34.0	%		35.2	%		39.8	%

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

(Thousands of Dollars)	2012			2011			2010
Current federal tax (benefit) expense	$	(85,347	)	$	8,059		$	(87,554	)
Current state tax expense		19,593			3,055			17,845
Current change in unrecognized tax expense (benefit)		3,997			(12,891	)		1,850
Deferred federal tax expense		196,655			128,206			205,232
Deferred state tax expense		47,869			55,658			47,092
Deferred change in unrecognized tax (benefit) expense		(4,543	)		12,256			(577	)
Deferred investment tax credits		(2,700	)		(2,694	)		(2,697	)
Total income tax expense	$	175,524		$	191,649		$	181,191

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

(Thousands of Dollars)	2012			2011			2010
Deferred tax expense excluding items below	$	285,726		$	190,470		$	295,994
Tax benefit (expense) allocated to other comprehensive income
and other		6,172			11,841			(776	)
Amortization and adjustments to deferred income taxes
on income tax regulatory assets and liabilities		(51,917	)		(6,191	)		(43,471	)
Deferred tax expense	$	239,981		$	196,120		$	251,747

52

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

(Thousands of Dollars)	2012		2011
Deferred tax liabilities:
Difference between book and tax bases of property	$	2,108,983	$	1,892,655
Regulatory assets		149,531		121,300
Other		24,812		17,319
Total deferred tax liabilities	$	2,283,326	$	2,031,274
Deferred tax assets:
NOL carryforward	$	142,094	$	196,074
Tax credit carryforward		72,842		62,463
Employee benefits		33,357		18,280
Property tax		17,569		-
Deferred investment tax credits		13,487		14,096
Regulatory liabilities		13,135		12,732
Bad debts		8,352		9,381
Rate refund		968		29,499
Other		18,559		11,512
Total deferred tax assets	$	320,363	$	354,037
Net deferred tax liability	$	1,962,963	$	1,677,237

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 its 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 60 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements.  At Dec. 31, 2012, NSP-Minnesota had 1,996 bargaining employees 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 2013 and 2014.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical 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.

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.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan.  The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants.  The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans.  The total obligations of the SERP and nonqualified plan as of Dec. 31, 2012 and 2011 were $39.4 million and $54.8 million, respectively, of which $5.7 million and $5.7 million was attributable to NSP-Minnesota.   In 2012 and 2011, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $15.6 million and $5.7 million, respectively, of which $0.6 million and $0.5 million was attributable to NSP-Minnesota. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.

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 historical returns achieved by the 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 2012 were above the assumed level of 7.50 percent.  Investment returns in 2011 were below the assumed level of 8.00 percent while returns in 2010 were above the assumed level of 8.00 percent.  Xcel Energy Inc. and NSP-Minnesota continually review pension assumptions.  In 2013, NSP-Minnesota’s expected investment-return assumption is 7.25 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.  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:

	2012			2011
Domestic and international equity securities		29	%		31	%
Long-duration fixed income securities		30			26
Short-to-intermediate term fixed income securities		12			14
Alternative investments		27			26
Cash		2			3
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.

54

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, 2012 and 2011:

	Dec. 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	50,360	$	-		$	-	$	50,360
Derivatives		-		2,471			-		2,471
Government securities		-		59,541			-		59,541
Corporate bonds		-		158,535			-		158,535
Asset-backed securities		-		-			4,741		4,741
Mortgage-backed securities		-		-			13,472		13,472
Common stock		25,173		-			-		25,173
Private equity investments		-		-			54,091		54,091
Commingled funds		-		483,598			-		483,598
Real estate		-		-			21,978		21,978
Securities lending collateral obligation and other		-		(9,630	)		-		(9,630	)
Total	$	75,533	$	694,515		$	94,282	$	864,330

	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

The following tables present the changes in NSP-Minnesota’s Level 3 pension plan assets for the years ended Dec. 31, 2012, 2011 and 2010:

								Purchases,
			Net Realized		Net Unrealized			Issuances, and
(Thousands of Dollars)	Jan. 1, 2012		Gains (Losses)		Gains (Losses)			Settlements, Net			Dec. 31, 2012
Asset-backed securities	$	10,188	$	1,249	$	(1,744	)	$	(4,952	)	$	4,741
Mortgage-backed securities		24,413		588		(705	)		(10,824	)		13,472
Private equity investments		54,499		5,985		(7,724	)		1,331			54,091
Real estate		12,967		6		2,141			6,864			21,978
Total	$	102,067	$	7,828	$	(8,032	)	$	(7,581	)	$	94,282

55

									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
Private equity investments		43,027		1,354			4,196			5,922			54,499
Real estate		24,041		(219	)		6,416			(17,271	)		12,967
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
Private equity investments		26,622		(355	)		5,269			11,491			43,027
Real estate		21,630		(13	)		2,182			242			24,041
Total	$	111,548	$	5,280		$	1,907		$	(4,493	)	$	114,242

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)	2012			2011
Accumulated Benefit Obligation at Dec. 31	$	1,081,074		$	976,227
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	1,031,594		$	989,277
Service cost		29,411			28,016
Interest cost		49,813			51,946
Plan amendments		230			-
Actuarial loss		120,770			59,195
Benefit payments		(92,462	)		(96,840	)
Obligation at Dec. 31	$	1,139,356		$	1,031,594

(Thousands of Dollars)	2012			2011
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	783,529		$	792,854
Actual return on plan assets		93,679			46,140
Employer contributions		79,584			41,375
Benefit payments		(92,462	)		(96,840	)
Fair value of plan assets at Dec. 31	$	864,330		$	783,529

(Thousands of Dollars)	2012			2011
Funded Status of Plans at Dec. 31:
Funded status (a)	$	(275,026	)	$	(248,065	)

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

(Thousands of Dollars)	2012		2011
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	664,795	$	611,409
Prior service cost		12,266		24,085
Total	$	677,061	$	635,494

56

(Thousands of Dollars)	2012		2011
Amounts Related to the Funded Status of the Plans Have Been Recorded as
Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	46,071	$	51,427
Noncurrent regulatory assets		630,990		584,067
Total	$	677,061	$	635,494
Measurement date	Dec. 31, 2012		Dec. 31, 2011

	2012			2011
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		4.00	%		5.00	%
Expected average long-term increase in compensation level		3.75			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 2011 through January 2013:

· In January 2013, contributions of $191.5 million were made across four of Xcel Energy’s pension plans, of which $72.1 million was attributable to NSP-Minnesota;

· In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans, of which $79.6 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;

· For future years, Xcel Energy and NSP-Minnesota anticipate contributions will be made as necessary.

Plan Amendments — Xcel Energy, which includes NSP-Minnesota, amended the plan in 2012 to allow a one time transfer of a portion of qualifying obligations from the nonqualified pension plan into the qualified pension plans.  Xcel Energy and NSP-Minnesota also modified the benefit formula for nonbargaining and some bargaining new hires beginning in 2012 to a reduced benefit level.

