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Xcel Energy Inc – ‘10-K’ for 12/31/05

On:  Friday, 2/24/06, at 9:48pm ET   ·   As of:  2/27/06   ·   For:  12/31/05   ·   Accession #:  1104659-6-12011   ·   File #:  1-03034

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 2/27/06  Xcel Energy Inc                   10-K       12/31/05   15:5.2M                                   Merrill Corp-MD/FA

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report Pursuant to Section 13 and 15(D)      HTML   3.07M 
 2: EX-4.13     Amendment to the Credit Agreement Dated Nov. 4,     HTML     97K 
                          2005 Between Xcel and Various Lenders                  
 3: EX-4.48     Amendment to the Credit Agreement Dated April 21,   HTML     94K 
                          2005 Between Nsp-Mn and Various Lenders                
 4: EX-4.64     $50,000,000.00 Revolving Line of Credit Note        HTML     38K 
                          Between Psc-Co and Wells Fargo Bank                    
                          12/1/2005                                              
 5: EX-4.65     Amendment to the Credit Agreement Dated April 21,   HTML    118K 
                          2005 Between Psc-Co and Various Lenders                
 6: EX-10.37    Material Contracts                                  HTML     35K 
 7: EX-10.38    Material Contracts                                  HTML     20K 
 8: EX-12.01    Statements of Computation of Ratio of Earnings to   HTML     32K 
                          Fixed Charges                                          
 9: EX-21.01    Subsidiaries of the Xcel Enegy, Inc.                HTML     27K 
10: EX-23.01    Consents of Independent Auditors                    HTML     19K 
11: EX-24.01    Written Consent Resolution of the Board of          HTML     30K 
                          Directors of Xcel Energy Inc., Adopting                
                          Power of Attorney                                      
12: EX-31.01    302 Certification                                   HTML     16K 
13: EX-31.02    302 Certification                                   HTML     16K 
14: EX-32.01    906 Certification                                   HTML     15K 
15: EX-99.01    Statement Pursuant to Private Securities            HTML     14K 
                          Litigation Reform Act of 1995                          


10-K   —   Annual Report Pursuant to Section 13 and 15(D)
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Part I
"Company Overview
"Electric Utility Operations
"Electric Utility Trends
"NSP-Minnesota
"NSP-Wisconsin
"PSCo
"Sps
"Electric Operating Statistics
"Natural Gas Utility Operations
"Natural Gas Utility Trends
"Natural Gas Operating Statistics
"Environmental Matters
"Capital Spending and Financing
"Employees
"Executive Officers
"Item 1A -- Risk Factors
"Item 1B -- Unresolved Staff Comments
"Item 2 -- Properties
"Item 3 -- Legal Proceedings
"Item 4 -- Submission of Matters to a Vote of Security Holders
"Part Ii
"Item 5 -- Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
"Item 6 -- Selected Financial Data
"Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations
"Item 7A -- Quantitative and Qualitative Disclosures about Market Risk
"Item 9B -- Other Information
"Part Iii
"Item 12 -- Security Ownership of Certain Beneficial Owners and Management
"Item 14 -- Principal Accounting Fees and Services
"Part Iv
"Signatures

This is an HTML Document rendered as filed.  [ Alternative Formats ]



 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

ý

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

 

 

For the Fiscal Year Ended Dec. 31, 2005

 

 

Or

 

 

o

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

 

Commission File Number 1-3034

 

Xcel Energy Inc.

(Exact name of registrant as specified in its charter)

 

Minnesota

 

41-0448030

(State or Other Jurisdiction of Incorporation or Organization)

 

(I.R.S. Employer Identification No.)

 

 

 

800 Nicollet Mall, Minneapolis, Minnesota

 

55402

(Address of Principal Executive Offices)

 

(Zip Code)

 

Registrant’s Telephone Number, including Area Code (612) 330-5500

 

Securities registered pursuant to Section 12(b) of the Act:

 

Registrant

 

Title of Each Class

 

Name of Each Exchange on
Which Registered

 

 

 

 

 

Xcel Energy Inc.

 

Common Stock, $2.50 par value per share

 

New York, Chicago, Pacific

Xcel Energy Inc.

 

Rights to Purchase Common Stock, $2.50 par value per share Cumulative Preferred Stock, $100 par value:

 

New York, Chicago, Pacific

Xcel Energy Inc.

 

Preferred Stock $3.60 Cumulative

 

New York

Xcel Energy Inc.

 

Preferred Stock $4.08 Cumulative

 

New York

Xcel Energy Inc.

 

Preferred Stock $4.10 Cumulative

 

New York

Xcel Energy Inc.

 

Preferred Stock $4.11 Cumulative

 

New York

Xcel Energy Inc.

 

Preferred Stock $4.16 Cumulative

 

New York

Xcel Energy Inc.

 

Preferred Stock $4.56 Cumulative

 

New York

 

Securities registered pursuant to Section 12(g) of Act:      None

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ý Yes or No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ 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. ý

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). ý Large accelerated filer  o Accelerated filer  o Non-accelerated filer

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes or No ý

 

As of June 30, 2005, the aggregate market value of the voting common stock held by non-affiliates of the Registrant was $7,843,601,587 and there were 402,357,588 shares of common stock outstanding.

 

As of February 21, 2006, there were 403,814,069 shares of common stock outstanding, $2.50 par value.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

The Registrant’s Definitive Proxy Statement for its 2006 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

 

 



 

TABLE OF CONTENTS

 

Index

 

 

Glossary of Terms

 

 

 

 

 

PART I

 

 

Item 1 — Business

 

 

COMPANY OVERVIEW

 

 

ELECTRIC UTILITY OPERATIONS

 

 

Electric Utility Trends

 

 

NSP-Minnesota

 

 

NSP-Wisconsin

 

 

PSCo

 

 

SPS

 

 

Electric Operating Statistics

 

 

NATURAL GAS UTILITY OPERATIONS

 

 

Natural Gas Utility Trends

 

 

NSP-Minnesota

 

 

NSP-Wisconsin

 

 

PSCo

 

 

Natural Gas Operating Statistics

 

 

NONREGULATED SUBSIDIARIES

 

 

ENVIRONMENTAL MATTERS

 

 

CAPITAL SPENDING AND FINANCING

 

 

EMPLOYEES

 

 

EXECUTIVE OFFICERS

 

 

Item 1A – Risk Factors

 

 

Item 1B – Unresolved Staff Comments

 

 

Item 2 — Properties

 

 

Item 3 — Legal Proceedings

 

 

Item 4 — Submission of Matters to a Vote of Security Holders

 

 

PART II

 

 

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

 

 

Item 6 — Selected Financial Data

 

 

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

 

 

Item 7A — Quantitative and Qualitative Disclosures about Market Risk

 

 

Item 8 — Financial Statements and Supplementary Data

 

 

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

 

 

Item 9A — Controls and Procedures

 

 

Item 9B — Other Information

 

 

PART III

 

 

Item 10 — Directors and Executive Officers of the Registrant

 

 

Item 11 — Executive Compensation

 

 

Item 12 — Security Ownership of Certain Beneficial Owners and Management

 

 

Item 13 — Certain Relationships and Related Transactions

 

 

Item 14 — Principal Accounting Fees and Services

 

 

PART IV

 

 

Item 15 — Exhibits, Financial Statement Schedules

 

 

SIGNATURES

 

 



 

PART I

 

Item 1 — Business

 

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

 

Xcel Energy Subsidiaries and Affiliate (current and former)

 

 

BMG

 

Black Mountain Gas Co., a regulated natural gas and propane distribution company

Cheyenne

 

Cheyenne Light, Fuel and Power Company, a Wyoming corporation

Eloigne

 

Eloigne Co., invests in rental housing projects that qualify for low-income housing tax credits

NRG

 

NRG Energy, Inc., a Delaware corporation and independent power producer

NMC

 

Nuclear Management Co.

NSP-Minnesota

 

Northern States Power Co., a Minnesota corporation

NSP-Wisconsin

 

Northern States Power Co., a Wisconsin corporation

Planergy

 

Planergy International, Inc., an energy management solutions company

PSCo

 

Public Service Company of Colorado, a Colorado corporation

PSRI

 

PSR Investments, Inc.

SPS

 

Southwestern Public Service Co., a New Mexico corporation

UE

 

Utility Engineering Corporation, an engineering, construction and design company

Utility Subsidiaries

 

NSP-Minnesota, NSP-Wisconsin, PSCo, SPS

Viking

 

Viking Gas Transmission Co., an interstate natural gas pipeline company

WGI

 

WestGas Interstate, Inc., a Colorado corporation operating an interstate natural gas pipeline

Xcel Energy

 

Xcel Energy Inc., a Minnesota corporation

 

 

 

Federal and State Regulatory Agencies

 

 

ASLB

 

Atomic Safety and Licensing Board

CPUC

 

Colorado Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of PSCo’s operations in Colorado. The CPUC also has jurisdiction over the capital structure and issuance of securities by PSCo.

DOE

 

United States Department of Energy

DOL

 

United States Department of Labor

EPA

 

United States Environmental Protection Agency

FERC

 

Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas, and the sale of wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates.

IRS

 

Internal Revenue Service

MEQB

 

Minnesota Environmental Quality Board. Selects and designates sites for new power plants (capacity of 50MW or more), wind energy conversion plants (capacity of 5MW or more) and routes for electric transmission lines (capacity of 100KV or more) in Minnesota.

MPSC

 

Michigan Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Wisconsin’s operations in Michigan.

MPUC

 

Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.

 

3



 

NMPRC

 

New Mexico Public Regulation Commission. The state agency that regulates the retail rates and services and other aspects of SPS’ operations in New Mexico. The NMPRC also has jurisdiction over the issuance of securities by SPS.

NDPSC

 

North Dakota Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in North Dakota.

NRC

 

Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.

OCC

 

Colorado Office of Consumer Counsel

PSCW

 

Public Service Commission of Wisconsin. The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin’s operations in Wisconsin.

PUCT

 

Public Utility Commission of Texas. The state agency that regulates the retail rates, services and other aspects of SPS’ operations in Texas.

SDPUC

 

South Dakota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in South Dakota.

WDNR

 

Wisconsin Department of Natural Resources

WPSC

 

Wyoming Public Service Commission. The state agency that regulates Cheyenne’s facilities, rates, accounts, services and issuances of securities.

SEC

 

Securities and Exchange Commission

 

 

 

Fuel, Purchased Gas and Resource Adjustment Clauses

 

 

AQIR

 

Air-quality improvement rider. Recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.

DSM

 

Demand-side management. Energy conservation and weatherization program for low-income customers.

DSMCA

 

Demand-side management cost adjustment. A clause permitting PSCo to recover demand-side management costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. Costs for the low-income energy assistance program are recovered through the DSMCA.

ECA

 

Electric commodity adjustment. An incentive adjustment mechanism allowing PSCo to compare actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA then provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate.

FCA

 

Fuel clause adjustment. A clause included in NSP-Minnesota’s retail electric rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of electric fuel and purchased energy. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent three-month period.

GCA

 

Gas cost adjustment. Allows PSCo to recover its actual costs of purchased natural gas and natural gas transportation. The GCA is revised monthly to coincide with changes in purchased gas costs.

ICA

 

Incentive cost adjustment. A retail adjustment clause that allowed PSCo to equally share between electric customers and shareholders certain fuel and purchased energy costs. This clause expired Dec. 31, 2002. The collection of prudently incurred 2002 ICA costs was amortized over the period June 1, 2002, through March 31, 2005.

 

4



 

IAC

 

Interim adjustment clause. A retail adjustment clause that allowed PSCo to recover prudently incurred fuel and energy costs not included in electric base rates. The clause expired Dec. 31, 2003.

PCCA

 

Purchased capacity cost adjustment. Allows PSCo to recover from customers purchased capacity payments to power suppliers under specifically identified power purchase agreements that are not included in the determination of PSCo’s base electric rates or other recovery mechanisms. This clause will expire Dec. 31, 2006.

PGA

 

Purchased gas adjustment. A clause included in NSP-Minnesota’s and NSP-Wisconsin’s retail natural gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas and natural gas transportation. The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period.

QSP

 

Quality of service plan. Provides for bill credits to Colorado retail customers if PSCo does not achieve certain operational performance targets.

RCR

 

Renewable cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities and other costs incurred to facilitate the purchase of renewable energy (including wind energy) in retail electric rates in Minnesota. The RCR is revised annually.

SCA

 

Steam cost adjustment. Allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA is revised annually to coincide with changes in fuel costs.

 

 

 

Other Terms and Abbreviations

 

 

AFDC

 

Allowance for funds used during construction. Defined in regulatory accounts as a non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.

ALJ

 

Administrative law judge. A judge presiding over regulatory proceedings.

ARO

 

Asset Retirement Obligation

C20

 

Derivatives Implementation Group of FASB Implementation Issue No. C20. Clarified the terms clearly and closely related to normal purchases and sales contracts, as included in SFAS No. 133, as amended.

COLI

 

Corporate-owned life insurance

Decommissioning

 

The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.

Deferred energy costs

 

The amount of fuel costs applicable to service rendered in one accounting period that will not be reflected in billings to customers until a subsequent accounting period.

Derivative instrument

 

A financial instrument or other contract with all three of the following characteristics:

 

 

      An underlying and a notional amount or payment provision or both,

 

 

      Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and

 

 

      Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement

 

5



 

Distribution

 

The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.

EPS

 

Earnings per share of common stock outstanding

EWG

 

Exempt wholesale generator, as defined under PUHCA

ERISA

 

Employee Retirement Income Security Act

FASB

 

Financial Accounting Standards Board

FIN No. 46

 

FASB Interpretation No. 46(R) – Consolidation of Variable Interest Entities (revised December 2003)-an interpretation of Accounting Research Bulletin 51

FTRs

 

Financial Transmission Rights

GAAP

 

Generally accepted accounting principles

Generation

 

The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).

JOA

 

Joint operating agreement among the Utility Subsidiaries

LDC

 

Local distribution company. A company or division that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or natural gas for ultimate consumption.

LIBOR

 

London Interbank Offered Rate

LNG

 

Liquefied natural gas. Natural gas that has been converted to a liquid.

Mark-to-market

 

The process whereby an asset or liability is recognized at fair value.

MERP

 

Metropolitan Emissions Reduction Project

MGP

 

Manufactured gas plant

MISO

 

Midwest Independent Transmission System Operator, Inc.

Moody’s

 

Moody’s Investor Services Inc.

Native load

 

The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.

Natural gas

 

A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.

Nonutility

 

All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.

OMOI

 

FERC Office of Market Oversight and Investigations

PBRP

 

Performance-based regulatory plan. An annual electric earnings test, an electric quality of service plan and a natural gas quality of service plan established by the CPUC.

PFS

 

Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.

PJM

 

PJM Interconnection, LLC

PUHCA

 

Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies.

QF

 

Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.

Rate base

 

The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.

ROE

 

Return on equity

 

6



 

RTO

 

Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utility’s electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.

SFAS

 

Statement of Financial Accounting Standards

SMA

 

Supply margin assessment

SMD

 

Standard market design

SO2

 

Sulfur dioxide

SPP

 

Southwest Power Pool, Inc.

Standard & Poor’s

 

Standard & Poor’s Ratings Services

TEMT

 

Transmission and Energy Markets Tariff

TRANSLink

 

TRANSLink Transmission Co., LLC

Unbilled revenues

 

Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.

Underlying

 

A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.

VaR

 

Value-at-risk

Wheeling or Transmission

 

An electric service wherein high-voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.

Working capital

 

Funds necessary to meet operating expenses.

 

 

 

Measurements

 

 

Btu

 

British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.

Bcf

 

Billion cubic feet

Dth

 

Dekatherm (one Dth is equal to one MMBtu)

kV

 

Kilovolts

kW

 

Kilowatts (one kW equals one thousand watts)

kWh

 

Kilowatt hours

Mcf

 

Thousand cubic feet

MMBtu

 

One million BTUs

MW

 

Megawatts (one MW equals one thousand KW)

Mwh

 

Megawatt hour (one Mwh equals one thousand Kwh)

Watt

 

A measure of power production or usage.