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

(Thousands of Dollars)	2012			2011			2010
Service cost	$	29,411		$	28,016		$	26,736
Interest cost		49,813			51,946			53,929
Expected return on plan assets		(67,315	)		(74,241	)		(76,611	)
Amortization of prior service cost		11,819			13,169			11,726
Amortization of net loss		41,147			28,736			17,728
Net periodic pension cost	$	64,875		$	47,626		$	33,508
Costs not recognized due to effects of regulation		(34,917	)		(34,898	)		(27,027	)
Net benefit cost recognized for financial reporting	$	29,958		$	12,728		$	6,481

	2012			2011			2010
Significant Assumptions Used to Measure Costs:
Discount rate		5.00	%		5.50	%		6.00	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term rate of return on assets		7.50			8.00			8.00

57

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.  Amounts allocated to NSP-Minnesota were $10.8 million, $7.6 million and $5.8 million in 2012, 2011 and 2010, respectively.  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 2013 pension cost calculations is 7.25 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 to these plans for NSP-Minnesota were approximately $9.0 million in 2012, $8.6 million in 2011 and $8.8 million in 2010.

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, which includes NSP-Minnesota, 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 nonbargaining retirees has been funded into a sub-account of the Xcel Energy 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 assumptions 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, 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, correlation 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, 2012 and 2011:

	Dec. 31, 2012
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	1,105	$	-		$	-	$	1,105
Government securities		-		889			-		889
Insurance contracts		-		605			-		605
Corporate bonds		-		530			-		530
Asset-backed securities		-		-			9		9
Mortgage-backed securities		-		-			483		483
Commingled funds		-		2,764			-		2,764
Other		-		(567	)		-		(567	)
Total	$	1,105	$	4,221		$	492	$	5,818

58

	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

The following tables present the changes in NSP-Minnesota’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2012, 2011 and 2010:

								Purchases,
			Net Realized			Net Unrealized		Issuances, and
(Thousands of Dollars)	Jan. 1, 2012		Gains (Losses)			Gains (Losses)		Settlements, Net			Dec. 31, 2012
Asset-backed securities	$	119	$	(4	)	$	28	$	(134	)	$	9
Mortgage-backed securities		415		(9	)		57		20			483
Total	$	534	$	(13	)	$	85	$	(114	)	$	492

									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
Total	$	397	$	(26	)	$	26		$	137	$	534

								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
Total	$	1,551	$	(22	)	$	157	$	(1,289	)	$	397

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)	2012			2011
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	146,043		$	134,996
Service cost		96			87
Interest cost		7,129			7,372
Medicare subsidy reimbursements		748			739
Early Retiree Reinsurance Program proceeds shared with retirees		-			2,120
Plan amendments		(29,776	)		-
Plan participants’ contributions		5,216			5,997
Actuarial loss		13,706			14,295
Benefit payments		(18,176	)		(19,563	)
Obligation at Dec. 31	$	124,986		$	146,043

59

(Thousands of Dollars)	2012			2011
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	6,493		$	7,676
Actual return (loss) on plan assets		263			(69	)
Plan participants’ contributions		5,216			5,997
Employer contributions		12,022			12,452
Benefit payments		(18,176	)		(19,563	)
Fair value of plan assets at Dec. 31	$	5,818		$	6,493

(Thousands of Dollars)	2012			2011
Funded Status of Plans at Dec. 31:
Funded status	$	(119,168	)	$	(139,550	)
Current assets		-			332
Current liabilities		(3,893	)		(5,448	)
Noncurrent liabilities		(115,275	)		(134,434	)
Net postretirement amounts recognized on consolidated balance sheets	$	(119,168	)	$	(139,550	)

(Thousands of Dollars)	2012			2011
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	75,153		$	64,473
Prior service credit		(30,577	)		(918	)
Transition obligation		35			1,381
Total	$	44,611		$	64,936

(Thousands of Dollars)	2012		2011
Amounts Related to the Funded Status of the Plans Have Been Recorded as
Follows Based Upon Expected Recovery in Rates:
Current regulatory assets	$	1,134	$	4,426
Noncurrent regulatory assets		40,722		56,683
Deferred Income taxes		1,127		1,561
Net-of-tax accumulated comprehensive income		1,628		2,266
Total	$	44,611	$	64,936
Measurement date	Dec. 31, 2012		Dec. 31, 2011

	2012			2011
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		4.10	%		5.00	%
Mortality table	RP 2000			RP 2000
Health care costs trend rate - initial		7.50	%		6.31	%

Effective Dec. 31, 2012, the initial medical trend rate was increased from 6.3 percent to 7.5 percent.  The ultimate trend assumption was reduced from 5.0 percent to 4.5 percent.  The period until the ultimate rate is reached is seven years.  Xcel Energy Inc. 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	$	11,009	$	(8,850	)
Service and interest components		833		(670	)

60

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 $47.1 million and $49.0 million during 2012 and 2011, of which $12.0 million and $12.5 million were attributable to NSP-Minnesota.  Xcel Energy expects to contribute approximately $21.8 million during 2013, of which $9.7 million is attributable to NSP-Minnesota.

Plan Amendments — The 2011 decrease of the projected Xcel Energy and NSP-Minnesota postretirement health and welfare benefit obligation for plan amendments is due to changes in the participant co-pay structure for certain retiree groups and the elimination of dental and vision benefits for some nonbargaining retirees.  The 2012 decrease of the projected Xcel Energy and NSP-Minnesota postretirement health and welfare benefit obligation for plan amendments is due to the expected transition of certain participant groups to an external plan administrator.

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

(Thousands of Dollars)	2012			2011			2010
Service cost	$	96		$	87		$	72
Interest cost		7,129			7,372			7,956
Expected return on plan assets		(438	)		(576	)		(809	)
Amortization of transition obligation		1,346			1,346			1,346
Amortization of prior service cost		(117	)		(117	)		(117	)
Amortization of net loss		3,204			2,348			2,195
Net periodic postretirement benefit cost	$	11,220		$	10,460		$	10,643

	2012			2011			2010
Significant Assumptions Used to Measure Costs:
Discount rate		5.00	%		5.50	%		6.00	%
Expected average long-term rate of return on assets		6.75			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
2013	$	108,308	$	9,762	$	52	$	9,710
2014		97,570		9,535		46		9,489
2015		95,977		9,452		54		9,398
2016		97,368		9,322		52		9,270
2017		97,322		8,918		51		8,867
2018-2022		450,483		40,728		212		40,516

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.

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Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2012, 2011 and 2010. 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)	2012		2011		2010
Multiemployer plan contributions:
Pension	$	14,984	$	17,811	$	13,461
Other postretirement benefits		197		336		153
Total	$	15,181	$	18,147	$	13,614

8.  Other Income, Net

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

(Thousands of Dollars)	2012			2011			2010
Interest income	$	5,364		$	4,663		$	5,887
Other nonoperating income (expense)		825			969			(30	)
Insurance policy expense		(5,210	)		(3,915	)		(4,706	)
Other income, net	$	979		$	1,717		$	1,151

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 hierarchical 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 with proper notice.  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.  Based on NSP-Minnesota’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

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Investments in debt securities—  Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities, except for asset-backed and mortgage-backed securities, for which the third party service may also consider additional, more subjective inputs.  Since the impact of the use of these less observable inputs can be significant to the valuation of asset-backed and mortgage-backed securities, fair value measurements for these instruments have been assigned a Level 3.  Inputs that may be considered in the valuation of asset-backed and mortgage-backed securities in conjunction with pricing of similar securities in active markets include the use of risk-based discounting and estimated prepayments in a discounted cash flow model.  When these additional inputs and models are utilized, decreases in the risk-adjusted discount rates and any acceleration of  the assumed future principal prepayment rates each have the impact of increasing reported fair values for these instruments.

Interest rate derivatives— The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives— The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Electric commodity derivatives held by NSP-Minnesota include FTRs purchased from MISO.  FTRs purchased from MISO are financial instruments that entitle the holder to one year of monthly revenues or charges based on transmission congestion across a given transmission path.  The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path.   Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.  NSP-Minnesota’s valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease.  Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.  Monthly FTR settlements are included in the FCA, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability.  Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of NSP-Minnesota.

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.  The MPUC approved NSP-Minnesota’s proposed change in escrow fund investment strategy in September 2012.  The MPUC approved an asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.

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 $135.8 million and $79.8 million at Dec. 31, 2012 and 2011, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $46.4 million and $87.5 million at Dec. 31, 2012 and 2011, respectively.

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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, 2012 and 2011:

	Dec. 31, 2012
			Fair Value
(Thousands of Dollars)	Cost		Level 1		Level 2		Level 3		Total
Nuclear decommissioning fund (a)
Cash equivalents	$	246,904	$	237,938	$	8,966	$	-	$	246,904
Commingled funds		396,681		-		417,583		-		417,583
International equity funds		66,452		-		69,481		-		69,481
Private equity investments		27,943		-		-		33,250		33,250
Real estate		32,561		-		-		39,074		39,074
Debt securities:
Government securities		21,092		-		21,521		-		21,521
U.S. corporate bonds		162,053		-		169,488		-		169,488
International corporate bonds		15,165		-		16,052		-		16,052
Municipal bonds		21,392		-		23,650		-		23,650
Asset-backed securities		2,066		-		-		2,067		2,067
Mortgage-backed securities		28,743		-		-		30,209		30,209
Equity securities:
Common stock		379,093		420,263		-		-		420,263
Total	$	1,400,145	$	658,201	$	726,741	$	104,600	$	1,489,542

(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $24.6 million of miscellaneous investments.

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

(Thousands of Dollars)		Jan. 1, 2012		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			Dec. 31, 2012
Private equity investments	$	9,203	$	20,671	$	(1,931	)	$	5,307		$	33,250
Real estate		26,395		9,777		(3,611	)		6,513			39,074
Asset-backed securities		16,501		-		(14,450	)		16			2,067
Mortgage-backed securities		78,664		33,016		(79,899	)		(1,572	)		30,209
Total	$	130,763	$	63,464	$	(99,891	)	$	10,264		$	104,600

(Thousands of Dollars)		Jan. 1, 2011		Purchases		Settlements			Gains (Losses) Recognized as Regulatory Assets and Liabilities			Dec. 31, 2011
Private equity investments	$	-	$	9,203	$	-		$	-		$	9,203
Real estate		-		24,768		-			1,627			26,395
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
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

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class at Dec. 31, 2012:

	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	$	-	$	1,206	$	12,072	$	8,243	$	21,521
U.S. corporate bonds		-		31,932		87,659		49,897		169,488
International corporate bonds		-		4,165		10,556		1,331		16,052
Municipal bonds		-		-		3,739		19,911		23,650
Asset-backed securities		-		2,067		-		-		2,067
Mortgage-backed securities		-		-		748		29,461		30,209
Debt securities	$	-	$	39,370	$	114,774	$	108,843	$	262,987

Derivative Instruments Fair Value Measurements

NSP-Minnesota enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.

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, 2012, accumulated other comprehensive losses related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for any unsettled hedges.

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In conjunction with the NSP-Minnesota debt issuance in August 2012, NSP-Minnesota settled interest rate hedging instruments with a notional amount of $225 million with cash payments of $45.0 million.  This loss is classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and is being reclassified to earnings over the term of the hedged interest payments.  See Note 4 for further discussion of long-term borrowings.

Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various 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, natural gas for resale, and vehicle fuel.

At Dec. 31, 2012, NSP-Minnesota had various vehicle fuel related contracts designated as cash flow hedges extending through December 2016.  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, 2012 and 2011.

At Dec. 31, 2012, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses 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 revenues, 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, 2012 and 2011:

(Amounts in Thousands) (a)(b)	Dec. 31, 2012		Dec. 31, 2011
MWh of electricity		55,163	37,522
MMBtu of natural gas		26	7,290
Gallons of vehicle fuel		375	330

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

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

Consideration of Credit Risk and Concentrations — NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, 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 derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

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.

NSP-Minnesota’s most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.  At Dec. 31, 2012, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $51.5 million or 18 percent of this credit exposure at Dec. 31, 2012, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  The remaining two significant counterparties, comprising $10.0 million or 4 percent of this credit exposure at Dec. 31, 2012, were not rated by these agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.

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

(Thousands of Dollars)	2012			2011			2010
Accumulated other comprehensive (loss) income related to cash flow hedges at Jan. 1	$	(11,729	)	$	4,977		$	3,941
After-tax net unrealized losses related to derivatives accounted for as hedges		(9,889	)		(16,578	)		(80	)
After-tax net realized losses (gains) on derivative transactions reclassified into earnings		225			(128	)		1,116
Accumulated other comprehensive (loss) income related to cash flow hedges at Dec. 31	$	(21,393	)	$	(11,729	)	$	4,977

The following tables detail the impact of derivative activity during the years ended Dec. 31, 2012, 2011 and 2010, on accumulated other comprehensive income (loss), regulatory assets and liabilities, and income:

	Year Ended Dec. 31, 2012
	Pre-Tax Fair Value Gains (Losses)							Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:							into 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	$	(16,832	)		$	-			$	490	(a)		$	-			$	-
Vehicle fuel and other commodity		58				-				(109	) (e)			-				-
Total	$	(16,774	)		$	-			$	381			$	-			$	-
Other derivative instruments
Commodity trading	$	-			$	-			$	-			$	-			$	12,224	(b)
Electric commodity		-				44,162				-				(39,999	) (c)			-
Natural gas commodity		-				(2,662	)			-				16,158	(d)			-
Total	$	-			$	41,500			$	-			$	(23,841	)		$	12,224

	Year Ended Dec. 31, 2011
	Pre-Tax Fair Value Gains (Losses)							Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:							into 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
Commodity trading	$	-			$	-			$	-			$	-			$	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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	Year Ended Dec. 31, 2010
	Pre-Tax Fair Value Gains (Losses)							Pre-Tax (Gains) Losses Reclassified
	Recognized During the Period in:							into 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
Commodity trading	$	-			$	-			$	-			$	-			$	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) Amounts are recorded to interest charges.

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

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

(e) Amounts are recorded to O&M expenses.

NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2012, 2011 and 2010. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those recorded to the consolidated balance sheet at fair value, as well as those accounted for as normal purchase-normal sale (NPNS) contracts and therefore not reflected on the balance sheet, 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 of NSP-Minnesota were downgraded below investment grade, derivative instruments reflected in a $1.4 million gross liability position on the consolidated balance sheets at Dec. 31, 2011 would have required NSP-Minnesota to post collateral or settle outstanding contracts, including NPNS contracts, which would have resulted in payment of $0.1 million at Dec. 31, 2011, inclusive of the impacts of the offsetting asset positions with the applicable counterparties.  At Dec. 31, 2011, there was no collateral posted on these specific contracts. At Dec. 31, 2012, no derivative instruments in a liability position would have required the posting of collateral or settlement of outstanding contracts if the credit ratings of NSP-Minnesota were downgraded below investment grade.