Volt

 

The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts or kV.

 

7



 

COMPANY OVERVIEW

 

Xcel Energy is a holding company, with subsidiaries engaged primarily in the utility business.  In 2005, Xcel Energy’s continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin.  Along with WGI, an interstate natural gas pipeline company, these companies comprise our continuing regulated utility operations

 

Xcel Energy’s nonregulated subsidiaries in continuing operations include Eloigne and Planergy International, Inc.  Planergy International, Inc. closed and began selling a majority of its business operations in 2003 with all operations ceasing in 2004.

 

Discontinued utility operations include the activity of Viking, which was sold in January 2003; BMG, which was sold in October 2003; and Cheyenne, which was sold in January 2005.

 

In April 2005, Zachry Group, Inc. acquired all of the outstanding shares of UE, a nonregulated subsidiary.  In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration projects that was not included in the sale of UE to Zachry.  As a result, Xcel Energy is reporting UE and Quixx as components of discontinued operations for all periods presented.

 

During 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc.   On Nov. 3, 2005, Xcel Energy completed the sale of Seren’s California assets to WaveDivision Holdings, LLC.  On Jan. 9, 2006, Xcel Energy completed the sale of Seren’s Minnesota assets to Charter Communications.

 

During 2003, Xcel Energy divested its ownership interest in NRG.  On May 14, 2003, NRG filed for bankruptcy to restructure their debt.  As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG.  Xcel Energy made payments of $752 million to NRG in 2004.  During 2003, the board of directors of Xcel Energy also approved management’s plan to exit certain businesses conducted by the nonregulated subsidiaries Xcel Energy International Inc. and e prime inc.  NRG, Xcel Energy International, e prime, Seren, UE and Quixx are accounted for as components of discontinued operations.

 

For more information regarding Xcel Energy’s discontinued operations, see Note 2 to the Consolidated Financial Statements.

 

Historically, Xcel Energy has been a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA).  As a registered holding company, Xcel Energy, its utility subsidiaries and certain of its non-utility subsidiaries have been subject to extensive regulation by the SEC under PUHCA with respect to numerous matters, including issuances and sales of securities, acquisitions and sales of certain utility properties, payments of dividends out of capital and surplus, and intra-system sales of certain non-power goods and services.  In addition, the PUHCA generally limited the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.

 

On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), significantly changing many federal statutes and repealing PUHCA as of February 8, 2006.  As part of the repeal of PUHCA, FERC was given more authority over the merger and acquisition of public utilities and more authority over the books and records of public utilities.  Despite these increases in FERC’s authority, Xcel Energy believes that the repeal of PUHCA will lessen its regulatory burdens and give it more flexibility in the event it were to choose to expand its utility or non-utility businesses.

 

Besides repealing PUHCA, the Energy Act is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and DOE.  FERC and DOE are in various stages of rulemaking in implementing the Energy Act.  While the precise impact of these rulemakings cannot be determined at this time, Xcel Energy generally views the Energy Act as legislation that will enhance the utility industry going forward.

 

Xcel Energy was incorporated under the laws of Minnesota in 1909Xcel Energy’s executive offices are located at 800 Nicollet Mall, Minneapolis, Minn. 55402.  Its Web site address is www.xcelenergy.com.  Xcel Energy makes available, free of charge through its Web site, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC.  In addition,

 

8



 

the Xcel Energy Guidelines on Corporate Governance and Code of Conduct also are available on its Web site.

 

NSP-Minnesota

 

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota.  Prior to 2000, the regulated utility operations currently conducted by NSP-Minnesota were conducted by the legal entity now operating under the name Xcel Energy.  NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota.  The wholesale customers served by NSP-Minnesota comprised approximately X percent of the total Kwh sales in 2005.  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 1.3 million customers and gas utility service to approximately 0.5 million customers.

 

The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin.  A FERC-approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the NSP System, including capital costs.

 

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; and NSP Nuclear Corp., which holds NSP-Minnesota’s interest in the NMC.  NSP Financing I, a former special purpose financing trust of NSP-Minnesota, was dissolved in September 2003.

 

NSP-Wisconsin

 

NSP-Wisconsin was incorporated in 1901 under the laws of Wisconsin.  NSP-Wisconsin is an operating utility engaged in the generation, transmission and distribution of electricity to approximately 242,000 customers in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan.  The wholesale customers served by NSP-Wisconsin comprised approximately 8 percent of NSP-Wisconsin’s total Kwh sales in 2005.  NSP-Wisconsin also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in the same service territory to approximately 98,000 customers.  See the discussion of the integrated management of the electric production and transmission system of NSP-Wisconsin under NSP-Minnesota, discussed previously.

 

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

 

PSCo

 

PSCo was incorporated in 1924 under the laws of Colorado. PSCo is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity.  PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas.  PSCo serves approximately 1.3 million electric customers and approximately 1.2 million natural gas customers in Colorado.  The wholesale customers served by PSCo comprised approximately 23 percent of PSCo’s total Kwh sales in 2005.

 

PSCo owns the following direct subsidiaries: 1480 Welton, Inc., which owns certain real estate interests for PSCo; PSRI, which owns and manages permanent life insurance policies on certain current and former employees; and Green and Clear Lakes Company, which owns water rights. PSCo also holds a controlling interest in several other relatively small ditch and water companies whose capital requirements are not significant.  PSCo Capital Trust I, a former special purpose financing trust of PSCo, was dissolved in December 2003.

 

SPS

 

SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity. SPS serves approximately 395,000 electric customers in portions of Texas, New Mexico, Oklahoma and Kansas. The wholesale customers served by SPS comprised approximately 38 percent of SPS’s total Kwh sales in 2005.  A major portion of SPS’ retail electric operating revenues is derived from operations in Texas.  In October 2005, SPS reached a definitive agreement to sell its delivery system operations in Oklahoma, Kansas and a small portion of Texas to Tri-County Electric Cooperative.  The transaction, subject to regulatory approvals, is expected to

 

9



 

be completed in 2006.  Southwestern Public Service Capital I, a former special purpose financing trust of SPS, was dissolved in January 2004.

 

Other Regulated Subsidiaries

 

WGI was incorporated in 1990 under the laws of Colorado. WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to the Cheyenne system near Cheyenne, Wyo.

 

See financial information regarding the segments of Xcel Energy’s business at Note 17 to the Consolidated Financial Statements.

 

ELECTRIC UTILITY OPERATIONS

 

Electric Utility Trends

 

Overview

 

Utility Industry Growth — Xcel Energy intends to focus on growing through investments in electric and natural gas rate base to meet growing customer demands and to maintain or increase reliability and quality of service to customers.  Xcel Energy will file rate cases with state and federal regulators to earn a return on its investments and recover costs of operations.

 

Utility Restructuring and Retail Competition — The structure of the utility industry has been subject to change.  Merger and acquisition activity has been significant as utilities combined to capture economies of scale or establish a strategic niche in preparing for the future.  Some states have implemented some form of retail electric utility competition.  Much of Texas has implemented retail competition, but it is presently limited to utilities within the Electric Reliability Council of Texas, which does not include SPS.  Under current law, SPS can file a plan to implement competition, subject to regulatory approval, in Texas on or after Jan. 1, 2007.  However, SPS has no plan to implement retail competition in its service area.  In 2002, NSP-Wisconsin began providing its Michigan electric customers with the opportunity to select an alternative electric energy provider.  To date, no NSP-Wisconsin customers have selected an alternative electric energy provider.

 

The retail electric business does face some competition as industrial and large commercial customers have some 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 or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  While each of Xcel Energy’s Utility Subsidiaries face these challenges, these subsidiaries believe their rates are competitive with currently available alternatives.

 

Summary of Recent Federal Regulatory Developments

 

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, accounting practices and certain other activities of Xcel Energy’s Utility Subsidiaries.  State and local agencies have jurisdiction over many of Xcel Energy’s activities, including regulation of retail rates and environmental matters.

 

FERC Rules Implementing Energy Act - The Energy Act repealed PUHCA effective Feb. 8, 2006.  In addition, the Energy Act required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act.  Since Aug. 2005, the FERC has completed or initiated the proceedings to modify its regulations on a number of subjects, including:

 

      Adopting new regulations to implement the Energy Act repeal of PUHCA by establishing rules for accounting procedures for holding company systems, including cost allocation rules for transactions between companies within a holding company system;

      Adopting new regulations to implement changes to the FERC’s merger and asset transfer authority under Section 203 of the Federal Power Act;

      Adopting new “market manipulation regulations” prohibiting any “manipulative or deceptive device or contrivance” in wholesale natural gas and electricity commodity and transportation or transmission markets and interpreting this standard in a manner consistent with Rule 10b-5 of the SEC; violations are subject to potential civil penalties of up to $1 million per day;

      Adopting regulations to establish a national Electric Reliability Organization (ERO) to replace the voluntary North American Electric Reliability Council (NERC) structure, and requiring the ERO to establish mandatory reliability

 

10



 

standards and imposition of financial or other penalties for violations of adopted standards; NERC is expected to apply to become designated as the ERO later in 2006;

      Adopting rules to implement changes to the Public Regulatory Policy Act of 1978 (PURPA) to allow utility ownership of Qualifying Facilities (QFs) and strengthening the thermal energy requirements for entities seeking to be QFs;

      Proposing rules that would allow a utility to seek to eliminate its mandatory QF power purchase obligation for utilities in organized wholesale energy markets;

      Proposing rules to establish incentives for investment in new electric transmission infrastructure.

 

Xcel Energy cannot predict the ultimate impact the new regulations will have on its operations or financial results.

 

Market-Based Rate Authority — The FERC regulates the wholesale sale of electricity.  In order to obtain market-based rate authorization from the FERC, utilities are required to submit analyses demonstrating whether they have market power in the relevant markets.  Xcel Energy and its utility subsidiaries were previously granted market-based rate authority by the FERC.  However, the FERC has subsequently modified its standards making it more difficult for utilities to demonstrate that they do not have market power and thus more difficult to obtain market-based rate authority, particularly in their own service territories.

 

On Feb. 7, 2005, Xcel Energy on behalf of itself and the utility subsidiaries filed an updated market-power analysis that applied FERC’s new standards.  This analysis demonstrated that all of the Utility Subsidiaries, with the exception of PSCo, passed the pivotal supplier analysis in their own control areas and all adjacent markets, but that all failed the market share analysis in their own control areas, and in the case of NSP-Minnesota and NSP-Wisconsin, which jointly operate a single control area and accordingly are analyzed as one company, in certain adjacent markets.

 

In June 2005, the FERC initiated a proceeding to investigate PSCo’s and SPS’ market-based rate authority within their own control areas.  The refund effective date that has been set as part of that investigation for such sales is Aug. 12, 2005.  Because of the commencement of the MISO Day 2 market, and the FERC’s decision consistent with other precedent to analyze NSP-Minnesota and NSP-Wisconsin as part of that larger market, the FERC is not addressing NSP-Minnesota’s and NSP-Wisconsin’s market power in that investigation. The FERC did require that Xcel Energy make a compliance filing providing information, including information regarding the FERC’s affiliate abuse component of its market power analysis and the allegations regarding that component made by an intervenor within 30 days of the date of issuance of its order.  The latter compliance filing was submitted on July 5, 2005.

 

On Aug. 1, 2005, SPS and PSCo submitted a filing to withdraw their market-based rate authority with respect to sales within their control areas.  SPS and PSCo proposed to charge existing cost-based rates for sales into the SPS and PSCo control areas.  In October 2005, PSCo and SPS filed revised tariff sheets to reflect that limitation on their market-based rate authority.  Certain intervenors are still contending that the FERC must hold an investigation regarding SPS’ market power and the rates that SPS is proposing to charge where it has relinquished market-based rate authority.  The matter is pending before the FERC.

 

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to an RTO.  NSP-Minnesota and NSP-Wisconsin are members of the MISO, which began RTO operations in early 2002.  SPS is a member of the SPP, which proposes to begin RTO operations on May 1, 2006.  SPS has been a member of SPP’s regional transmission tariff since 2001.  Each RTO separately files for regional transmission tariff rates for approval by FERC.  All members within that RTO are then subjected to those rates.  SPS has not yet filed for state regulatory authorization in New Mexico to transfer functional control of its transmission system to the SPP RTO.  PSCo is currently participating with other utilities in the development of an RTO.

 

Centralized Regional Wholesale Markets – FERC rules require RTO’s to operate centralized regional wholesale energy markets.  The FERC required the MISO to begin operation of a “Day 2” energy market on April 1, 2005.  MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTR’s.  The Day 2 market is intended to provide more efficient generation dispatch over the 15 state MISO region.

 

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NSP-Minnesota

 

Ratemaking Principles

 

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, property transfers, mergers and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans for meeting customers’ future energy needs. The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV.

 

The MPUC is also empowered to select and designate sites for new power plants with a capacity of 50 MW or more and wind energy conversion plants with a capacity of five MW or more. It also designates routes for electric transmission lines with a capacity of 100 KV or more. No 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 the need for certain generating and transmission facilities, and the siting and routing of certain 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, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion) and is a transmission-owner member of the MISO RTO.

 

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA that provides for monthly adjustments to billings and revenues 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 individually approved by the regulators in each jurisdiction.  The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers.  With NSP-Minnesota’s participation in the MISO Day 2 market, questions have been raised regarding the inclusion of certain MISO charges in the FCA.  For further discussion, see NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings – MPUC.  In general, capacity costs are not recovered through the FCA.  NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

 

NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue on conservation improvement programs.  These costs are recovered through an annual cost recovery mechanism for electric conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

 

Performance-Based Regulation — In December 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant.  All three plants are located in the Minneapolis - St. Paul metropolitan area. These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW. The projects are expected to come on line between 2007 and 2009, at a cumulative investment of approximately $1 billion.  The MPUC approved a rate rider to recover prudent costs of the projects from Minnesota customers beginning Jan. 1, 2006, including a rate of return on the construction work in progress.  The MPUC approval has a sliding ROE scale based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and debt of 51.5 percent) to incentivize NSP-Minnesota to control construction costs.

 

Actual Costs as a Percent of Target Costs

 

ROE

 

Less than or equal to 75%

 

11.47

%

Over 75% and up through 85%

 

11.22

%

Over 85% and up through 95%

 

11.00

%

Over 95% and up through 105%

 

10.86

%

Over 105% and up through 115%

 

10.55

%

Over 115% and up through 125%

 

10.22

%

Over 125%

 

9.97

%

 

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Pending and Recently Concluded Regulatory Proceedings - FERC

 

MISO Operations —NSP-Minnesota and NSP-Wisconsin are members of the MISO. The MISO is an RTO that provides regional transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota and NSP-Wisconsin.  In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 KVand above) transmission systems to the MISO. The MISO membership grants MISO functional control over the operations of these facilities and the facilities of certain neighboring electric utilities.

 

On April 1, 2005, MISO initiated a regional wholesale energy market using LMP and FTR’s Day 2 market pursuant to its TEMT.  While it is anticipated the Day 2 market will provide efficiencies through region-wide generation dispatch and increased reliability, as well as long-term benefits through dispatch of power from the most cost-effective sources of generation or transmission, there are costs associated with the Day 2 market.  NSP-Minnesota and NSP-Wisconsin have requested recovery of these costs within their respective jurisdictions.  For further discussion, see Pending and Recently Concluded Regulatory Proceedings – MPUC.

 

Within MISO, an independent market monitor reviews market bids and prices to identify any unusual activity.  The FERC has notified Xcel Energy that it is investigating pricing and market-related issues.  Xcel Energy and other market participants continue to work with MISO, the independent market monitor and the FERC to resolve Day 2 market implementation issues such as dispatch methods and settlement calculation details.  Xcel Energy also intends to work with these parties to resolve any identified issues.

 

New business processes, systems and internal controls over financial reporting were planned and implemented by Xcel Energy and MISO during the second quarter of 2005 to conduct business within the MISO Day 2 market.  Xcel Energy continues to validate these changes and to review the energy costs and revenues determined by MISO.  Xcel Energy and other market participants have disputed certain transactions.

 

MISO Long Term Transmission Pricing - On Oct. 7, 2005, MISO filed proposed tariff revisions that would allow MISO to regionalize the cost of certain future high voltage transmission lines owned by specific transmission owners but constructed pursuant to the MISO transmission expansion plan.  The proposed tariffs reflect stakeholder input to MISO.  MISO proposed the tariff revisions to be effective on Feb. 4, 2006.  Xcel Energy generally supports the proposed tariff revisions, which should encourage transmission construction by regionalizing a share of the cost of projects providing regional benefits.  Comments on or protests to the proposed tariff revisions were filed at FERC in late 2005.  In February 2006, the FERC issued an order accepting the tariff revisions, subject to modifications and additional procedures.  Xcel Energy cannot predict the ultimate impact of the MISO tariff proposed at this time.

 

MISO/PJM SECA - On Nov. 18, 2004, FERC issued an order approving portions of a plan providing for continued use of “license plate” rates for the MISO/PJM region, but rejecting proposed transition payments to compensate transmission owners for reductions in transmission revenues.  FERC instead ordered the MISO and PJM to file a Seams Elimination Charge Adjustment (SECA) transition mechanism.  The replacement compliance filings were effective Dec. 1, 2004.  The FERC order eliminates any transition payments and the SECA filings instead provide for both revenues and payments that net to approximately $86,000 in revenues per month to NSP-Minnesota and NSP-Wisconsin in 2005.

 

Various parties sought rehearing of the Nov. 18, 2004 order and/or filed objections to the Nov. 24, 2004 SECA compliance filings.  On Feb. 10, 2005, the FERC issued an order accepting the SECA filings effective Dec. 1, 2004, subject to refund, and set the proposals for hearings.  The SECA proposals are now in hearings at the FERC.  Certain parties have proposed a regional average transition charge, which could shift costs to NSP-Minnesota and NSP-Wisconsin, effective Dec. 1, 2004.  Xcel Energy has opposed these regionalized approaches.  The final FERC decision is expected to be issued by the end of 2006.  Under the FERC orders, the SECA transition charges are set to expire Mar. 31, 2006.

 

Pending and Recently Concluded Regulatory Proceedings - MPUC

 

NSP-Minnesota Electric Rate Case – In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent.  This increase was based on a requested 11 percent return on common equity, a projected common equity ratio to total capitalization of 51.7 percent and a projected electric rate base of $3.2 billion.  On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006.  The anticipated procedural schedule is as follows:

 

      March 2nd – Intervenor Direct Testimony

      March 30th – Rebuttal Testimony

      April 13th – Surrebuttal Testimony

 

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      April 20th – April 28th – Evidentiary Hearings

      May 24th – Initial Briefs

      June 6th – Reply Briefs

      July 6th – Administrative Law Judge Report

      September 5th – MPUC Order

 

Renewable Transmission Cost RecoveryIn 2002, NSP-Minnesota filed for MPUC approval to establish an RCR adjustment mechanism to recover the costs of transmission investments incurred to deliver renewable energy resources.  The RCR adjustment mechanism provides for annual filings to set the RCR adjustment rates using updated transmission cost information.  The MPUC approved the RCR adjustment mechanism and the two-phase filing mechanism in April 2003.  In February 2004, the MPUC conditionally approved the initial Phase 1 facility eligibility determination filing.  NSP-Minnesota then filed for approval to recover annual additional transmission costs from May 2004 to December 2004, which were approximately $6 million. The request was approved and the RCR was implemented Dec. 1, 2004.  NSP-Minnesota collected approximately $0.2 million in 2004.  NSP-Minnesota submitted a filing in February 2005 to determine the eligibility of additional transmission projects and to establish the RCR factors for 2005, seeking recovery of $12.9 million of additional costs in 2005.  The MPUC approved revised factors by order dated Jan. 9, 2006, and NSP-Minnesota submitted its compliance filing in late January 2006 for rates to be effective Mar. 1, 2006.  In Oct. 2005, NSP-Minnesota revised the recoverable expense to $9.3 million, of which $5.4 million has been recovered. Because of the pending Minnesota rate case, the RCR rates in effect in 2006 will recover only the unrecovered 2005 costs of $3.9 million.  All 2006 costs are proposed to be recovered in the Minnesota electric rate case discussed above.

 

MISO Cost Recovery — On Dec. 18, 2004, NSP-Minnesota filed with the MPUC a petition to seek recovery of the Minnesota jurisdictional portion of all net costs associated with the implementation of the MISO Day 2 market through its FCA.  The MPUC issued an interim order in April 2005 allowing MISO Day 2 charges to be recovered through the NSP-Minnesota FCA mechanism. In December 2005, the MPUC issued a second interim order approving the recovery of certain MISO charges through the FCA mechanism but requiring that additional charges either be recovered as part of a general rate case or through an annual review process outside the fuel and purchased energy cost recovery mechanism, and requiring refunds of non-FCA costs.  The December 2005 MPUC order also suspended the refund obligation until such time as it could reconsider the matter.  On Feb. 9, 2006, the MPUC voted to reconsider its December 2005 order.  The MPUC on reconsideration determined that parties be directed to determine which charges are appropriately in the FCA and which are more appropriately established in base rates and report back to the MPUC in 60 days; to grant deferred accounting treatment for costs ultimately determined to be included in base rates for a period of 36 months, with recovery of deferred amounts to be reviewed in a general rate case; and that amounts collected to date through the FCA under the April and December 2005 interim orders are not subject to refund.  As a result, NSP-Minnesota expects to have the opportunity to recover (or seek to recover in a rate case) all of its MISO Day 2 costs.

 

In March 2005, the PSCW issued an interim order allowing NSP-Wisconsin deferred accounting treatment of MISO charges.  However, the PSCW staff issued an interpretive memorandum in October 2005 asserting that certain MISO costs may not be recovered through the interim fuel cost mechanism and may not be deferrable.  NSP-Wisconsin and the other Wisconsin utilities contested staff’s interpretation in their November comments to the PSCW.  To date, NSP-Wisconsin has deferred approximately $5.7 million of MISO Day 2 costs as a regulatory asset.

 

Xcel Energy also notified MISO that NSP-Minnesota and NSP-Wisconsin may seek to withdraw from MISO if rate recovery of Day 2 costs is not allowed.  Withdrawal would require FERC approval and could require Xcel Energy to pay a withdrawal fee.

 

In addition, in March 2005, NSP-Minnesota filed petitions similar to the December 2004 Minnesota filing with the NDPSC and the SDPUC proposing changes to allow recovery of the applicable North Dakota and South Dakota jurisdictional portions of the MISO Day 2 market costs.  The SDPUC approved the proposed tariff changes effective April 1, 2005, as requested.  The NDPSC granted interim recovery through the FCA beginning April 1, 2005, but similar to the decision of the MPUC, conditioned the relief as being subject to refund until the merits of the case are determined.  To date, the NDPSC has conducted no further proceedings regarding the NSP-Minnesota filing.

 

Energy Legislation In 2005, the Minnesota Legislature passed and the Governor signed an Omnibus Energy Bill, effective July 1, 2005.  Among other things, the new law provides authority for the MPUC to approve rate rider recovery for transmission investments that have been approved through a certificate of need, the biennial transmission plan, or are associated with compliance with the state’s renewable energy objective.  The statute provides that the rate rider may include recovery of the revenue requirement associated with qualifying projects, including a current return on construction work in progress.  NSP-Minnesota is currently preparing a filing to the MPUC for approval of a new tariff to implement this statute.

 

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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 2006, assuming normal weather, are listed below.

 

 

 

System Peak Demand (in MW)

 

 

 

2003

 

2004

 

2005

 

2006 Forecast

 

 

 

 

 

 

 

 

 

 

 

NSP System

 

8,868

 

8,665

 

9,212

 

9,401

 

 

The peak demand for the NSP System typically occurs in the summer. The 2005 uninterrupted system peak demand for the NSP System occurred on June 23, 2005.

 

Energy Sources and Related Initiatives

 

NSP-Minnesota expects to use existing electric generating stations; purchases from other utilities, independent power producers and power marketers; demand-side management options; and phased expansion of existing generation at select power plants to meet its system capacity requirements.

 

Purchased Power — NSP-Minnesota has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

 

NSP-Minnesota also makes short-term firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide the utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

 

On Dec. 27, 2005, Excelsior Energy Inc. (Excelsior), an independent energy developer, filed a petition with the MPUC seeking to compel NSP-Minnesota to enter into a power purchase agreement related to its proposed integrated gasification, combined-cycle power plant (Mesaba project) that would be located in northern Minnesota.  The petition requested the MPUC to determine that the proposed purchase is in the public interest and that the technology proposed for the Mesaba Project, which Excelsior claims is a “clean energy technology” under Minnesota law, is or is likely to be a least-cost resource pursuant to Minnesota law.  NSP-Minnesota has not been provided a full, unredacted copy of the proposed power purchase agreement and has not entered into the power purchase agreement with Excelsior.  The petition seeks to compel NSP-Minnesota to purchase at least 13 percent of NSP-Minnesota’s electric energy provided to retail customers from the Mesaba Project, which Excelsior claims would require two units of its Mesaba Project each proposed at 603 MW.  Excelsior’s filing asserts much of its proposal is confidential under the MPUC’s rules, including the pricing and other economic terms.  NSP-Minnesota is seeking access to the confidential information.  The MPUC asked for comments on the process for the filing and comments on the ability to obtain information filed under confidential protection.  NSP-Minnesota has asked the MPUC to first resolve issues surrounding the confidential information, then to address legal issues surrounding the proposal and after resolution of those issues, to consider the proposal in light of its legal conclusions.

 

NSP System Resource Plan — On Nov. 1, 2004, NSP-Minnesota filed its 2004 resource plan with the MPUC.  The resource plan projects a need for an additional 3,100 MW of electricity resources during the next 15 years, based on an anticipated growth in demand of 1.61 percent annually, or approximately 170 MW per year, during the period.  The resource plan:

 

      identifies the need for adding up to 1,125 MW of new base-load electricity generation by 2015;

      recommends a new resource acquisition process that includes multiple options for consideration, including generation built by NSP-Minnesota;

      recommends increasing energy-saving goals for demand-side energy management programs by nearly 17 percent;

      recommends extending the operating licenses for the Prairie Island and Monticello nuclear plants by 20 years (on Jan. 18, 2005, NSP-Minnesota applied for a certificate of need in Minnesota for a dry spent-fuel storage facility at the Monticello plant, and plans to file an application with the federal government to extend the Monticello plant’s

 

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license and to make similar filings for the Prairie Island plant in 2008);

      assumes nearly 1,700 MW of wind power with most developed on NSP-Minnesota’s system;

      identifies the need for obtaining up to 550 MW of new power resources for peak usage times by 2015 depending on the amount and timing of any base-load resources acquired; and

      cites the importance of ensuring that sufficient transmission resources are available to move electricity from generation sources.

 

On Aug. 1, 2005, the Minnesota Department of Commerce filed comments that Xcel Energy had overestimated its forecast and that there was no need for new resources until 2015.  Other parties filed various comments relating to the environmental impacts of the plan, the use of renewable fuels, the need to construct a 600 MW integrated gasification combined-cycle facility in Northern Minnesota, and NSP-Minnesota’s monitoring of the Northern Flood Agreement between the Province of Manitoba and various Canadian First Nations.

 

On Nov. 23, 2005, Xcel Energy filed updated analysis and replies with the MPUC.  The updated analysis supported Xcel Energy’s original forecast and identified upgrades to certain existing facilities that could provide cost-effective base load energy to Xcel Energy’s customers and defer the need for new base load until 2015.  The filing also detailed Xcel Energy’s examination of new base load options.  On the same day, the Minnesota Department of Commerce filed a proposal to select base load resources through a certificate of need process rather than a bidding process.  Xcel Energy expects the MPUC to make a final ruling on the Resource Plan and the bidding process in the first half of 2006.

 

NSP-Minnesota Transmission Certificates of Need — In December 2001, NSP-Minnesota proposed construction of various transmission system upgrades to provide transmission outlet capacity for up to 825 MW of renewable energy generation (wind and biomass) being constructed in southwest and western Minnesota.  In March 2003, the MPUC granted four certificates of need to NSP-Minnesota, thereby approving construction, subject to certain conditions. The initial projected cost of the transmission upgrades was approximately $160 million.  The MEQB granted a routing permit for the first major transmission facilities in the development program in 2004.  The remaining route permit proceedings were completed in 2005.  In 2003, the MPUC also approved an RCR adjustment that allows NSP-Minnesota to recover the revenue requirements associated with certain transmission investments associated with delivery of renewable energy resources through an automatic adjustment mechanism that started in 2004.  See the Pending and Recently Concluded Regulatory Proceedings — MPUC, Renewable Transmission Cost Recovery section for further discussion.

 

Purchased Transmission Services —NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO to deliver power and energy to NSP System native load customers.  Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved. Network transmission services include a charge based on the transmission customer’s monthly peak demand.

 

Nuclear Power Operations and Waste Disposal - NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant. See additional discussion regarding the nuclear generating plants at Note 15 to the Consolidated Financial Statements.

 

Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes. The discharge and handling of such wastes are controlled by federal regulation.  High-level radioactive wastes primarily include used nuclear fuel. Low-level radioactive waste consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

 

Low-Level Radioactive Waste DisposalFederal law places responsibility on each state for disposal of its low-level radioactive waste generated within its borders. Low-level radioactive waste from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Barnwell facility located in South Carolina (all classes of low-level waste) and at the Clive facility located in Utah (class A low-level substance only). Chem Nuclear is the owner and operator of the Barnwell facility, which has been given authorization by South Carolina to accept low-level radioactive waste from states that are not a member of South Carolina’s state compact.  Envirocare, Inc. operates the Clive facility.  NSP-Minnesota has an annual contract with Barnwell, but is also able to utilize the Envirocare facility through various low-level waste processors.  NSP-Minnesota has low-level storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site low-level disposal facilities were not available to NSP-Minnesota.

 

High-Level Radioactive Waste DisposalThe federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to

 

16



 

implement a program for nuclear high level waste management. This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent Federal storage or disposal facility. To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel.  See Item 3 — Legal Proceedings and Note 15 to the Consolidated Financial Statements for further discussion of this matter.

 

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants. In 1993, the Prairie Island plant was licensed by the federal NRC to store up to 48 casks of spent fuel at the plant. In 1994, the Minnesota Legislature adopted a limit on dry cask storage of 17 casks for the entire state.  On May 29, 2003, the Minnesota Legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its current licenses with the NRC expire in 2013 and 2014. The legislation transfers the primary authority concerning future spent-fuel storage issues from the state Legislature to the MPUC. It also allows for additional storage without the requirement of an affirmative vote from the state Legislature, if the NRC extends the licenses of the Prairie Island and Monticello plants and the MPUC grants a certificate of need for such additional storage. It is estimated that operation through the end of the current license will require 12 additional storage casks to be stored at the plant, for a total of 29 casks.  As of Dec. 31, 2005, there were 20 casks loaded and stored at the Prairie Island plant. See Note 15 in the Consolidated Financial Statements for further discussion of the matter.

 

Visual InspectionsRequired visual inspections have been performed on the Prairie Island Unit 2 upper and lower reactor vessel heads, and the Unit 1 upper head. Reactor vessel heads for both units were found to be in compliance with all NRC requirements. The reactor vessel upper head for Prairie Island Unit 2 was replaced during the 2005 refueling outage, and Xcel Energy expects to replace the reactor vessel upper head for Prairie Island Unit 1 in early 2006.

 

Private Fuel Storage (PFS)NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel. In 1997, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah. The NRC license review process includes formal evidentiary hearings before the ASLB and opportunities for public input. On Sept. 9, 2005, the NRC Commissioners directed the NRC staff to issue the license for PFS, ending the 8-year effort to gain a license for the site.  In December 2005, the U.S. Supreme Court denied Utah’s petition for a writ of certiorari to hear an appeal of a lower court’s ruling on a series of state statutes aimed at blocking the storage and transportation of spent fuel to PFS. Also in December 2005, NSP-Minnesota forwarded a letter to Senator Hatch (UT) indicating that it would hold in abeyance future investments in the construction of PFS as long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation’s spent nuclear fuel.