Certain 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.  NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2012 and 2011.

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Recurring Fair Value Measurements — The following table presents, for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2012:

	Dec. 31, 2012
	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	$	-	$	52	$	-	$	52	$	-		$	52
Other derivative instruments:
Commodity trading		-		19,871		692		20,563		(3,374	)		17,189
Electric commodity		-		-		16,724		16,724		(843	)		15,881
Total current derivative assets	$	-	$	19,923	$	17,416	$	37,339	$	(4,217	)		33,122
Purchased power agreements (a)													23,110
Current derivative instruments												$	56,232
Noncurrent derivative assets
Derivatives designated as cash flow hedges:
Vehicle fuel and other commodity	$	-	$	47	$	-	$	47	$	(47	)	$	-
Other derivative instruments:
Commodity trading		-		37,513		76		37,589		(2,616	)		34,973
Total noncurrent derivative assets	$	-	$	37,560	$	76	$	37,636	$	(2,663	)		34,973
Purchased power agreements (a)													31,507
Noncurrent derivative instruments												$	66,480
Current derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	12,664	$	-	$	12,664	$	(6,400	)	$	6,264
Electric commodity		-		-		843		843		(843	)		-
Natural gas commodity		-		2		-		2		-			2
Total current derivative liabilities	$	-	$	12,666	$	843	$	13,509	$	(7,243	)		6,266
Purchased power agreements (a)													13,851
Current derivative instruments												$	20,117
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading	$	-	$	17,966	$	-	$	17,966	$	(2,664	)	$	15,302
Total noncurrent derivative liabilities	$	-	$	17,966	$	-	$	17,966	$	(2,664	)		15,302
Purchased power agreements (a)													159,169
Noncurrent derivative instruments												$	174,471

(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 PPAs 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 table presents, for each of the fair value hierarchy levels, NSP-Minnesota’s derivative assets and liabilities 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:
Commodity trading		-		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:
Commodity trading		-		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:
Commodity trading		-		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:
Commodity trading	$	-	$	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 PPAs 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, 2012, 2011 and 2010:

	Year Ended Dec. 31
(Thousands of Dollars)	2012			2011			2010
Balance at Jan. 1	$	12,417		$	2,392		$	27,237
Purchases		37,595			33,609			10,948
Settlements		(44,950	)		(36,552	)		(24,960	)
Transfers out of Level 3		-			-			(11,638	)
Net transactions recorded during the period:
Gains recognized in earnings (a)		463			66			4,719
Gains (losses) recognized as regulatory assets and liabilities		11,124			12,902			(3,914	)
Balance at Dec. 31	$	16,649		$	12,417		$	2,392

(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 years ended Dec. 31, 2012 and 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
Commodity trading 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, 2012 and 2011, other financial instruments for which the carrying amount did not equal fair value were as follows:

	2012				2011
	Carrying				Carrying
(Thousands of Dollars)	Amount		Fair Value		Amount		Fair Value
Long-term debt, including current portion	$	3,488,640	$	4,181,580	$	3,338,897	$	4,066,367

The fair value of NSP-Minnesota’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of Dec. 31, 2012 and 2011, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since those dates and current estimates of fair values may differ significantly.

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10.  Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — MPUC

Base Rate

NSP-Minnesota – Minnesota 2012 Electric Rate Case—  In November 2012, NSP-Minnesota filed a request with the MPUC for an increase in annual revenues of approximately $285 million, or 10.7 percent. The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent.

In December 2012, the MPUC accepted the filing as complete and approved the interim rates of approximately $251 million, as requested, effective Jan. 1, 2013, subject to refund.  In addition, the MPUC ordered NSP-Minnesota to file supplemental testimony regarding its ability to refinance additional debt and to discuss the effects of certain changes to its equity ratio.

The procedural schedule is as follows:

· Intervenor Direct Testimony – Feb. 28, 2013

· Rebuttal Testimony – March 25, 2013

· Surrebuttal Testimony – April 12, 2013

· Evidentiary Hearing – April 18 – 24, 2013

· Initial Brief – May 15, 2013

· Reply Brief and Findings of Fact – May 30, 2013

· ALJ Report – July 3, 2013

· MPUC Order – Anticipated by September 2013

NSP-Minnesota – Minnesota 2010 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, a requested ROE of 11.25 percent, an electric rate base of $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 August 2011, NSP-Minnesota submitted supplemental testimony, revising its requested rate increase to approximately $122 million for 2011 and an additional increase of approximately $29 million in 2012.

In November 2011, NSP-Minnesota reached a settlement agreement with certain customer intervenors.  In February 2012, NSP-Minnesota filed to reduce the interim rate request to $72.8 million to align with the settlement agreement.  In March 2012, the MPUC approved the settlement.  In May 2012, the MPUC issued an order approving the following:

· A rate increase of approximately $58 million in 2011 and an incremental rate increase of $14.8 million in 2012 based on an ROE of 10.37 percent and an equity ratio of 52.56 percent.

· A reduction to depreciation expense and NSP-Minnesota’s rate request by $30 million.

NSP-Minnesota filed its final rate implementation and interim rate refund compliance filing in June 2012, which the MPUC approved in August 2012.  Final rates were implemented Sept. 1, 2012, and interim refunds were completed during October 2012.

NSP-Minnesota – 2012 Transmission Cost Recovery Rate Filing —  In January 2012, the 2012 NSP-Minnesota TCR filing was submitted to the MPUC, requesting recovery of $29.6 million of transmission investment costs not included in base electric rates in the 2010 rate case settlement.  In 2012, the Minnesota Department of Commerce (DOC) recommended that the MPUC exclude $1.5 million of capitalized labor costs from the TCR, based on a prior MPUC decision in a TCR filing by another Minnesota utility, and added that the costs NSP-Minnesota has incurred for its share of the CapX2020 Bemidji project should be capped for TCR consideration at the level estimated in the CON application, plus reasonable escalation.  The DOC did not assert the costs are not recoverable in rates, but asserted the costs should not be eligible for recovery through the TCR adjustment mechanism.  The DOC’s position remained that the capitalized labor costs should not be recovered through the TCR and NSP-Minnesota estimates that the DOC positions, if approved by the MPUC, would result in granting NSP-Minnesota approximately $26.3 million in revenue requirements for 2012 under the TCR.  Final MPUC action is anticipated in the first half of 2013.

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Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a CON for an EPU project at the Prairie Island nuclear generating plant.  The total estimated cost of the EPU was $294 million, of which approximately $77.6 million has been incurred, including AFUDC of approximately $13.3 million.  Subsequently, NSP-Minnesota filed a resource plan update and a change of circumstances filing notifying the MPUC that there were changes in the size, timing and cost estimates for this project, revisions to economic and project design analysis and changes due to the estimated impact of revised scheduled outages.  The information indicated reductions to the estimated benefit of the uprate project.  As a result, NSP-Minnesota concluded that further investment in this project would not benefit customers.  In December 2012, the MPUC voted unanimously that no party had shown cause to prevent termination of the EPU CON.  The MPUC is expected to issue an order terminating the EPU CON in the first half of 2013.