 

Prairie Island Steam Generator ReplacementIn the fall of 2004, NSP-Minnesota spent approximately $132 million to successfully replace the Prairie Island Unit 1 steam generators.  The Unit 2 steam generators have not yet been replaced, but received the required inspections during the scheduled 2005 outage. Based on current rates of degradation and available repair processes, NSP-Minnesota plans to replace these steam generators in the 2013 regular refueling outage. Due to the potential shortages in the world markets for materials and shop capabilities, NSP-Minnesota expects to begin the approval process in 2006 for long-lead time materials.

 

NSP-Minnesota Nuclear Plant Re-licensing— Monticello’s current 40-year license expires in 2010, and Prairie Island’s licenses for its two units expire in 2013 and 2014.  In March 2005, NSP-Minnesota filed its application with the NRC for an operating license extension for Monticello of up to 20 years.  NSP-Minnesota filed its application with the MPUC for Monticello in January 2005 seeking a certificate of need for dry spent fuel storage. Decisions by both the federal and state agencies regarding Monticello re-licensing are expected in early 2007. Prairie Island has initiated the necessary plant assessments and aging analysis to support submittal of similar applications to the NRC and Minnesota, currently planned for submittal in early 2008.

 

Nuclear Management Co. (NMC) — During 1999, NSP-Minnesota, Wisconsin Electric Power Co., Wisconsin Public Service Corporation (WPS) and Alliant Energy Corp. established NMC. The Consumers Power subsidiary of CMS Energy Corp. joined the NMC during 2000.

 

NMC manages the operations and maintenance at the plants, and is responsible for physical security. NMC’s responsibilities also include oversight of on-site dry storage facilities for used nuclear fuel at the Prairie Island nuclear plant. Utility plant owners, including NSP-Minnesota, continue to own the plants, control all energy produced by the plants, and retain responsibility for nuclear liability insurance and decommissioning costs.

 

In 2005 and 2006, as a result of selling their nuclear plants, WPS and Alliant Energy ended their participation in NMC.  In December 2005, Consumer Power announced its intent to sell its nuclear plant, which will leave NSP-Minnesota and Wisconsin Electric Power Co. as the remaining members of the NMC, with a combined total of 3 sites and 5 reactors. NMC

 

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is in the process of identifying and marketing its services to other potential nuclear utility candidates to replace the departing members.

 

For further discussion of nuclear issues, see Notes 14 and 15 to the Consolidated Financial Statements.

 

Fuel Supply and Costs

 

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

 

NSP System

 

Coal*

 

Nuclear

 

Natural Gas

 

Average Fuel

 

Generating Plants

 

Cost

 

Percent

 

Cost

 

Percent

 

Cost

 

Percent

 

Cost

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2005

 

$

1.04

 

60

%

$

0.46

 

36

%

$

8.32

 

3

%

$

1.11

 

2004

 

$

0.99

 

61

%

$

0.44

 

37

%

$

6.48

 

2

%

$

0.92

 

2003

 

$

0.99

 

61

%

$

0.43

 

36

%

$

5.80

 

2

%

$

0.90

 

 


* Includes refuse-derived fuel and wood

 

See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

 

Fuel Sources — Coal inventory levels may vary widely among plants.  However, the NSP System normally maintains no less than 30 days of coal inventory at each plant site.  Estimated coal requirements at NSP-Minnesota and NSP-Wisconsin’s major coal-fired generating plants are approximately 13.3 million tons per year. NSP-Minnesota and NSP-Wisconsin have long-term contracts providing for the delivery of up to 99 percent of 2006 coal requirements. Coal delivery may be subject to short-term interruptions or reductions due to transportation problems, weather, and availability of equipment.  See Management’s Discussion and Analysis for further discussion of coal delivery disruptions.

 

NSP-Minnesota and NSP-Wisconsin expect that all of the coal burned in 2006 will have an average sulfur content of less than 0.75 percent.  The NSP System has contracts for a maximum of 35.8 million tons of low-sulfur coal for the next 3 years.  The contracts are with 1 Montana coal supplier, 3 Wyoming suppliers and 1 Minnesota oil refinery, with expiration dates in 2006 and 2007.

 

To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication. The contract strategy involves a portfolio of spot purchases and medium- and long-term contracts for uranium, conversion and enrichment.

 

      Current nuclear fuel supply contracts cover 100 percent of uranium requirements through 2006 and 91.8 percent of the 2007 requirements with no coverage of requirements for 2008 and beyond. Contracts with additional uranium concentrates suppliers are currently in various stages of negotiations that are expected to provide a portion of the requirements through 2016.

      Current contracts for conversion services requirements cover 100 percent of the requirements for 2006 and 53 percent for 2007 with no current coverage of requirements for 2011 and beyond. A contract with an additional conversion services supplier is nearing completion that is expected to provide additional coverage for 2007 through 2011.

      Current enrichment services contracts cover 100 percent of the 2006 requirements. Approximately 30 percent of the 2007 through 2010 requirements are currently covered with no coverage of requirements for 2011 and beyond. These contracts expire at varying times between 2006 and 2010. Contracts with additional enrichment services suppliers are currently in various stages of negotiation that are expected to supply additional coverage from 2007 through 2010.

      Fuel fabrication for Monticello is covered through 2010.  Fuel fabrication is 100 percent committed for Prairie Island Unit 1 through 2006 and Prairie Island Unit 2 is covered for the 2006 fuel fabrication services under an amendment signed in 2005. NSP-Minnesota and NMC are currently in negotiations with Westinghouse to pursue fuel fabrication for Prairie Island plant needs beyond the current fuel contracts.

 

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants. Contracts for additional uranium and enrichment services are currently being negotiated that would provide additional supply requirements through 2016 for uranium and 2010 for enrichment services.

 

The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers.  Natural gas supplies for power plants are procured under short-, intermediate- and long-term contracts which expire in various years from 2006 through 2027 in order to provide an adequate supply of fuel.  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, 2005, NSP-Minnesota’s commitments related to these contracts were approximately $127 million.  The NSP System has current fuel oil inventory adequate to meet anticipated 2006 requirements and also has access to the spot market to buy more oil, if needed.

 

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Commodity Marketing Operations

 

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of NSP-Minnesota.  NSP-Minnesota uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers. NSP-Minnesota also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

 

NSP-Wisconsin

 

Ratemaking Principles

 

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states.  In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines to be located within the respective states before the facilities may be sited and built.  NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce. NSP-Wisconsin has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion).

 

The PSCW has a biennial base-rate filing requirement.  By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

 

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers.  Instead, it has a procedure that compares actual monthly and anticipated annual fuel costs with those costs that were included in the latest retail electric rates. If the comparison results in a difference of 2 percent above base rates or 0.5 percent below, the PSCW may hold hearings limited to fuel costs and revise rates upward or downward. Any revised rates would remain in effect until the next rate change. The adjustment approved is calculated on an annual basis, but applied prospectively.  NSP-Wisconsin’s wholesale electric rate schedules provide for adjustments to billings and revenues for changes in the cost of fuel and purchased energy.

 

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections.  After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

 

Pending and Recently Concluded Regulatory Proceedings - FERC

 

MISO See the discussion of the MISO activity under NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings.

 

Pending and Recently Concluded Regulatory Proceedings - PSCW

 

MISO Cost Recovery - On Mar. 29, 2005, NSP-Wisconsin received an order from the PSCW granting its request to defer the costs and benefits attributable to the start-up of the MISO Day 2 energy market.  NSP-Wisconsin also received an order granting its request to record energy market transactions on a net basis. The netting of transactions is consistent with the approach envisioned by the FERC in approving the transmission and energy markets tariff and is consistent with generally accepted accounting principles.  On Sept. 22, 2005, the PSCW opened an investigation to obtain information from interested persons related to MISO policy development that is beneficial to ratepayers and that protects the public interest.  On Oct. 18, 2005, the PSCW solicited comments on the PSCW staff proposal regarding rate and accounting treatment of MISO revenues and costs, as well as a request to escrow MISO Day 2 energy market costs until 2008.  On Nov. 17, 2005, NSP-Wisconsin and other Wisconsin utilities filed comments on the PSCW staff proposal and clarified the utilities’ position on their interpretation of the previously granted deferral order.  NSP-Wisconsin will continue to work with the PSCW and other utilities to address the longer-term issue related to MISO policies.

 

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NSP-Wisconsin 2005 Fuel Cost Recovery - On April 22, 2005, NSP-Wisconsin filed an application with the PSCW to increase electric rates by $10 million, or 2.7 percent, annually to provide for recovery of forecasted increased costs of fuel and purchased power over the balance of 2005.  The March 2005 actual fuel costs were approximately 13 percent higher than authorized recovery in current base rates, and the forecast for the remainder of 2005 showed costs outside the previously established annual range by 9.6 percent.  On May 18, 2005, the PSCW issued an order approving interim rates at the level requested, effective May 19, 2005.  This rate increase generated an estimated $6.5 million in additional revenue for NSP-Wisconsin in 2005.  Under the provisions of the Wisconsin fuel rules, any difference between interim rates and final rates is subject to refund.  On Sept. 28, 2005, the PSCW issued a final order approving an increase of $11.6 million, or 3.1 percent annually.  Because the final rates were slightly higher than interim rates authorized in May 2005, no refund was necessary.  With an effective date of Oct. 1, 2005, final rates collected approximately $0.4 million in incremental revenue, as compared to interim rates, over the last three months of 2005.

 

On Oct. 14, 2005, NSP-Wisconsin filed an application with the PSCW to increase the amount of the authorized fuel and purchased power surcharge by $8.9 million or 2.3 percent on an annual basis.  This additional request was due to dramatic increases in the cost of natural gas and purchased power since the surcharge amount was set in mid-August.  September 2005 actual fuel costs were approximately 38 percent higher than authorized recovery in current rates, and the forecast for the remainder of 2005 showed costs outside the annual range by 7.5 percent.  A PSCW order authorizing an increase in the amount of the surcharge on an interim basis, subject to refund, was issued Nov. 10, 2005, and NSP-Wisconsin collected approximately $1.3 million in additional revenue over the remainder of 2005.  The surcharge was discontinued with the implementation of new 2006 base rates, which went into effect Jan. 9, 2006.  A final hearing in the 2005 fuel surcharge case was held Feb. 10, 2006, to determine whether any refund of interim rates is necessary.  NSP-Wisconsin and PSCW staff both filed testimony indicating that actual fuel costs for the period in question exceeded levels assumed in setting interim rates, and no refund is necessary.  A final PSCW decision is expected in the first quarter of 2006.

 

NSP-Wisconsin 2006 General Rate Case – In 2005, NSP-Wisconsin, requested an electric revenue increase of $58.3 million and a natural gas revenue increase of $8.1 million, based on a 2006 test year, an 11.9 percent return on equity and a common equity ratio of 56.32 percent.  On Jan. 5, 2006, the PSCW approved an electric revenue increase of $43.4 million and a natural gas revenue increase of $3.9 million, based on an 11.0 percent return on equity and a 54-percent common equity ratio target.  The new rates were effective Jan. 9, 2006.  The order authorized the deferral of an additional $6.5 million in costs related to nuclear decommissioning and manufactured gas plant site clean up for recovery in the next rate case.  The order also prohibits NSP-Wisconsin from paying dividends above $42.7 million, if its actual calendar year average common equity ratio is or will fall below 54.03 percent.  It also imposes an asymmetrical electric fuel clause bandwidth of positive 2 percent to negative 0.5 percent outside of which NSP-Wisconsin would be permitted to request or be required to change rates.

 

Capacity and Demand

 

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

 

Energy Sources and Related Initiatives

 

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

 

Fuel Supply and Costs

 

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

 

PSCo

 

Ratemaking Principles

 

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.

 

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

 

20



 

      Electric Commodity Adjustment (ECA) — The ECA, effective Jan. 1, 2004, is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. The ECA also provides for an $11.25 million cap on any cost sharing over or under an allowed ECA formula rate.  The formula rate is revised annually and collected or refunded in the following year, if necessary.  The current ECA mechanism will expire Jan. 1, 2007.

 

      Purchased Capacity Cost Adjustment (PCCA) — The PCCA, which became effective June 1, 2004, allows for recovery of purchased capacity payments to certain power suppliers under specifically identified power purchase agreements that are not included in the determination of PSCo’s base electric rates or other recovery mechanisms.  The PCCA will expire on Dec. 31, 2006.  Purchased capacity costs both from contracts included within the PCCA and from contracts not included within the PCCA are expected to be eligible for recovery through base rates, when PSCo files its next general rate case.

 

      Steam Cost Adjustment (SCA) — The SCA allows PSCo to recover the difference between its actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised at least annually to coincide with changes in fuel costs.

 

      Air-Quality Improvement Rider (AQIR) — The AQIR recovers, over a 15-year period, the incremental cost (including fuel and purchased energy) incurred by PSCo as a result of a voluntary plan to reduce emissions and improve air quality in the Denver metro area.

 

      Demand-Side Management Cost Adjustment (DSMCA) — The DSMCA clause currently permits PSCo to recover DSM costs over five years while non-labor incremental expenses and carrying costs associated with deferred DSM costs are recovered on an annual basis. PSCo also has a low-income energy assistance program. The costs of this energy conservation and weatherization program for low-income customers are recovered through the DSMCA.

 

PSCo recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC.

 

Performance-Based Regulation and Quality of Service Requirements — PSCo currently operates under an electric and natural gas PBRP.  The major components of this regulatory plan include:

 

      an annual electric earnings test for 2004 through 2006 with the sharing between customers and shareholders of earnings in excess of a return on equity for electric operations of 10.75 percent;

 

      an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service through 2006; and

 

      a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service through 2007.

 

PSCo regularly monitors and records as necessary an estimated customer refund obligation under the PBRP. In April of each year following the measurement period, PSCo files its proposed rate adjustment under the PBRP. The CPUC conducts proceedings to review and approve these rate adjustments annually.

 

      In 2003, PSCo did not achieve the performance targets for the QSP electric service unavailability measure or the customer complaint measure.  Targets were met for the natural gas QSP.  There was no sharing of earnings for 2003, as PSCo established new rates in its general rate case.

 

      In 2004, PSCo did not earn a return on equity in excess of 10.75 percent, so no refund liability was recorded.  PSCo did not achieve the 2004 performance targets for the electric service unavailability measure, creating a bill credit obligation for 2004 and increasing the maximum bill credit obligation for subsequent years’ performance.  Targets were met for the natural gas QSP.

 

      In 2005, PSCo does not anticipate earning a return on equity in excess of 10.75 percent and did not record a refund liability.  QSP results will be filed with the CPUC in April 2006.  An estimated customer refund obligation under the electric QSP plan was recorded in 2005 related to the electric service unavailability measure.  No refund under the natural gas QSP is anticipated. See further discussion of the QSP below.

 

21



 

Pending and Recently Concluded Regulatory Proceedings - FERC

 

PSCo and SPS FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and SPS an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff (OATT).  PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million.  As a result of a settlement with certain PSCo wholesale power customers in 2003, their power sales rates would be reduced by $1.4 million.  The net increase in annual revenues proposed was $4.7 million, of which $3.0 million is attributable to PSCo.  The FERC suspended the filing and delayed the effective date of the proposed increase to June 1, 2005.  The interim rates went into effect on June 1, 2005, subject to refund.  On Feb. 6, 2006, the parties in the proceeding submitted an uncontested offer of settlement that contains a formula rate for PSCo, a 10.5 percent rate of return on common equity, and the phased inclusion of PSCo’s 345 KV tie line costs in wholesale transmission service rates.  The settlement results in a $1.6 million rate increase for PSCo effective June 2005.  The offer of settlement is pending FERC approval.