NSP-Minnesota plans to address recovery of incurred costs in the next rate case for each of the NSP-Minnesota jurisdictions and to file a request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement.  NSP-Wisconsin plans to seek cost recovery in a future rate case.  Based on the outcome of the MPUC decision, EPU costs incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent, resulting in a $10.1 million pretax charge in December 2012 which is included in O&M expense.

Pending and Recently Concluded Regulatory Proceedings — NDPSC

NSP-Minnesota – North Dakota 2012 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC for an increase in annual retail electric revenues of approximately $16.9 million, or 9.25 percent.  The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent.

In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund.  A final NDPSC decision on the case is expected in the third quarter of 2013.

NSP-Minnesota – North Dakota 2010 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 12 percent, and a step increase of $4.2 million, or 2.6 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 $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.

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.  In February 2012, the NDPSC approved the settlement agreement, which provided for 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 the unknown timing of economic recovery and the effect on sales, the settlement includes a true-up to 2012 non-fuel revenues plus the settlement rate increase.  NSP-Minnesota implemented final rates in May 2012 and issued refunds in June 2012.

Pending and Recently Concluded Regulatory Proceedings — SDPUC

NSP-Minnesota – South Dakota 2012 Electric Rate Case—In June 2012, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $19.4 million annually.  The request was based on a 2011 historic test year adjusted for known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent.

In December 2012, the procedural schedule was suspended to allow time to construct a potential settlement agreement between NSP-Minnesota and the SDPUC Staff.  Interim rates of $19.4 million went into effect on Jan. 1, 2013, subject to refund.  A SDPUC decision is expected in the first half of 2013.

NSP-Minnesota – South Dakota 2011 Electric Rate Case — In June 2011, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $14.6 million annually, effective in 2012.  The request was 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.  On Jan. 2, 2012, interim rates of $12.7 million were implemented.  In June 2012, the SDPUC authorized a rate increase of approximately $8.0 million, based on an ROE of 9.25 percent, and an equity ratio of 53 percent.  Final rates became effective Aug. 1, 2012.  Interim rate refunds of $2.9 million were completed in September 2012.

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Electric, Purchased Gas and Resource Adjustment Incentive Clauses

CIP and CIP Rider —In December 2012, the MPUC approved reductions to the CIP financial incentive mechanisms effective for the 2013 through 2015 program years.  Based on the approved savings goals, the estimated average annual electric and natural gas incentives are $30.6 million and $3.6 million, respectively.

CIP expenses are recovered through base rates and a rider that is adjusted annually.  In December 2012, the MPUC approved NSP-Minnesota’s 2011 CIP financial incentives of $51.4 million for electric and $2.8 million for natural gas, and NSP-Minnesota’s 2013 electric and natural gas rider requests.  NSP-Minnesota estimates 2013 recovery of $54.7 million of electric CIP expenses and $12.6 million of natural gas CIP expenses.  This proposed recovery through the riders is in addition to an estimated $77.9 million and $3.7 million through electric and gas base rates, respectively.

11.  Commitments and Contingencies

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 EPU — NSP-Minnesota is pursuing capital improvements to enhance plant safety through the extended licensed life of the Monticello facility. Planned improvements are expected to result in capacity increases at the Monticello generating plant of up to approximately 71 MW. The MPUC approved the CON for the EPU for Monticello in 2008.  The license amendment application was filed with the NRC in November 2008.  NSP-Minnesota expects to receive approval of the EPU project by the NRC in the second half of 2013.  Pending approval by the NRC, NSP-Minnesota plans to implement the equipment changes needed to support the Monticello life extension and EPU projects during the planned spring 2013 refueling outage.  In addition to the Monticello projects, NSP-Minnesota is also implementing life cycle management improvements at the Prairie Island facilities to help ensure their safe and reliable operation through 2034.  The major capital investments for these activities at the Monticello and Prairie Island nuclear generating plants are expected to be completed in the years 2013 through 2017.

CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including NSP System that has 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 and on the allocation of costs borne by other participating utilities in the upper Midwest.

Fuel Contracts— NSP-Minnesota has entered into various long-term commitments 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 2013 and 2033.  NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements.

The estimated minimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2012, are as follows:

(Millions of Dollars)	Coal		Nuclear fuel		Natural gas supply		Natural gas storage and transportation
2013	$	300.1	$	92.3	$	55.5	$	95.9
2014		247.5		143.6		1.4		94.0
2015		207.6		86.5		1.4		91.0
2016		164.5		131.2		1.4		91.6
2017		153.9		128.9		0.7		77.4
Thereafter		155.9		830.2		-		250.4
Total (a)	$	1,229.5	$	1,412.7	$	60.4	$	700.3

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

Estimated coal requirements at Dec. 31, 2012 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.  Repairs to Sherco Unit 3 are expected to be substantially complete in 2013, followed by an extended period of commissioning and testing.  See Note 5 for further discussion.

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Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs.  NSP-Minnesota’s risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers with expiration dates through 2033 for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and to meet operating reserve obligations.  In general, these agreements provide for energy payments based on actual power taken under the contracts, as well as capacity payments.  Certain PPAs accounted for as executory contracts also contain minimum energy purchase commitments.  Capacity and energy 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 PPAs, accounted for as executory contracts, were payments for capacity of $106.2 million, $106.8 million and $109.3 million in 2012, 2011 and 2010, respectively.  At Dec. 31, 2012, the estimated future payments for capacity and energy that NSP-Minnesota is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:

(Millions of Dollars)	Capacity		Energy (a)
2013	$	108.3	$	77.0
2014		111.2		78.3
2015		106.3		83.7
2016		91.0		81.6
2017		84.7		87.3
Thereafter		449.0		959.9
Total (b)	$	950.5	$	1,367.8

(a) Excludes contingent energy payments for renewable energy PPAs.

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

Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.

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 $78.5 million, $72.9 million and $73.0 million for 2012, 2011 and 2010, respectively.  These expenses include capacity payments for PPAs accounted for as operating leases of $59.0 million, $58.2 million and $57.1 million in 2012, 2011 and 2010, respectively, recorded to electric fuel and purchased power expenses.

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

			Purchased		Total
	Operating		Power Agreement		Operating
(Millions of Dollars)	Leases		Operating Leases (a) (b)		Leases
2013	$	8.3	$	55.9	$	64.2
2014		7.1		56.8		63.9
2015		6.2		57.9		64.1
2016		6.1		58.8		64.9
2017		6.8		59.7		66.5
Thereafter		79.5		497.8		577.3

(a) Amounts do not include PPAs accounted for as executory contracts.

(b) PPA operating leases contractually expire through 2025.

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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.

PPAs — Under certain PPAs, 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 PPAs 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 PPAs.

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 PPAs as of Dec. 31, 2012 and 2011 with entities that have been determined to be variable interest entities.  These agreements have expiration dates through the year 2028.