 

California Refund ProceedingA number of proceedings are pending before the FERC relating to the price of sales into the California electricity markets from May 1, 2000 through June 20, 2001.  PSCo supplied energy to these markets during this period and has been an active participant in the proceedings.  In September 2005, PSCo reached an agreement with respect to these proceedings with a group of California entities including: San Diego Gas & Electric Company, Pacific Gas and Electric Company, Southern California Edison Company, the California Department of Water Resources, the California Electricity Oversight Board, the California Public Utilities Commission and the California Attorney General.  In December 2005, the FERC approved the settlement without condition for the period of Jan. 1, 2000 through June 20, 2001.  PSCo will pay approximately $5.5 million in cash and assign $1.8 million in accounts receivable from the California Independent System Operator and the California Power Exchange to the settling participants. In 2004, PSCo reserved approximately $7 million related to this proceeding.  The settlement, which includes no acknowledgment of wrongdoing by PSCo, avoids further costly litigation and resolves all claims by PSCo against the settling participants and by the settling participants against PSCo.  While accounting for approximately 90 percent of purchases in the California markets, the California utilities were not the only purchasers in those markets.  However, the settlement makes provision for other purchasers to opt into the settlement.  We do not expect a material financial impact as resolution is reached with the non-settling parties.

 

Pacific Northwest FERC Refund ProceedingIn July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling the FERC has allowed the parties to request additional evidence regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed that the total amount of transactions with PSCo subject to refund are $34 million.

 

On June 25, 2003, the FERC issued an order terminating the proceeding without ordering further proceedings.  On Nov. 10, 2003, in response to requests for rehearing, FERC reaffirmed this ruling to terminate the proceeding without refunds.  Certain purchasers have filed appeals of the FERC’s orders in this proceeding.

 

FERC OMOI Compliance Audit — On October 28, 2004, the OMOI sent a letter to Xcel Energy stating that OMOI had initiated a routine audit of PSCo compliance with various FERC regulations, including PSCo’s OATT, FERC’s Order No. 889 standards of conduct rules and PSCo’s code of conduct for transactions in power and non-power goods with affiliates with market-based rates.  Similar compliance audits of other utilities have resulted in compliance orders and, in certain cases, civil penalties.  On November 28, 2005, FERC issued an order approving an audit report that recommended certain operational changes but imposed no civil penalties.

 

Pending and Recently Concluded Regulatory Proceedings - CPUC

 

Tie Line Cost Recovery - On Sept. 20, 2001, the CPUC ruled that only 50 percent of the total cost of the high voltage direct current (HVDC) converter constructed by PSCo in Lamar, Colorado would be allowed in rate base.  This facility is part of the 345 KV tie line transmission facilities connecting the PSCo and SPS systems.  The CPUC decision resulted in a reduction of potential PSCo rate base of approximately $16.7 million.  On April 7, 2005, PSCo filed an application with the CPUC proposing a mechanism that would leave half of the HVDC facility as a non-rate-base asset, but that would generate revenue

 

22



 

to recover the cost of the non-rate-base asset on a pay-as-you-go basis.  The proposal would involve allocating half of any energy or fuel cost savings derived from buying electricity through the tie line or making sales through the tie line.  Alternatively, PSCo stated that it would not object to the entire HVDC facility being placed in rate base.  A hearing examiner for the CPUC issued a recommended decision on Nov. 16, 2005, that reasoned that 100 percent of the HVDC converter be placed in rate base.  The CPUC acted on the recommended decision in February 2006 with generally favorable results.

 

Quality of Service Plan — The PSCo QSP provides for bill credits to Colorado retail customers, if PSCo does not achieve certain operational performance targets. During the second quarter of 2005, PSCo filed its calendar year 2004 operating performance results for electric service unavailability, phone response time, customer complaints, accurate meter reading and natural gas leak repair time measures.  PSCo did not achieve the 2004 performance targets for the electric service unavailability measure.  The CPUC staff and the OCC disputed the performance results.  The parties agreed PSCo did not achieve the 2004 performance targets for the electric service unavailability measure as filed, creating a bill credit obligation for 2004 of $5.6 million.  Additionally, the agreement provides that PSCo will invest an additional $11 million in 2006 toward improving reliability, and PSCo will not be required to pay any bill credits that may be owed for 2006 performance results for electric service unavailability.  For 2005, PSCo has evaluated its performance under the QSP and has recorded a liability of $13.6 million.  Under the electric QSP, the estimated maximum potential bill credit obligation for calendar 2005 performance is approximately $16.8 million, assuming none of the performance targets are met.  The maximum potential bill credit obligation for the same period related to permanent natural gas leak repair and natural gas meter reading errors is approximately $1.6 million.

 

Capacity and Demand

 

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2006, assuming normal weather, are listed below.

 

 

 

System Peak Demand (in MW)

 

 

 

2003

 

2004

 

2005

 

2006 Forecast

 

 

 

 

 

 

 

 

 

 

 

PSCo

 

6,419

 

6,483

 

6,975

 

6,751

 

 

The peak demand for PSCo’s system typically occurs in the summer.  The 2005 uninterrupted system peak demand for PSCo occurred on July 21, 2005.

 

Energy Sources and Related Transmission Initiatives

 

PSCo expects to meet its system capacity requirements through existing electric generating stations; purchases from other utilities, independent power producers and power marketers; demand-side management options and phased expansion of existing generation at select power plants.

 

Purchased Power — PSCo has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers.  Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity.  Energy, typically measured in Kwh or Mwh, is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

 

PSCo also makes short-term firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide the utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

 

PSCo Resource Plan — PSCo estimates it will purchase approximately 36 percent of its total electric system energy needs for 2006 and generate the remainder with PSCo-owned resources.  Additional capacity has been secured under contract making additional energy auditable for purchase, if required. PSCo currently has under contract or through owned generation, the resources necessary to meet its anticipated 2006 load obligation.

 

On April 30, 2004, PSCo filed a least-cost resource plan (LCP) with the CPUC.  PSCo’s plan showed a need to provide for approximately 3,600 MW of additional generation capacity through 2013 to meet load growth and replace expiring power purchase contracts. The LCP proposed to meet these resource needs through a combination of utility built generation, DSM, and power purchases.

 

23



 

On Dec. 17, 2004, the CPUC approved a settlement agreement between PSCo and intervening parties concerning the LCP.  The CPUC approved PSCo’s plan to construct a 750-MW pulverized coal-fired unit at the existing Comanche power station located near Pueblo, Colo.; transfer up to 250 MW of capacity ownership from the 750-MW unit to Intermountain Rural Electric Association and Holy Cross Energy; and install additional emission control equipment on the two existing Comanche station units.  PSCo has completed permitting the 750 MW Comanche 3 unit and began construction of the facility in December 2005. In the approved settlement, PSCo also agreed to invest in additional demand-side management and fund environmental programs in Pueblo, Colo.

 

The approved settlement contains a confidential construction cost cap for the Comanche 3 project (i.e., the new unit and the emission controls on existing units 1 and 2) and a regulatory plan that authorizes PSCo to increase the equity component of its capital structure up to 60 percent in its 2006 rate case to offset the debt equivalent value of PSCo’s existing power purchase contracts and to otherwise improve PSCo’s financial strength.  Depending upon PSCo’s senior unsecured debt rating during the time of PSCo general rate cases, the approved settlement permits PSCo to include various amounts of construction work in progress that are associated with the Comanche 3 project in rate base without an offset for allowance for funds used during construction.

 

PSCo has signed agreements with IREA that define the respective rights and obligations of PSCo and IREA in the transfer of capacity ownership in the Comanche 3 unit.  PSCo continues to discuss the possibility of partnership arrangements with Holy Cross Energy.

 

PSCo has received the following permits or authorizations for construction and operation of Comanche 3:

 

      Final air quality permits (received July 5, 2005);

      A long-term water supply contract with the Pueblo Board of Water Works (received July 19, 2005);

      Pueblo City Council approval to annex the Comanche plant into the city (received Sept. 12, 2005) and

      Use by Special Review permit for onsite disposal of ash over a 50-year period (received Sept. 27, 2005).

 

The settlement agreement also called for PSCo to acquire the remaining resource needs through an all-source competitive bidding process.  On Feb. 24, 2005, in conjunction with the approved LCP, PSCo released an All-Source solicitation for new supply and demand-side resources.  In May 2005, PSCo received proposals for over 11,000 MW of firm capacity, nearly 4,600 MW of nameplate wind capacity, and almost 900 MW of demand-side management programs.  On Dec. 28, 2005 PSCo filed a report with the CPUC detailing the bids received, the bid evaluation process, and the winning bids. PSCo selected bids for approximately 30 MW of DSM resources, approximately 1300 MW of gas-fired generation resources and approximately 775 MW of wind generation resources.  These bids, together with Comanche 3, and the additional DSM agreed to in the LCP settlement agreement, are expected to meet PSCo’s resource needs through 2012.

 

Renewable Portfolio Standards — In November 2004, an amendment to the Colorado statutes was passed by referendum requiring implementation of a renewable energy portfolio standard for electric service.  The law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources.  Generation of electricity from renewable resources, particularly solar energy, may be a higher-cost alternative to traditional fuels, such as coal and natural gas.  These incremental costs are expected to be recovered from customers.  On March 29, 2005, the CPUC initiated a proceeding and held various hearings to determine the rules and regulations required to implement the renewable portfolio standard.  The CPUC determined that compliance with the renewable energy portfolio standard should be measured through the acquisition of renewable energy credits either with or without the accompanying renewable energy; that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on this issue; that Colorado utilities should be required to file implementation plans, thereby rejecting the proposal to use an independent plan administrator; and the methods utilities should use for determining the budget available for renewable resources.  The CPUC issued proposed rules on Jan. 27, 2006.  Final rules are expected to become effective by the end of the first quarter 2006.

 

Renewable Energy Standard Adjustment (RESA) – On December 1, 2005, PSCo filed with the CPUC to implement a new 1 percent rider that would apply to each customer’s total electric bill, providing approximately $22 million in annual revenue.  The revenues collected under the RESA will be used to acquire sufficient solar resources to meet the on-site solar system requirements in the Colorado statutes. On Feb. 14, 2006, PSCo and the other parties to the case filed a stipulation agreeing to reduce the RESA rider to 0.60 percent and to provide monthly reports.  Hearings were held on Feb. 17, 2006.  A CPUC decision is pending.  PSCo expects the RESA rider will go into effect in early March 2006.

 

Purchased Transmission Services — PSCo has contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one year.  Point-to-point transmission services typically include a charge for the specific amount of

 

24



 

transmission capacity being reserved, although some agreements may base charges on the amount of metered energy delivered.  Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

 

Fuel Supply and Costs

 

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

 

 

 

Coal

 

Natural Gas

 

Average Fuel

 

 

 

Cost

 

Percent

 

Cost

 

Percent

 

Cost

 

 

 

 

 

 

 

 

 

 

 

 

 

2005

 

$

1.01

 

85

%

$

7.56

 

15

%

$

2.00

 

2004

 

$

0.89

 

87

%

$

5.61

 

13

%

$

1.52

 

2003

 

$

0.92

 

86

%

$

4.49

 

14

%

$

1.42

 

 

See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

 

Fuel Sources Coal inventory levels may vary widely among plants.  However, PSCo normally maintains no less than 30 days of coal inventory at each plant site.  PSCo’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Colorado and Wyoming. During 2005, PSCo’s coal requirements for existing plants were approximately 9.8 million tons. Coal supply inventories at Dec. 31, 2005 were approximately 12 days usage, based on the maximum burn rate for all of PSCo’s coal-fired plants.  See Management’s Discussion and Analysis for further discussion of coal delivery disruptions.

 

PSCo has contracted for coal suppliers to supply 100 percent of the Cherokee, Cameo, and Valmont stations’ projected requirements in 2006.

 

PSCo has long-term coal supply agreements for the Pawnee and Comanche stations’ projected requirements. Under the long-term agreements the supplier has dedicated specific coal reserves at the contractually defined mines to meet the contract quantity obligations. In addition, PSCo has a coal supply agreement to supply approximately 70 percent of Arapahoe station’s projected requirements for 2006. Any remaining Arapahoe station requirements will be procured via spot market purchases.

 

PSCo operates the jointly owned Hayden generating plant in Colorado.  All of Hayden’s coal requirements are under contract through the end of 2011.  The coal will be trucked approximately 14 miles under a trucking contract effective through 2009 with an option to extend to the end of 2011.  In addition to Hayden, PSCo has partial ownership in the Craig generating plant in Colorado.  Approximately 70 percent of PSCo’s coal requirements for Craig are supplied by two long-term agreements.  The remaining coal requirements for Craig are purchased on the spot market under short term contracts.  All of 2006 expected requirements for Craig are under contract.

 

PSCo had a number of coal transportation contracts, which expired over the course of 2005.  PSCo has entered into new transportation agreements at rates substantially higher than its 2005 costs.

 

PSCo uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under short- and intermediate- term contracts, which expire in various years from 2006 through 2025 to provide an adequate supply of fuel.  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, 2005, PSCo’s commitments related to these contracts were approximately $205 million.

 

Commodity Marketing Operations

 

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of PSCo.  PSCo uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers.  PSCo also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

 

25



 

SPS

 

Ratemaking Principles

 

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT regulates SPS’ Texas operations as an electric utility and has jurisdiction over its retail rates and services. The municipalities in which SPS operates in Texas have jurisdiction over SPS’ rates in those communities. The NMPRC has jurisdiction over the issuance of securities. The NMPRC, the Oklahoma Corporation Commission and the Kansas Corporation Commission have jurisdiction with respect to retail rates and services and construction of transmission or generation in their respective states.  SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.  SPS has received authorization from the FERC to make wholesale electricity sales at market-based prices, however, as discussed previously, SPS has filed to withdraw its market-based rate authority with respect to sales in its own control area.

 

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates.  The Texas retail fuel factors change each November and May based on the projected cost of natural gas.

 

If it appears that SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the PUCT. The regulations require refunding or surcharging over- or under-recovery amounts, including interest, when they exceed 4 percent of the utility’s annual fuel and purchased energy costs, as allowed by the PUCT, if this condition is expected to continue.

 

PUCT regulations require periodic examination of SPS fuel and purchased energy costs, the efficiency of the use of fuel and purchased energy, fuel acquisition and management policies and purchase energy commitments.  SPS is required to file an application for the PUCT to retrospectively review at least every three years the operations of SPS’ electric generation and fuel management activities.  SPS is scheduled to file for review and reconciliation of its 2004-2005 costs at the end of May 2006.

 

The NMPRC regulations provide for a fuel and purchased power cost adjustment clause for SPS’ New Mexico retail jurisdiction.  SPS files monthly and annual reports of its fuel and purchased power costs with the NMPRC.  The NMPRC authorized SPS to implement a monthly adjustment factor.

 

SPS recovers fuel and purchased energy costs from its wholesale customers through a fuel cost adjustment clause accepted for filing by the FERC.

 

Performance-Based Regulation and Quality of Service Requirements — In Texas, SPS is subject to a quality of service plan requiring SPS to comply with electric service reliability, telephone response and abandoned call performance targets.  If these targets are not met, SPS is required to make refunds to its customers of up to $950,000 per year.  As of Dec. 31, 2005, SPS accrued $800,000 to reflect the expected refund obligation for those measures.

 

Pending and Recently Concluded Regulatory Proceedings - FERC

 

PSCo and SPS FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of SPS and PSCo an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff (OATT).  PSCo and SPS requested an increase in annual transmission service and ancillary services revenues, which was adjusted to reflect a net increase in annual revenues of $4.7 million, of which $1.7 million is attributable to SPS.  The FERC suspended the filing and delayed the effective date of the proposed increase to June 1, 2005.  The interim rates went into effect on June 1, 2005, subject to refund.  On Feb. 6, 2006, the parties in the proceeding submitted to the settlement judge an uncontested offer of settlement that contains stated rates for SPS, with the opportunity to file revised rates effective Oct. 1, 2006, by which time the SPP is expected to have filed a regional formula transmission rate mechanism similar to MISO.  The settlement results in a $1.1 million SPS rate increase effective June 2005.  The offer of settlement is pending FERC approval.