Guarantees and Indemnifications

In connection with the acquisition of the 201 MW Nobles wind project in 2011, 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 had no assets held as collateral related to this agreement at Dec. 31, 2012 or 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 — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, 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 three sites, where former MGP activities have or may have resulted in 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 remediation.  NSP-Minnesota anticipates that the majority of the remediation at these sites will continue through at least 2014.  NSP-Minnesota had accrued $0.1 million for all of these sites at Dec. 31, 2012 and 2011.  There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred.  NSP-Minnesota anticipates that any amounts 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.  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.

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Environmental Requirements

EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare.  In 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 the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Minnesota’s power plants.

GHG New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the EPA proposed a GHG NSPS for newly constructed power plants.  The proposal requires that CO2 emission rates be equal to a natural gas combined-cycle plant, even if the plant is coal-fired.  The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and that installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program.  It is not possible to evaluate the impact of this regulation until its final requirements are known.

The EPA also plans to propose GHG regulations applicable to emissions from existing power plants under the CAA.  It is not known when the EPA will propose new standards for existing sources.

CSAPR — In 2011, the EPA issued the CSAPR to address long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States, including Minnesota.  The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule.  The rule also would have created an emissions trading program.

In August 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the CSAPR and remanded it back to the EPA.  The D.C. Circuit also stated that the EPA must continue administering the CAIR pending adoption of a valid replacement.  In October 2012, the EPA, as well as state and local governments and environmental advocates, petitioned the D.C. Circuit to rehear the CSAPR appeal.  In January 2013, the D.C. Circuit denied all requests for rehearing.  It is not yet known whether the D.C. Circuit’s decision will be appealed, or how the EPA might approach a replacement rule.  Therefore, it is not known what requirements may be imposed in the future.

Although the EPA continues to administer the CAIR while the CSAPR or a replacement rule is pending, the CAIR does not apply in Minnesota because the D.C. Circuit specifically found the EPA had not adequately justified the application of the CAIR in Minnesota.

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

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012.  The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date.  NSP-Minnesota expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects.  NSP-Minnesota believes these costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.

Minnesota Mercury Legislation — NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King generating plants and has obtained MPUC approval to install mercury controls on Sherco Units 1 and 2 by the end of 2014.  NSP-Minnesota projects installation costs of $9.0 million for the mercury controls on the units and believes these costs would be recoverable through regulatory mechanisms.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules, known as BART, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas.  NSP-Minnesota generating facilities are subject to BART requirements.  Individual states were required to identify the facilities located in their states that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities.

In 2009, the MPCA approved the SIP and submitted it 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 Reduction (SCR) should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA’s source-specific 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.  The scrubber upgrades are underway and scheduled to be completed by January 2015.

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The EPA’s preliminary review of the SIP in 2011 indicated that SCR controls should be added to Sherco Units 1 and 2.   Subsequently, the EPA and MPCA both determined that CSAPR meets BART requirements for purposes of the SIP.  In addition, the MPCA retained its source-specific BART determination for Sherco Units 1 and 2 from the 2009 SIP. The EPA approved the SIP for EGUs, and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the SIP, but avoided characterizing them as BART limits.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eight Circuit.  The Court denied intervention in the case to NSP-Minnesota and other regulated parties who petitioned to intervene.  It is not yet known how the D.C. Circuit’s reversal of the CSAPR may impact the EPA’s approval of the SIP.

The estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $31 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 through regulatory recovery mechanisms.  If the above litigation results in further EPA proceedings concerning SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

In addition to the regional haze rules, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program.  In 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 RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI or what that proposal will entail.  In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club.  The lawsuit alleges that the EPA has failed to perform a nondiscretionary duty to determine BART for the Sherco Units 1 and 2 under the RAVI program.  The EPA filed an answer denying the allegations and asserting that it did not have a nondiscretionary duty under the RAVI program.  NSP-Minnesota has asked the Court to allow it to intervene in this litigation.  The Court is expected to rule on NSP-Minnesota’s request by mid-March 2013.

Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM.  In areas where NSP-Minnesota operates power plants, current monitored air concentrations are below the level of the final annual primary standard.  The EPA is expected to designate non-compliant locations by December 2014.  States would then study the sources of the nonattainment and make emission reduction plans to attain the standards.  It is not possible to evaluate the impact of this regulation further until the final designations have been made.

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 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office.  The proposed rule is expected to be finalized in July 2013.  It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements.

NSP-Minnesota submitted its Black Dog CWA compliance plan for the MPCA’s review and approval in 2010.  The MPCA is currently reviewing the proposal in consultation with the EPA.

Proposed Coal Ash Regulation — NSP-Minnesota’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste.  In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste.  Coal ash is currently exempt from hazardous waste regulation.  NSP-Minnesota’s costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste.  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 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 alleges that various maintenance, repair and replacement projects 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, natural gas transmission and distribution and office buildings.  The steam production obligation includes asbestos, ash containment facilities, radiation sources and decommissioning.  The asbestos recognition associated with the steam production includes certain plants.  NSP-Minnesota also recorded asbestos recognition for its general office building.  This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  AROs also have been recorded for NSP-Minnesota steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.  The origination dates on the ARO recognition for ash-containment facilities at steam plants was 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 has also recorded AROs for the retirement and removal of assets at certain wind production facilities for which the land is leased and removal is required by contract, with the origination dates being the in-service date of the various facilities.

NSP-Minnesota has recognized AROs for the retirement costs of natural gas mains and for the removal of electric transmission and distribution equipment, which 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 numerous 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 NSP-Minnesota’s AROs is shown in the tables below for the years ended Dec. 31, 2012 and 2011, respectively:

	Beginning				Revisions			Ending
	Balance				to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2012		Accretion		Estimates			Dec. 31, 2012 (a)
Electric plant
Steam production asbestos	$	10,479	$	459	$	1,851		$	12,789
Steam production ash containment		30,989		1,065		15,872			47,926
Steam production radiation sources		42		3		-			45
Nuclear production decommissioning		1,482,741		75,301		(11,684	)		1,546,358
Wind production		40,515		2,068		(9,647	)		32,936
Electric transmission and distribution		15,700		570		(2,432	)		13,838
Natural gas plant
Gas transmission and distribution		295		18		-			313
Common and other property
Common general plant asbestos		1,135		62		-			1,197
Total liability	$	1,581,896	$	79,546	$	(6,040	)	$	1,655,402

(a) There were no new ARO liabilities recognized or settled during the 12 months ended Dec. 31, 2012.

The aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.5 billion as of Dec. 31, 2012, consisting of external investment funds.

In 2012, NSP-Minnesota incurred revisions for nuclear decommissioning, asbestos, ash-containment facilities, wind facilities and electric transmission and distribution AROs due to revised estimated cash flows.

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	Beginning				Revisions			Ending
	Balance				to Prior			Balance
(Thousands of Dollars)	Jan. 1, 2011		Accretion		Estimates			Dec. 31, 2011 (a)
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	(b)		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) There were no new ARO liabilities recognized or settled during the 12 months ended Dec. 31, 2011.

(b) 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 aggregate fair value of NSP-Minnesota’s legally restricted assets, for purposes of funding future nuclear decommissioning, was $1.3 billion as of Dec. 31, 2011, including external and internal investment funds.

In 2011, NSP-Minnesota incurred revisions for nuclear decommissioning, radiation sources, ash-containment facilities and electric transmission and distribution AROs due to revised estimated cash flows.

Removal Costs— NSP-Minnesota records a regulatory liability for the plant removal costs of steam and other 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, 2012 and 2011 were $377 million and $382 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 $16.5 million for business interruption insurance and $35.8 million for property damage insurance if losses exceed accumulated reserve funds.

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Legal Contingencies

NSP-Minnesota is involved in various litigation matters that are being defended and handled in the ordinary course of business.  The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation.  Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.  In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.  For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Minnesota’s financial statements.  Unless otherwise required by GAAP, legal fees are expensed as incurred.

Environmental 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 the 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 (Ninth Circuit).  In October 2012, the Ninth Circuit affirmed the U.S. District Court’s dismissal and subsequently rejected plaintiffs’ request for rehearing.  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.  Although, Xcel Energy Inc. believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — In May 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 the 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. and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.  Although Xcel Energy Inc. believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 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.  NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011.  In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements.  enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco’s lawsuit is without merit.  On Oct. 22, 2012, NSP-Minnesota filed a motion for summary judgment, with a hearing set for March 1, 2013.  If the U.S. District Court denies NSP-Minnesota’s motion, trial in this matter is expected to occur in 2013.  Although NSP-Minnesota believes the likelihood of loss is remote based primarily on existing case law, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

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Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the DOE’s failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota.  NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004.  In September 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million.  The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation.  NSP-Minnesota received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, and the third installment of $20.7 million in October 2012.  Amounts were subsequently credited to customers, except for approved reductions such as legal costs, customer credit amounts still in process at Dec. 31, 2012, and amounts set aside to be credited through another regulatory mechanism.

In NSP-Wisconsin’s 2012 Electric and Gas Rate Case, the PSCW authorized NSP-Wisconsin to utilize the proceeds from the second and third installments to be included as a reduction of the 2013 electric rate increase.  In December 2012, the MPUC approved NSP-Minnesota’s triennial nuclear decommissioning filing which required NSP-Minnesota to place the Minnesota retail portion of the DOE settlement payments for the third installment of $15.3 million and the anticipated fourth installment in 2013 into the nuclear decommissioning fund when received.  The SDPUC required NSP-Minnesota to credit the settlement funds to customers rather than apply the credits to the revenue requirement in the pending 2012 rate case.  South Dakota customers will receive credits for the third installment, beginning in February 2013.  NSP-Minnesota proposed to contribute the second, third and fourth installments to the nuclear decommissioning fund to offset the increase in the decommissioning accrual that was included in the 2012 North Dakota electric rate case. That filing is pending NDPSC action.

Other Contingencies

See Note 10 for further discussion.

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 $12 million in 2012, $11 million in 2011 and $13 million in 2010.  In total, NSP-Minnesota had paid approximately $434.2 million to the DOE through Dec. 31, 2012.  See Note 11 — Nuclear Waste Disposal Litigation for further discussion.

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 2091, 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.  The Monticello dry-cask storage facility currently stores 10 of the 30 canisters authorized by the MPUC.

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Prairie Island Units 1 and 2 received their initial operating license and began commercial operations in 1973 and 1974.  In 2011, the NRC approved Prairie Island’s license renewal application for its nuclear reactors, allowing operations for an additional 20 years until 2033 and 2034, respectively.  In 2011, the MPUC approved a depreciation life extension for Prairie Island 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.

NSP-Minnesota previously recorded annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding consistent with cost-recovery in utility customer rates.  Cost studies quantify decommissioning costs in current dollars.  This study presumed that costs will escalate in the future at a rate of 3.63 percent per year during operations and radiological portion of decommissioning and 2.63 percent during the independent spent fuel storage installation and site restoration portion of decommissioning.  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 an after-tax return between 4.57 percent and 5.53 percent, depending on production unit and time frame for external funding.  The net unrealized gain or loss on nuclear decommissioning investments is deferred as a regulatory asset or liability.

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.  In November 2012, the MPUC approved NSP-Minnesota’s most recent nuclear decommissioning study which used 2011 cost data.  The MPUC approved the use of a 60-year decommissioning scenario.  This resulted in an approved annual accrual for 2013 of $14.2 million for Minnesota retail customers to be offset by funds received in October 2012 of $15.3 million from the DOE settlement.

The external funds are held in trust and in escrow.  The portion in escrow is subject to refund if approved by the various commissions.  In 2009, the MPUC authorized the return of funds associated with the Monticello plant for the Minnesota retail jurisdictions with refunds made on customers’ bills in 2010.  In March 2010, approximately $5.9 million was also withdrawn from the Monticello plant portion of the escrow fund for a refund to Wisconsin and Michigan retail customers through general rates in 2011 and 2012.

As of Dec. 31, 2012, NSP-Minnesota has recorded and recovered in rates cumulative decommissioning expense of $1.5 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)	2012			2011
Estimated decommissioning cost obligation from most recently
approved study (2011 dollars for 2012 and 2008 dollars for 2011)	$	2,694,079		$	2,308,196
Effect of escalating costs (to 2012 and 2011 dollars, respectively,
at 3.63/2.63 percent for 2012 and 2.89 percent for 2011)		93,327			205,960
Estimated decommissioning cost obligation (in current dollars)		2,787,406			2,514,156
Effect of escalating costs to payment date (3.63/2.63 percent for 2012
and 2.89 percent for 2011)		5,793,882			2,602,207
Estimated future decommissioning costs (undiscounted)		8,581,288			5,116,363
Effect of discounting obligation (using risk-free interest rate)		(6,243,332	)		(3,187,914	)
Discounted decommissioning cost obligation		2,337,956			1,928,449
Assets held in external decommissioning trust		1,489,542			1,336,431
Underfunding of external decommissioning fund compared to
the discounted decommissioning obligation	$	848,414		$	592,018

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

(Thousands of Dollars)	2012			2011			2010
Annual decommissioning recorded as depreciation expense: (a)
Externally funded	$	-		$	-		$	934
Internally funded (including interest costs)		(1,251	)		(456	)		(777	)
Net decommissioning expense recorded	$	(1,251	)	$	(456	)	$	157

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

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Reductions to expense for internally-funded portions in 2012, 2011 and 2010 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).  Due to the immaterial amount remaining in the internal fund, the entire remaining amount was unwound for Prairie Island 1 and 2 in 2012.  As of December 2012, there is no balance remaining in the internally funded decommissioning account.  The 2011 nuclear decommissioning filing approved in 2012 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.