 

SPS Wholesale Rate Complaints — In November 2004, several wholesale cooperative customers of SPS filed a $3 million rate complaint at the FERC requesting that the FERC investigate SPS’ wholesale power base rates and fuel cost adjustment clause calculations.  In December 2004, the FERC accepted the complaint filing and ordered SPS base rates subject to refund,

 

26



 

effective Jan. 1, 2005.  Also in November 2004, SPS filed revisions to its wholesale fuel cost adjustment clause.  The FERC set the proposed rate changes into effect on Jan. 1, 2005, subject to refund, and consolidated the proceeding with the wholesale cooperative customers’ complaint proceeding.  The FERC set the consolidated proceeding for hearing and settlement judge procedures, which were terminated when the parties could not reach a settlement.  A hearing judge has been appointed by the FERC.  Hearings began Feb. 24, 2006 and are expected to last several weeks.

 

On Sept. 15, 2005, Public Service Company of New Mexico (PNM) filed a separate complaint at the FERC in which it contended that its demand charge under an existing interruptible power supply contract with SPS is excessive and that SPS has overcharged PNM for fuel costs under three separate agreements through erroneous fuel clause calculations.  PNM’s arguments mirror those that it made as an intervenor in the cooperatives’ complaint case, and SPS believes that they have little merit.  SPS submitted a response to PNM’s complaint in October 2005.  In November 2005, the FERC accepted PNM’s complaint, set it for hearing, suspended hearings and set the matter for settlement judge procedures.

 

SPS Wholesale Power Base Rate Application — In December 2005, SPS filed at the FERC for a $4.1 million annual increase in wholesale power rates for many of its requirements and interruptible capacity wholesale customers.  In January 2006, the FERC issued an order conditionally accepting and suspending the proposed rates until July 1, 2006, establishing hearing and settlement judge procedures.

 

Southwest Power Pool (SPP) Restructuring — SPS is a member of the SPP regional reliability council, and SPP acts as transmission tariff administrator for the SPS system. In October 2003, SPP filed for FERC authorization to transform its operation into an RTO.  On Oct. 1, 2004, the FERC issued an order granting the SPP status as an RTO.  SPS is required to obtain Kansas and NMPRC approval before it can transfer functional control of its electrical transmission system to SPP.  When SPP begins RTO operations and SPS obtains all required approvals, SPS will be required to transfer functional control of its electric transmission system to SPP and take all transmission services, including services required to serve retail native loads, under the SPP regional tariff.

 

SPP Energy Imbalance Service - On June 15, 2005, SPP filed proposed tariff provisions to establish an Energy Imbalance Service (EIS) wholesale energy market for the SPP region, using a phased approach toward the development of a fully-functional LMP energy market with appropriate FTR’s, to be effective Mar. 1, 2006.  On July 15, 2005, Xcel Energy filed a protest addressing the EIS market proposal and urging FERC to reject the proposal and provide guidance to SPP in its effort to design and implement a fully functional Day 2 market for the SPP region to avoid “seams” between the MISO and SPP regions.  On Sept. 19, 2005, FERC issued an order rejecting the SPP EIS proposal and providing guidance and recommendations to SPP; however, the FERC did not require SPP to implement a full Day 2 market similar to MISO.  On Jan. 4, 2006, SPP filed a revised EIS market proposal, to be effective May 1, 2006.  On Jan. 25, 2006, Xcel Energy protested the revised EIS market proposal, requesting that FERC find SPP’s proposal as incomplete and deficient even as a limited market, and reject it on that basis.  A final FERC decision is expected later in 2006.  SPS has not yet requested NMPRC or PUCT approval regarding accounting and ratemaking treatment of EIS costs.

 

Pending and Recently Concluded Regulatory Proceedings - PUCT

 

SPS Texas Retail Fuel Cost Reconciliation – Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor.  In May 2004, SPS filed with PUCT its periodic request for fuel and purchased power cost recovery for January 2002 through December 2003.  SPS requested approval of approximately $580 million of Texas-jurisdictional fuel and purchased power costs for the two-year period.  Intervenor testimony contained objections to SPS’ methodology for assigning average fuel costs to certain wholesale sales, among other things.  Recovery of $49 million to $86 million of the requested amount was contested by multiple intervenors.

 

In 2005, SPS entered into a non-unanimous stipulation with the PUCT staff and several of the intervenors.  The stipulation provided reasonable regulatory certainty for SPS on all key issues raised in this proceeding.  On Dec. 19, 2005, the PUCT issued an order approving the stipulation.  The stipulation reflects a liability of approximately $25 million, which was accrued in 2004.  An additional accrual of $4 million was recorded in 2005 to reflect the impact of the order through Dec. 31, 2005.  Under the terms of the stipulation, SPS will file a Texas base rate case and its next fuel reconciliation application by the end of May 2006.

 

Energy Legislation - The 2005 Texas Legislature passed a law, effective June 18, 2005, establishing statutory authority for electric utilities outside of the electric reliability council of Texas in the SPP or the Western Electricity Coordinating Council to have timely recovery of transmission infrastructure investments.  After notice and hearing, the PUCT may allow recovery on an annual basis of the reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges under a tariff approved by FERC.  The PUCT will initiate a rulemaking for this

 

27



 

process that is expected to take place largely in the first quarter of 2006.

 

Lamb County Electric CooperativeOn July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS. LCEC alleged that SPS had been unlawfully providing service to oil field customers and their facilities in LCEC’s singly-certificated area. The PUCT denied LCEC’s petition. See further discussion under Item 3 — Legal Proceedings.

 

Pending and Recently Concluded Regulatory Proceedings - NMPRC

 

New Mexico Fuel Review - On Jan. 28, 2005, the NMPRC accepted the staff petition for a review of SPS’ fuel and purchased power cost.  The staff requested a formal review of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) for the period of Oct. 1, 2001 through August 2004.  Hearings in the fuel review case have been scheduled for April 2006.

 

New Mexico Fuel Factor Continuation Filing - The filing to continue the use of SPS’ FPPCAC was made on Aug. 18, 2005.  This filing is required every two years pursuant to the NMPRC rules.  The filing proposes that the FPPCAC continue the current monthly factor cost recovery methodology.  Certain industrial customers have asked the NMPRC to review SPS’ assignment of system average fuel cost to certain wholesale capacity sales.  Customers have also asked the NMPRC to investigate the treatment of renewable energy certificates and sulfur dioxide allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause.   Hearings have been scheduled for April 2006, and a NMPRC decision is expected in late 2006.

 

Capacity and Demand

 

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2006, assuming normal weather, are listed below.

 

 

 

System Peak Demand (in MW)

 

 

 

2003

 

2004

 

2005

 

2006 Forecast (a)

 

 

 

 

 

 

 

 

 

 

 

SPS

 

4,661

 

4,679

 

4,667

 

4,603

 

 

The peak demand for the SPS system typically occurs in the summer.  The 2005 uninterrupted system peak demand for SPS occurred on July 25, 2005.

 

Energy Sources and Related Transmission Initiatives

 

SPS expects to use existing electric generating stations; purchases from other utilities, independent power producers and power marketers and demand-side management options to meet its net dependable system capacity requirements.

 

Purchased Power — SPS has contractual arrangements to purchase power from other utilities and nonregulated energy suppliers. Capacity, typically measured in KW or MW, is the measure of the rate at which a particular generating source produces electricity. Energy, typically measured in Kwh or Mwh, is a measure of the amount of electricity produced from a particular generating source over a period of time. Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

 

SPS also makes short-term firm and non-firm purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to provide the utility’s reserve obligation, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts, and for various other operating requirements.

 

Purchased Transmission Services — SPS has contractual arrangements with regional transmission service providers to deliver power and energy to the subsidiaries’ native load customers, which are retail and wholesale load obligations with terms of more than one year.  Point-to-point transmission services typically include a charge for the specific amount of transmission capacity being reserved, although some agreements may base charges on the amount of metered energy

 

28



 

delivered.  Network transmission services include a charge for the metered demand at the delivery point at the time of the provider’s monthly transmission system peak, usually calculated as a 12-month rolling average.

 

Fuel Supply and Costs

 

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

 

SPS Generating

 

Coal

 

Natural Gas

 

Average Fuel

 

Plants

 

Cost

 

Percent

 

Cost

 

Percent

 

Cost

 

 

 

 

 

 

 

 

 

 

 

 

 

2005

 

$

1.32

 

68

%

$

7.77

 

32

%

$

3.38

 

2004

 

$

1.20

 

69

%

$

5.74

 

31

%

$

2.60

 

2003*

 

$

0.93

 

73

%

$

5.24

 

27

%

$

2.10

 

 


* The lower 2003 SPS coal costs reflect a prior period fuel credit adjustment. The normalized cost per MMBtu was approximately $1.14.

 

See additional discussion of fuel supply and costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

 

Fuel Sources — SPS purchases all of its coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO, Inc. in the form of crushed, ready-to-burn coal delivered to the plant bunkers. TUCO, in turn, arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to the plant bunkers to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers. For the Harrington station, the coal supply contract with TUCO expires in 2016. For the Tolk station, the coal supply contract with TUCO expires in 2017.  At Dec. 31, 2005, coal supplies at the Harrington and Tolk sites were approximately 36 and 40 days supply, respectively.  See Item 7 – Management’s Discussion & Analysis for discussion of coal delivery disruptions.  TUCO has coal supply agreements to supply 100 percent of the projected 2006 requirements for Harrington and Tolk stations.  TUCO has long-term contracts for supply of coal in sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

 

SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas suppliers for SPS’ power plants are procured under short- and intermediate-term contracts to provide an adequate supply of fuel.

 

Commodity Marketing Operations

 

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. Participation in short-term wholesale energy markets provides market intelligence and information that supports the energy management of SPS.  SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. Engaging in short-term sales and purchase commitments results in an efficient use of our plants and the capturing of additional margins from non-traditional customers.  On a limited basis, SPS also uses these marketing operations to capture arbitrage opportunities created by regional pricing differentials, supply and demand imbalances and changes in fuel prices.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

 

29



 

Xcel Energy Electric Operating Statistics

 

 

 

Year Ended Dec. 31,

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Electric Sales (Millions of Kwh)

 

 

 

 

 

 

 

Residential

 

23,930

 

22,828

 

23,207

 

Commercial and Industrial

 

60,049

 

58,192

 

57,576

 

Public Authorities and Other

 

1,091

 

1,133

 

1,165

 

Total Retail

 

85,070

 

82,153

 

81,948

 

Sales for Resale

 

22,194

 

22,521

 

21,981

 

Total Energy Sold

 

107,264

 

104,674

 

103,929

 

 

 

 

 

 

 

 

 

Number of Customers at End of Period

 

 

 

 

 

 

 

Residential

 

2,791,859

 

2,800,338

 

2,769,468

 

Commercial and Industrial

 

400,035

 

401,744

 

398,605

 

Public Authorities and Other

 

75,937

 

79,777

 

80,875

 

Total Retail

 

3,267,831

 

3,281,859

 

3,248,948

 

Wholesale

 

128

 

206

 

211

 

Total Customers

 

3,267,959

 

3,282,065

 

3,249,159

 

 

 

 

 

 

 

 

 

Electric Revenues (Thousands of Dollars)

 

 

 

 

 

 

 

Residential

 

$

2,048,100

 

$

1,791,606

 

$

1,781,179

 

Commercial and Industrial

 

3,733,648

 

3,203,629

 

3,038,716

 

Public Authorities and Other

 

110,895

 

106,657

 

107,234

 

Total Retail

 

5,892,643

 

5,101,892

 

4,927,129

 

Wholesale

 

1,193,762

 

1,011,210

 

855,389

 

Other Electric Revenues

 

157,232

 

112,143

 

137,420

 

Total Electric Revenues

 

$

7,243,637

 

$

6,225,245

 

$

5,919,938

 

 

 

 

 

 

 

 

 

Kwh Sales per Retail Customer

 

26,033

 

25,032

 

25,223

 

 

 

 

 

 

 

 

 

Revenue per Retail Customer

 

$

1,803.23

 

$

1,554.57

 

$

1,516.53

 

 

 

 

 

 

 

 

 

Residential Revenue per Kwh

 

8.56

¢

7.85

¢

7.68

¢

 

 

 

 

 

 

 

 

Commercial and Industrial Revenue per Kwh

 

6.22

¢

5.51

¢

5.28

¢

 

 

 

 

 

 

 

 

Wholesale Revenue per Kwh

 

5.38

¢

4.49

¢

3.89

¢

 

30



 

NATURAL GAS UTILITY OPERATIONS

 

Natural Gas Utility Trends

 

Changes in regulatory policies and market forces have shifted the industry from traditional bundled natural gas sales service to an unbundled transportation and market-based commodity service at the wholesale level and for larger commercial and industrial retail customers. These customers have greater ability to buy natural gas directly from suppliers and arrange their own pipeline and retail LDC transportation service.

 

The natural gas delivery/transportation business has remained competitive as industrial and large commercial customers have the ability to bypass the local natural gas utility through the construction of interconnections directly with interstate pipelines, thereby avoiding the delivery charges added by the local natural gas utility.

 

As LDCs, NSP-Minnesota, NSP-Wisconsin and PSCo provide unbundled transportation service to large customers. Transportation service does not have an adverse effect on earnings because the sales and transportation rates have been designed to make them economically indifferent to whether natural gas has been sold and transported or merely transported. However, some transportation customers may have greater opportunities or incentives to physically bypass the LDCs’ distribution system.

 

The most significant recent developments in the natural gas operations of the utility subsidiaries was the substantial and continuing increases in wholesale natural gas market prices and the continued trend toward declining use per customer by residential customers as a result of improved building construction technologies and higher appliance efficiencies.  From 1995 to 2005, average annual sales to the typical residential customer declined from 104 Dth per year to 87 Dth per year on a weather-normalized basis.  Although recent wholesale price increases do not directly affect earnings because of gas cost recovery mechanisms, the high prices are expected to encourage further efficiency efforts by customers.

 

NSP-Minnesota

 

Ratemaking Principles

 

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s gas supply plans for meeting customers’ future energy needs.

 

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

 

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5 percent of Minnesota natural gas revenue on conservation improvement programs. These costs are recovered through an annual cost recovery mechanism for natural gas conservation and energy management program expenditures. NSP-Minnesota is required to request a new cost recovery level annually.

 

Pending and Recently Concluded Regulatory Proceedings

 

NSP-Minnesota Natural Gas Rate Case - In September 2004, NSP-Minnesota filed a natural gas rate case for its Minnesota retail customers, seeking a rate increase of $9.9 million, based on a return on equity of 11.5 percent.  In August 2005, the MPUC approved an annual rate increase of $5.8 million, based on a return on equity of 10.4 percent. Final rates became effective Dec. 1, 2005.

 

31



 

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 611,950 MMBtu for 2005, which occurred on Jan. 5, 2005.

 

NSP-Minnesota purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 521,854 MMBtu/day. In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 21 percent of winter natural gas requirements and 26 percent of peak day, firm requirements of NSP-Minnesota.

 

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalent and three propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 250,300 MMBtu of natural gas per day, or approximately 34 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. NSP-Minnesota’s 2004-2005 entitlement levels were approved on July 12, 2005 which allow NSP-Minnesota to recover the demand entitlement costs associated with the increase in transportation, supply, and storage levels in its monthly PGA. In June 2005, NSP-Minnesota also filed to add incremental storage to its portfolio.  The increase in storage was approved by the MPUC on Nov. 18, 2005.  The 2005-2006 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. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

 

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

 

2005

 

$

8.90

 

2004

 

$

6.88

 

2003

 

$

5.47

 

 

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

 

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2006 through 2027.

 

NSP-Minnesota has certain natural gas supply and transportation 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, 2005, NSP-Minnesota was committed to approximately $810 million in such obligations under these contracts.

 

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 25 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

 

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

 

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NSP-Wisconsin

 

Ratemaking Principles

 

Summary of Regulatory Agencies and Areas of Jurisdiction NSP-Wisconsin is regulated by the PSCW and the MPSC.