The components of regulatory assets shown on the consolidated balance sheets of NSP-Minnesota at Dec. 31, 2012 and 2011 are:

	See		Remaining
(Thousands of Dollars)	Note(s)		Amortization Period	Dec. 31, 2012				Dec. 31, 2011
Regulatory Assets				Current		Noncurrent		Current		Noncurrent
Pension and retiree medical obligations (a)		7	Various	$	23,131	$	367,578	$	20,836	$	312,260
Recoverable deferred taxeson AFUDC recorded in
plant		1	Plant lives		-		183,572		-		166,457
Net AROs (c)		1, 11, 12	Plant lives		-		115,877		-		136,941
Contract valuation adjustments (b)		1, 9	Term of related contract		2		127,661		13,498		118,403
Conservation programs (d)		1	One to two years		41,644		46,524		28,948		45,716
Nuclear refueling outage costs		1	One to two years		56,035		22,647		40,365		8,810
Renewable resources and environmental initiatives		11	One to two years		12,777		21,228		19,922		10,082
Purchased power contracts costs		11	Term of related contract		-		34,971		-		30,905
Losses on reacquired debt		4	Term of related debt		1,927		19,224		1,566		17,411
Recoverable purchased natural gas costs		1	One to two years		15,860		8,340		6,157		9,867
Gas pipeline inspection and remediation costs			Pending rate case		-		12,340		-		7,822
State commission adjustments		1	Plant lives		-		4,283		-		4,561
MISO Day 2 costs					-		-		3,276		-
Nuclear fuel storage		12	Two to four years		358		363		2,529		721
Prairie Island EPU (e)		10	Pending rate cases		-		67,590		-		-
Other			Various		4,489		7,477		4,612		2,058
Total regulatory assets				$	156,223	$	1,039,675	$	141,709	$	872,014

(a) Includes $330.3 million and $365.2 million for the regulatory recognition of pension expense of which $24.3 million and $35.2 million is included in the current asset at Dec. 31, 2012 and 2011, respectively.  Also included are $2.1 million and $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, 2012 and 2011, respectively.

(b) 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.

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

(d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

(e) For the cancelled Prairie Island EPU project, NSP-Minnesota plans to address recovery of incurred costs to date in the next rate case for each of the NSP-Minnesotajurisdictions and to file a request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement. In December 2012, EPU costs incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent, and as a result, NSP-Minnesota recognized a $10.1 million pretax charge.

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The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Minnesota at Dec. 31, 2012 and 2011 are:

	See		Remaining
(Thousands of Dollars)	Note(s)		Amortization Period	Dec. 31, 2012				Dec. 31, 2011
Regulatory Liabilities				Current		Noncurrent		Current		Noncurrent
Plant removal costs		1, 11	Plant lives	$	-	$	377,107	$	-	$	382,089
DOE Settlement		11	One to two years		17,071		1,131		80,249		-
Deferred income tax adjustment		1, 6	Various		-		29,715		-		31,518
Conservation programs (b)		1	Less than one year		1,823		-		5,382		-
Investment tax credit deferrals		1, 6	Various		-		22,821		-		23,802
Contract valuation adjustments (a)		1, 9	Term of related contract		25,139		-		20,976		-
Deferred electric energy costs		1	Less than one year		6,424		-		10,582		-
Renewable resources and environmental initiatives		10, 11	Less than one year		256		-		4,358		-
Other			Various		2,446		1,697		11,027		1,620
Total regulatory liabilities				$	53,159	$	432,471	$	132,574	$	439,029

(a) 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.

(b) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

At Dec. 31, 2012, approximately $115 million of NSP-Minnesota's regulatory assets represented past expenditures not currently earning a return.  This amount primarily includes Prairie Island EPU costs and recoverable purchased natural gas costs.

14.  Segments and Related Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Minnesota’s chief operating decision maker.  NSP-Minnesota evaluates performance 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 reportable segment.

NSP-Minnesota has the following reportable segments: regulated electric utility, regulated natural gas utility 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.

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	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
2012
Operating revenues	$	3,842,529	$	471,765	$	23,045	$	-		$	4,337,339
Intersegment revenues		532		608		-		(1,140	)		-
Total revenues	$	3,843,061	$	472,373	$	23,045	$	(1,140	)	$	4,337,339
Depreciation and amortization	$	360,224	$	38,776	$	432	$	-		$	399,432
Interest charges and financing cost		167,080		13,471		158		-			180,709
Income tax expense		161,450		9,516		4,558		-			175,524
Net income		314,853		17,389		7,899		-			340,141

	Regulated		Regulated		All			Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other			Eliminations			Total
2011
Operating revenues	$	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

	Regulated		Regulated		All		Reconciling			Consolidated
(Thousands of Dollars)	Electric		Natural Gas		Other		Eliminations			Total
2010
Operating revenues	$	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

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.

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.

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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)	2012		2011		2010
Operating revenues:
Electric	$	449,958	$	440,519	$	416,076
Gas		116		98		163
Operating expenses:
Purchased power		65,426		68,379		68,224
Transmission expense		59,918		55,955		48,088
Other operating expenses — paid to Xcel Energy Services Inc.		345,529		351,470		338,676
Interest expense		333		192		178
Interest income		18		92		69

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

	2012				2011
	Accounts		Accounts		Accounts		Accounts
(Thousands of Dollars)	Receivable		Payable		Receivable		Payable
NSP-Wisconsin	$	26,632	$	-	$	18,003	$	-
PSCo		-		23,214		-		11,623
SPS		-		3,820		-		1,314
Other subsidiaries of Xcel Energy Inc.		28		42,705		30		34,714
	$	26,660	$	69,739	$	18,033	$	47,651

16.  Summarized Quarterly Financial Data (Unaudited)

	Quarter Ended
(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
Operating revenues	$	1,076,773	$	972,536	$	1,185,400	$	1,102,630
Operating income		132,676		139,478		259,747		126,385
Net income		76,986		64,312		136,011		62,832

	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

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 the 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, 2012, 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.

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Internal Control 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, 2012 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.

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 2013 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, 2012.
	Report of Independent Registered Public Accounting Firm — Financial Statements
	Consolidated Statements of Income — For the three years ended Dec. 31, 2012, 2011 and 2010.
	Consolidated Statements of Comprehensive Income — For the three years ended Dec. 31, 2012, 2011 and 2010.
	Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2012, 2011 and 2010.
	Consolidated Balance Sheets — As of Dec. 31, 2012 and 2011.
2.	Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2012, 2011 and 2010.
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.

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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).
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. 001-31387) 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. 001-31387) 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)).
4.13*	Supplemental Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $300 million principal amount of 2.15 percent First Mortgage Bonds, Series due Aug. 15, 2022 and $500 million principal amount of 3.40 percent First Mortgage Bonds, Series due Aug. 15, 2042 (Exhibit 4.01 to NSP-Minnesota’s Form 8-K dated Aug. 13, 2012 (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).

89

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).
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) (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*+	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).
10.18*+	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).
10.19*+	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).
10.20*	Amended and Restated Credit Agreement, dated as of July 27, 2012 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 Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.02 to Form 8-K, dated July 27, 2012 (file no. 001-03034)).
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, 2012 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flow, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Stockholder’s Equity, (vi) Notes to Condensed Consolidated Financial Statements, and (vii) document and entity information

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SCHEDULE II

NSP-MINNESOTA AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2012, 2011 AND 2010

(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:
2012	$	23,004	$	11,241	$	5,874	$	19,699	$	20,420
2011		20,996		15,936		5,833		19,761		23,004
2010		22,675		15,213		5,805		22,697		20,996

(a) Recovery of amounts previously written off.

(b) Principally bad debts written off.

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SIGNATURES

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

	NORTHERN STATES POWER COMPANY
	/s/ TERESA S. MADDEN
	Teresa S. Madden
	Senior Vice President, Chief Financial Officer and Director
	(Principal Financial Officer)
Feb. 25, 2013

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
(Principal Executive Officer)	Chairman and Director
/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.

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