 

The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. The filing procedure and review generally allow the PSCW sufficient time to issue an order and implement new base rates effective with the start of the test year.

 

Natural Gas Cost Recovery Mechanisms NSP-Wisconsin has a retail gas cost recovery mechanism for Wisconsin operations to recover changes in the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds the utility was not prudent in its procurement activities.

 

NSP-Wisconsin’s gas rate schedules for Michigan customers include a gas cost recovery factor, which is based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

 

Pending and Recently Concluded Regulatory Proceedings - PSCW

 

See NSP-Wisconsin 2006 General Rate Case discussion under Pending and Recently Concluded Regulatory Proceedings - PSCW in NSP-Wisconsin’s Electric Utility Operations section above.

 

Capability and Demand

 

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 154,040 MMBtu for 2005, which occurred on Jan. 17, 2005.

 

NSP-Wisconsin purchases natural gas from independent suppliers. The natural gas is delivered under natural gas transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 122,872 MMBtu/day. In addition, NSP-Wisconsin has contracted with providers of underground natural gas storage services. These storage agreements provide storage for approximately 21 percent of winter natural gas requirements and 29 percent of peak day, firm requirements of NSP-Wisconsin.

 

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 14 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

 

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2005-2006 supply plan was approved by the PSCW in October 2005.

 

Natural Gas Supply and Costs

 

NSP-Wisconsin actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

 

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

 

2005

 

$

8.64

 

2004

 

$

7.00

 

2003

 

$

6.23

 

 

The cost of natural gas supply, transportation service and storage service is recovered through various cost recovery adjustment mechanisms.

 

NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2006 through 2027.

 

33



 

NSP-Wisconsin has certain natural gas supply and transportation 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, 2005, NSP-Wisconsin was committed to approximately $145 million in such obligations under these contracts.

 

NSP-Wisconsin purchased firm natural gas supply utilizing short-term agreements from approximately 25 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

 

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

 

PSCo

 

Ratemaking Principles

 

Summary of Regulatory Agencies and Areas of Jurisdiction PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities.  PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the federal Natural Gas Act.

 

Purchased Gas and Conservation Cost Recovery Mechanisms PSCo has a GCA mechanism, which allows PSCo to recover its actual costs of purchased gas.  The GCA is revised monthly to allow for changes in gas rates.

 

Performance-based Regulation and Quality of Service Requirements — The CPUC established a combined electric and natural gas quality of service plan.  See further discussion under Item 1, Electric Utility Operations.

 

Pending and Recently Concluded Regulatory Proceedings

 

PSCo Natural Gas Rate Case — In 2005, PSCo filed for an increase of $34.5 million in natural gas base rates in Colorado, based on a return on equity of 11.0 percent with a common equity ratio of 55.49 percent.

 

On Jan. 19, 2006, the CPUC approved a settlement agreement between PSCo and other parties to the case.  Final rates became effective Feb. 6, 2006. The terms of the settlement include:

 

      Natural gas revenue increase of $22 million;

      Return on common equity of 10.5 percent;

      Earnings in excess of 10.5 percent return on common equity will be refunded back to customers;

      Common equity ratio of 55.49 percent; and

      Customer charges for the residential and commercial sales classes of $10 and $20 per month, respectively.

 

Capability and Demand

 

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation, which include transportation customers contracting for firm supply backup, to be 1,792,770 MMBtu. In addition, firm transportation customers hold 489,014 MMBtu of capacity for PSCo without supply backup.  Total firm delivery obligation for PSCo is 2,281,784 MMBtu per day. The maximum daily deliveries for PSCo in 2005 for firm and interruptible services were 1,871,486 MMBtu on Dec. 7, 2005.

 

PSCo purchases natural gas from independent suppliers. The natural gas supplies are delivered to the respective delivery systems through a combination of transportation agreements with interstate pipelines and deliveries by suppliers directly to each company. These agreements provide for firm deliverable pipeline capacity of approximately 1,802,524 MMBtu/day, which includes 831,866 MMBtu of supplies held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide about 40,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at the companies’ city gate meter stations and a small amount is received directly from wellhead sources.

 

PSCo has closed the Leyden Storage Field and is in the monitoring phase of the abandonment process, which is expected to continue until December 2007. See further discussion at Note 14 to the Consolidated Financial Statements.

 

PSCo is required by CPUC regulations to file a natural gas purchase plan by June of each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the period beginning July

 

34



 

1 through June 30 of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the 12-month period ending the previous June 30.

 

Natural Gas Supply and Costs

 

PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk, and economical rates. This diversification involves numerous supply sources with varied contract lengths.

 

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

 

2005

 

$

8.01

 

2004

 

$

6.30

 

2003

 

$

4.94

 

 

PSCo has certain natural gas supply and transportation 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, 2005, PSCo was committed to approximately $1.4 billion in such obligations under these contracts, which expire in various years from 2006 through 2025.

 

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2005, PSCo purchased natural gas from approximately 37 suppliers.

 

See additional discussion of natural gas costs under Factors Affecting Results of Continuing Operations in Management’s Discussion and Analysis under Item 7.

 

35



 

Xcel Energy Gas Operating Statistics

 

 

 

Year Ended Dec. 31,

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Gas Deliveries (Thousands of MMBtu)

 

 

 

 

 

 

 

Residential

 

135,794

 

134,512

 

139,107

 

Commercial and Industrial

 

83,667

 

86,053

 

90,937

 

Total Retail

 

219,461

 

220,565

 

230,044

 

Transportation and Other

 

134,061

 

116,593

 

117,343

 

Total Deliveries

 

353,522

 

337,158

 

347,387

 

 

 

 

 

 

 

 

 

Number of Customers at End of Period

 

 

 

 

 

 

 

Residential

 

1,636,652

 

1,612,047

 

1,576,438

 

Commercial and Industrial

 

145,067

 

145,153

 

147,427

 

Total Retail

 

1,781,719

 

1,757,200

 

1,723,865

 

Transportation and Other

 

3,764

 

3,544

 

3,298

 

Total Customers

 

1,785,483

 

1,760,744

 

1,727,163

 

 

 

 

 

 

 

 

 

Gas Revenues (Thousands of Dollars)

 

 

 

 

 

 

 

Residential

 

$

1,450,316

 

$

1,180,120

 

$

1,018,782

 

Commercial and Industrial

 

794,230

 

660,227

 

592,623

 

Total Retail

 

2,244,546

 

1,840,347

 

1,611,405

 

Transportation and Other

 

62,839

 

75,167

 

66,363

 

Total Gas Revenues

 

$

2,307,385

 

$

1,915,514

 

$

1,677,768

 

 

 

 

 

 

 

 

 

Dth Sales per Retail Customer

 

123.17

 

125.52

 

133.45

 

 

 

 

 

 

 

 

 

Revenue per Retail Customer

 

$

1,259.76

 

$

1,047.32

 

$

934.76

 

 

 

 

 

 

 

 

 

Residential Revenue per MMBtu

 

$

10.68

 

$

8.77

 

$

7.32

 

 

 

 

 

 

 

 

 

Commercial and Industrial Revenue per MMBtu

 

$

9.49

 

$

7.67

 

$

6.52

 

 

 

 

 

 

 

 

 

Transportation and Other Revenue per MMBtu

 

$

0.47

 

$

0.63

 

$

0.57

 

 

36



 

ENVIRONMENTAL MATTERS

 

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

 

Xcel Energy and its subsidiaries strive to comply with all environmental regulations applicable to its operations. However, it is not possible at this time 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, generally, what effect future laws or regulations may have upon Xcel Energy’s operations. For more information on environmental contingencies, see Notes 14 and 15 to the Consolidated Financial Statements, environmental matters in Management’s Discussion and Analysis under Item 7 and the matter discussed below.

 

Levee Station Manufactured Gas Plant Site — A portion of NSP-Minnesota’s High Bridge plant coal yard is located on the site of the former Levee Station MGP site. The Levee Station was a coke-oven gas purification, storage and distribution facility.  The Levee Station supplied manufactured gas to the city of St. Paul from 1918 to the early 1950s.  In the 1950s, the facility was demolished, and the High Bridge coal yard was extended onto the property.  In the 1990s, the site was investigated and partially remediated at a cost of approximately $2.9 million.  In 2006, NSP-Minnesota plans to commence construction of the High Bridge Combined Cycle Generating Plant, as part of the MERP, on the site of the Levee Station. The construction of the new plant required the removal of buried structures and soil and groundwater remediation. Remediation activities were essentially completed in 2005 at a cost of $3.5 million, which will be accounted for as a capital expenditure of the MERP project.

 

CAPITAL SPENDING AND FINANCING

 

For a discussion of expected capital expenditures and funding sources, see Management’s Discussion and Analysis under Item 7.

 

EMPLOYEES

 

The number of full-time Xcel Energy employees in continuing operations at Dec. 31, 2005, is presented in the table below. Of the full-time employees listed below, 5,459 or 56 percent, are covered under collective bargaining agreements.

 

NSP-Minnesota*

 

2,642

 

NSP-Wisconsin

 

538

 

PSCo

 

2,595

 

SPS

 

1,041

 

Xcel Energy Services Inc.

 

2,961

 

Other subsidiaries

 

4

 

Total

 

9,781

 

 


* NSP-Minnesota full-time employees include 347 employees loaned to the NMC. In addition, the NMC has 712 full-time employees of its own.

 

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EXECUTIVE OFFICERS

 

Richard C. Kelly, 59, Chairman of the Board, Xcel Energy Inc., December 2005 to present; Chief Executive Officer, Xcel Energy Inc., July 2005 to present; President, Xcel Energy Inc., October 2003 to present. Previously, Chief Operating Officer, Xcel Energy Inc., October 2003 to June 2005, Vice President and Chief Financial Officer, Xcel Energy Inc., August 2002 to October 2003 and President — Enterprises Business Unit, Xcel Energy, August 2000 to August 2002.

 

Paul J. Bonavia, 54, President — Utilities Group, Xcel Energy, November 2005 to present; Vice President, Xcel Energy Services Inc., September 2000 to present. Previously, President — Commercial Enterprises Business Unit, Xcel Energy, December 2003 to October 2005 and President — Energy Markets Business Unit, Xcel Energy, August 2000 to December 2003.

 

Benjamin G.S. Fowke III, 47, Chief Financial Officer, Xcel Energy Inc., October 2003 to present; Vice President, Xcel Energy Inc., November 2002 to present.  Previously, Treasurer, Xcel Energy Inc., November 2002 to May 2004 and Vice President and Chief Financial Officer — Energy Markets Business Unit, Xcel Energy, August 2000 to November 2002.

 

Gary L. Gibson, 64, President, SPS, December 2000 to present; Chief Executive Officer, SPS, August 2001 to present.

 

Raymond E. Gogel, 55, Vice President, Xcel Energy Services Inc., April 2002 to present; Chief Information Officer, Xcel Energy Services Inc., April 2002 to February 2006 Vice President Customer and Enterprise Solutions Group, Chief Human Resource Officer and Chief Administrative Officer, November 2005 to present.  Previously, Vice President and Senior Client Services Principal, IBM Global Services, April 2001 to April 2002 and Senior Project Executive, IBM Global Services, April 1999 to April 2001.

 

Cathy J. Hart, 56, Vice President and Corporate Secretary, Xcel Energy Inc., August 2000 to present; Vice President, Corporate Services Group, November 2005 to present.

 

Gary R. Johnson, 59, Vice President and General Counsel, Xcel Energy Inc., August 2000 to present.

 

Cynthia L. Lesher, 57, President and Chief Executive Officer, NSP-Minnesota, October 2005 to present. Previously, Chief Administrative Officer, Xcel Energy, August 2000 to October 2005 and Chief Human Resources Officer, Xcel Energy, July 2001 to October 2005.

 

Teresa S. Madden, 49, Vice President and Controller, Xcel Energy Inc., January 2004 to present. Previously, Vice President of Finance — Customer and Field Operations Business Unit, Xcel Energy, August 2003 to January 2004, Interim CFO, Rogue Wave Software, Inc., February 2003 to July 2003 and Corporate Controller, Rogue Wave Software, Inc., October 2000 to February 2003.

 

Michael L. Swenson, 55, President and Chief Executive Officer, NSP-Wisconsin, February 2002 to present. Previously, State Vice President for North Dakota and South Dakota, August 2000 to February 2002.

 

George E. Tyson II, 40, Vice President and Treasurer, Xcel Energy Inc., May 2004 to present.  Previously, Managing Director and Assistant Treasurer, Xcel Energy, July 2003 to May 2004; Director of Origination — Energy Markets Business Unit, Xcel Energy, May 2002 to July 2003; Associate and Vice President, Deutsche Bank Securities, December 1996 to April 2002.

 

Patricia K. Vincent, 47, President and Chief Executive Officer, PSCo, October 2005 to present.  Previously, President — Customer and Field Operations Business Unit, Xcel Energy, July 2003 to October 2005, President — Retail Business Unit, Xcel Energy, March 2001 to July 2003 and Vice President of Marketing and Sales, Xcel Energy Services Inc., August 2000 to March 2001.

 

David M. Wilks, 59, Vice President, Xcel Energy Services, Inc., September 2000 to present; President — Energy Supply Group, Xcel Energy, August 2000 to present.

 

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

 

38



 

Item 1A — Risk Factors

 

Risks Associated with Our Business

 

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

 

We are subject to comprehensive regulation by several federal and state utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility commissions in the states where our utility subsidiaries operate regulate many aspects of our utility operations including siting and construction of facilities, customer service and the rates that we can charge customers.

 

The profitability of our utility operations is dependent on our ability to recover costs related to providing energy and utility services to our customers.  Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of the utility’s expenses incurred in a test year.  Thus, the rates a utility is allowed to charge may or may not match its expenses at any given time.  While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.   Although we believe that the current regulatory environment applicable to our business would permit us to recover the costs of our utility services, it is possible that there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers. 

 

State utility commissions generally possess broad powers to ensure that the needs of the utility customers are being met. The state utility commissions also may seek to impose restrictions on the ability of our utility subsidiaries to pay dividends to us. If successful, this could materially and adversely affect our ability to meet our financial obligations, including paying dividends on our common stock.

 

The FERC has jurisdiction over wholesale rates for electric transmission service, electric energy sold at wholesale in interstate commerce, hydro facility licensing and certain other activities of our utility subsidiaries. Federal, state and local agencies also have jurisdiction over many of our other activities, including regulation of retail rates and environmental matters. 

 

We are unable to predict the impact on our operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations 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 paying dividends on our common stock.

 

We are subject to commodity price risk, credit risk and other risks associated with energy markets.

 

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and, accordingly, are subject to commodity price risk, credit risk and other risks associated with these activities.

 

We are exposed to market and credit risks in our generation, distribution, commodity acquisition, short-term wholesale and commodity trading activities.  To minimize the risk of market price fluctuations and product availability, we enter into physical and financial contracts to hedge both price and availability risk associated with purchase and sale commitments, fuel requirements and inventories of coal, natural gas, fuel oil and energy and energy-related products.  However, these contracts do not completely eliminate risks, including commodity price changes, market supply shortages, credit risk and interest rate changes. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales commitments or increased interest expense.

 

Credit and performance risk includes the risk that 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.

 

We mark commodity trading derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which causes earnings variability. Quoted market prices are utilized in determining the value of these derivative commodity instruments.  For positions for which market prices are not available, we utilize models based on forward price curves. These

 

39



 

models incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions.

 

Our subsidiary, PSCo, has received a notice from the Internal Revenue Service (IRS) proposing to disallow certain interest expense deductions that PSCo claimed in 1993 through 1999. Should the IRS ultimately prevail on this issue, our liquidity position and financial results could be materially adversely affected.

 

PSCo’s wholly owned subsidiary PSR Investments, Inc. (PSRI) owns and manages permanent life insurance policies on some of PSCo’s employees, known as corporate-owned life insurance (COLI). At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999.

 

We believe that the tax deduction of interest expense on the COLI policy loans is in full compliance with the law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.

 

In April 2004, Xcel Energy filed a lawsuit against the government in the U.S. District Court for the District of Minnesota to establish its right to deduct the policy loan interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its COLI policies.

 

After Xcel Energy had filed this suit, the IRS sent it two statutory notices of proposed deficiency of tax, penalty, and interest for taxable years 1995 through 1999.  Xcel Energy then timely filed two Tax Court petitions challenging those notices.  Xcel Energy anticipates that the dispute relating to its claimed interest expense deductions for tax years 1993 and later will be resolved in the refund suit that is pending in the Minnesota federal district court and that the two Tax Court petitions will be held in abeyance pending the outcome of the refund litigation.

 

On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material fact that required a trial for resolution.  At the same time, the district court denied the government’s motion for summary judgment that was based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies.  However, the district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest.  The case is expected to proceed to trial and the litigation could take another two or more years.

 

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.  As discussed above, the litigation could require several years to reach final resolution.  Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.  Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position, results of operations and cash flows. 

 

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce retained earnings by an estimated $361 million.  In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2005, is approximately $428 million.  Xcel Energy annual earnings for 2006 would be reduced by approximately $44 million, after tax, which represents 10 cents per share, if COLI interest expense deductions were no longer available.

 

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

 

We are subject to a number of environmental laws and regulations affecting many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the management of wastes and hazardous substances.  These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to perform environmental remediations and to install pollution control equipment at our facilities.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We must pay all or a portion of the cost to remediate sites where our past activities, or the activities of certain other parties, caused environmental

 

40



 

contamination.  At December 31, 2005, these sites included:

 

 the site of a former federal uranium enrichment facility;

 the sites of former manufactured gas plants operated by our subsidiaries or predecessors; and

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

 

In addition, we cannot assure you that existing environmental laws or regulations will not be revised or that new laws or regulations seeking to protect the environment will not be adopted or become applicable to us or that we will not identify in the future conditions that will result in obligations or liabilities under existing environmental laws and regulations.  Revised or additional laws or regulations which result in increased compliance costs or additional operating restrictions, or currently unanticipated costs or restrictions under existing laws or regulations, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our results of operations.

 

For further discussion see Note 14 to the Consolidated Financial Statements.

 

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

 

NSP-Minnesota’s two nuclear stations, Prairie Island and Monticello, subject it to the risks of nuclear generation, which include:

 

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

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

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

 

The Nuclear Regulatory Commission (NRC) has broad authority under federal law 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 safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-Minnesota’s nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident, if an incident did occur, it could have a material adverse effect on our results of operations or financial condition. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.

 

Recession, grid disturbances, acts of war or terrorism could negatively impact our business.

 

The consequences of a prolonged recession and adverse market conditions may include the continued uncertainty of energy prices and the capital and commodity markets. We cannot predict the impact of any economic slowdown or fluctuating energy prices. However, such impact could have a material adverse effect on our financial condition and results of operations.

 

Also, because our generation and transmission systems are part of an interconnected regional grid, we face the risk of possible loss of business due to a disruption or black-out caused by an event (severe storm, generator or transmission facility outage) on a neighboring system or the actions of a neighboring utility, similar to the Aug. 14, 2003 black-out in portions of the eastern U.S. and Canada. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results of operations.

 

The conflict in Iraq and any other military strikes or sustained military campaign may affect our operations in unpredictable ways and may cause changes in the insurance markets, force us to increase security measures and cause disruptions of fuel supplies and markets, particularly with respect to natural gas and purchased energy. The possibility that infrastructure facilities, such as electric generation, transmission and distribution facilities, would be direct targets of, or indirect casualties of, an act of war may affect our operations. War and the possibility of further war may have an adverse impact on the economy in general. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets as a result of war may also affect our ability to raise capital.

 

41



 

Further, like other operators of major industrial facilities, our generation plants, fuel storage facilities and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business.  While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, including our nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel.

 

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

 

Reduced coal availability could negatively impact our business.

 

Xcel Energy’s coal generation portfolio is heavily dependent on coal supplies located in the Powder River Basin of Wyoming.  Approximately 70 percent of our annual coal requirement comes from this area. Coal generation comprises approximately 60 percent to 85 percent of our annual generation for the operating utilities.  In the first half of 2005, we began experiencing disruptions in our coal deliveries from the Powder River Basin, which continued throughout the year and are expected to continue at least through part of 2006.  In response to these disruptions Xcel Energy mitigated the impact of reduced coal deliveries, by modifying the dispatch of certain facilities to conserve coal inventories. In addition to the mitigation efforts, Xcel Energy negotiated for the acquisition of additional, higher capacity rail cars and is working to upgrade certain coal handling facilities with completion anticipated in the first half of 2006.  Despite, these efforts, coal inventories have declined to below target levels. While we have secured, under contract, approximately 99 percent of our anticipated 2006 coal requirements, we cannot predict with any certainty the likelihood of receiving the required coal.  This factor, combined with the currently low inventory levels, has led us to continue coal mitigation.  While we are planning to rebuild inventories during 2006, there is no guarantee that we will be able to do so.   The ultimate impact of coal availability cannot be fully assessed at this time, but could impact our future results. 

 

Rising energy prices could negatively impact our business.

 

A variety of market factors have contributed to higher natural gas prices.  The direct impact of these higher costs is generally mitigated for Xcel Energy through recovery of such costs from customers through various fuel cost recovery mechanisms.  However, higher fuel costs could significantly impact the results of operations, if requests for recovery are unsuccessful.  In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on Xcel Energy’s results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases are expected to have an impact on the cash flows of Xcel Energy.  Xcel Energy is unable to predict the future natural gas prices or the ultimate impact of such prices on its results of operations or cash flows.

 

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

 

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

 

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

 

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

 

42



 

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

 

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

 

We have defined benefit 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 earnings and funding requirements.  Based on our assumptions at Dec. 31, 2005 and assuming continuation of the current federal interest rate relief beyond 2005, in order to maintain required funding levels for our pension plans, we do not expect to make required future contributions.  However, it is our practice to make voluntary contributions to maintain more prudent funding levels than minimally required.  These amounts are estimates and may change based on actual stock market performance, changes in interest rates and any changes in governmental regulations.  Therefore, contributions could be required in the future.

 

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

 

Risks Associated with Our Holding Company Structure

 

We must rely on cash from our subsidiaries to make dividend payments.

 

We are a holding company and thus our investments in our subsidiaries are our primary assets. Substantially all of our operations are conducted by our subsidiaries. Consequently, our operating cash flow and our ability to service our indebtedness and pay dividends, depends upon the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends. Our subsidiaries are separate legal entities that have no obligation to pay any amounts due pursuant to our obligations or to make any funds available for that purpose or for dividends on our common stock, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any statutory and/or contractual restrictions that may be applicable to such subsidiary, which may include requirements to maintain minimum levels of equity ratios, working capital or other assets.

 

Our utility subsidiaries are regulated by various state utility commissions which generally possess broad powers to ensure that the needs of the utility customers are being met. To the extent that the state commissions attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends to us, it could adversely affect our ability to pay dividends on our common stock and preferred stock or otherwise meet our financial obligations.

 

Our utility subsidiaries are  subject to regulatory restrictions on accessing capital.

 

Financings by our utility subsidiaries are subject to prior approval by the applicable state regulatory commission and, possibly, by the FERC.  The state utility commissions generally posses broad powers to ensure the needs of the utility customers are being met and there is no assurance they will authorize financings in amounts requested by our utility subsidiaries.

 

For additional information regarding our liquidity and capital resources, see Item 7 – Management’s Discussion and Analysis.

 

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

 

We cannot assure you that any of our current ratings or our subsidiaries’ ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.  Any future downgrade could increase the cost of short-term borrowings but would not result in any defaults or accelerations as a result of the rating changes.  Any downgrade could lead to higher borrowing costs.

 

43



 

Certain provisions of law, as well as provisions in our bylaws and shareholder rights plan, may make it more difficult for others to obtain control of us, even though some shareholders might consider this favorable.

 

We are a Minnesota corporation and certain anti-takeover provisions of Minnesota law apply to us and create various impediments to the acquisition of control of us or to the consummation of certain business combinations with us.  In addition, our shareholder rights plan contains provisions which may make it more difficult to effect certain business combinations with us without the approval of our board of directors.  Finally, certain federal and state utility regulatory statutes may also make it difficult for another party to acquire a controlling interest in us.  These provisions of law and of our corporate documents, individually or in the aggregate, could discourage a future takeover attempt which individual shareholders might deem to be in their best interests or in which shareholders would receive a premium for their shares over current prices.

 

Item 1B — Unresolved SEC Staff Comments

 

None.

 

Item 2 — Properties

 

Virtually all of the utility plant of NSP-Minnesota and NSP-Wisconsin is subject to the lien of their first mortgage bond indentures.  Virtually all of the electric utility plant of PSCo is subject to the lien of its first mortgage bond indenture.

 

Electric utility generating stations:

 

NSP-Minnesota

 

 

Station, City and
Unit

 

Fuel

 

Installed

 

Summer 2005 Net
Dependable
Capability (MW)

 

Steam:

 

 

 

 

 

 

 

Sherburne-Becker, MN

 

 

 

 

 

 

 

Unit 1

 

Coal

 

1976

 

697

 

Unit 2

 

Coal

 

1977

 

682

 

Unit 3

 

Coal

 

1987

 

504

(a) 

Prairie Island-Welch, MN

 

 

 

 

 

 

 

Unit 1

 

Nuclear

 

1973

 

523

 

Unit 2

 

Nuclear

 

1974

 

522

 

Monticello-Monticello, MN

 

Nuclear

 

1971

 

572

 

King-Bayport, MN

 

Coal

 

1968

 

528

 

Black Dog-Burnsville, MN

 

 

 

 

 

 

 

2 Units

 

Coal/Natural Gas

 

1955-1960

 

282

 

2 Units

 

Natural Gas

 

2002

 

298

 

High Bridge-St. Paul, MN

 

 

 

 

 

 

 

2 Units

 

Coal

 

1956-1959

 

271

 

Riverside-Minneapolis, MN

 

 

 

 

 

 

 

2 Units

 

Coal

 

1964-1987

 

381

 

Combustion Turbine:

 

 

 

 

 

 

 

Angus Anson-Sioux Falls, SD

 

 

 

 

 

 

 

3 Units

 

Natural Gas

 

1994-2005

 

384

 

Inver Hills-Inver Grove Heights, MN

 

 

 

 

 

 

 

6 Units

 

Natural Gas

 

1972

 

350

 

Blue Lake-Shakopee, MN

 

 

 

 

 

 

 

6 Units

 

Natural Gas

 

1974-2005

 

490

 

Other

 

Various

 

Various

 

261

 

 

 

 

 

Total

 

6,745

 

 


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

 

44



 

 

NSP-Wisconsin

 

Station, City and
Unit

 

Fuel

 

Installed

 

Summer 2005 Net
Dependable
Capability (MW)

 

 

 

 

 

 

 

 

 

Combustion Turbine:

 

 

 

 

 

 

 

Flambeau Station-Park Falls, WI - 1 Unit

 

Natural Gas/Oil

 

1969

 

13

 

Wheaton-Eau Claire, WI - 6 Units

 

Natural Gas/Oil

 

1973

 

353

 

French Island-La Crosse, WI - 2 Units

 

Oil

 

1974

 

147

 

 

 

 

 

 

 

 

 

Steam:

 

 

 

 

 

 

 

Bay Front-Ashland, WI - 3 Units

 

Coal/Wood/Natural Gas

 

1945-1960

 

73

 

French Island-La Crosse, WI - 2 Units

 

Wood/RDF*

 

1940-1948

 

29

 

 

 

 

 

 

 

 

 

Hydro:

 

 

 

 

 

 

 

19 Plants

 

 

 

Various

 

254

 

 

 

 

 

Total

 

869

 

 


* RDF is refuse-derived fuel, made from municipal solid waste.

 

45



 

 

PSCo

 

Station, City and
Unit

 

Fuel

 

Installed

 

Summer 2005 Net
Dependable
Capability (MW)

 

 

 

 

 

 

 

 

 

Steam:

 

 

 

 

 

 

 

Arapahoe-Denver, CO 2 Units

 

Coal

 

1950-1955

 

156

 

Cameo-Grand Junction, CO 2 Units

 

Coal

 

1957-1960

 

73

 

Cherokee-Denver, CO 4 Units

 

Coal

 

1957-1968

 

717

 

Comanche-Pueblo, CO 2 Units

 

Coal

 

1973-1975

 

660

 

Craig-Craig, CO 2 Units

 

Coal

 

1979-1980

 

83

(a) 

Hayden-Hayden, CO 2 Units

 

Coal

 

1965-1976

 

237

(b) 

Pawnee-Brush, CO

 

Coal

 

1981

 

505

 

Valmont-Boulder, CO

 

Coal

 

1964

 

186

 

Zuni-Denver, CO 2 Units

 

Natural Gas/Oil

 

1948-1954

 

107

 

 

 

 

 

 

 

 

 

Combustion Turbines:

 

 

 

 

 

 

 

Fort St. Vrain-Platteville, CO 4 Units

 

Natural Gas

 

1972-2001

 

690

 

Various Locations 6 Units

 

Natural Gas

 

Various

 

174

 

 

 

 

 

 

 

 

 

Hydro:

 

 

 

 

 

 

 

Various Locations 12 Units

 

 

 

Various

 

32

 

Cabin Creek-Georgetown, CO Pumped Storage

 

 

 

1967

 

210

 

 

 

 

 

 

 

 

 

Wind:

 

 

 

 

 

 

 

Ponnequin-Weld County, CO

 

 

 

1999-2001

 

 

 

 

 

 

 

 

 

 

Diesel Generators:

 

 

 

 

 

 

 

Cherokee-Denver, CO 2 Units

 

 

 

1967

 

6

 

 

 

 

 

Total

 

3,836

 

 


(a)  Based on PSCo’s ownership interest of 9.7 percent.

 

(b)  Based on PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2.

 

46



 

SPS

 

Station, City and
Unit

 

Fuel

 

Installed

 

Summer 2005 Net
Dependable
Capability (MW)

 

 

 

 

 

 

 

 

 

Steam:

 

 

 

 

 

 

 

Harrington-Amarillo, TX 3 Units

 

Coal

 

1976-1980

 

1,066

 

Tolk-Muleshoe, TX 2 Units

 

Coal

 

1982-1985

 

1,080

 

Jones-Lubbock, TX 2 Units

 

Natural Gas

 

1971-1974

 

486

 

Plant X-Earth, TX 4 Units

 

Natural Gas

 

1952-1964

 

442

 

Nichols-Amarillo, TX 3 Units

 

Natural Gas

 

1960-1968

 

457

 

Cunningham-Hobbs, NM 2 Units

 

Natural Gas

 

1957-1965

 

267

 

Maddox-Hobbs, NM

 

Natural Gas

 

1983

 

118

 

CZ-2-Pampa, TX

 

Purchased Steam

 

1979

 

26

 

Moore County-Amarillo, TX

 

Natural Gas

 

1954

 

48

 

 

 

 

 

 

 

 

 

Gas Turbine:

 

 

 

 

 

 

 

Carlsbad-Carlsbad, NM

 

Natural Gas

 

1977

 

13

 

CZ-1-Pampa, TX

 

Hot Nitrogen

 

1965

 

13

 

Maddox-Hobbs, NM

 

Natural Gas

 

1983

 

65

 

Riverview-Electric City, TX

 

Natural Gas

 

1973

 

23

 

Cunningham-Hobbs, NM 2 Units

 

Natural Gas

 

1998

 

220

 

Diesel:

 

 

 

 

 

 

 

Tucumcari-NM 6 Units

 

 

 

1941-1968

 

 

 

 

 

 

Total

 

4,324

 

 

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2005:

 

Conductor Miles

 

NSP-Minnesota

 

NSP-Wisconsin

 

PSCo

 

SPS

 

 

 

 

 

 

 

 

 

 

 

500 KV

 

2,917

 

 

 

 

345 KV

 

5,648

 

1,312

 

832

 

5,139

 

230 KV

 

1,704

 

 

10,892

 

9,408

 

161 KV

 

295

 

1,494

 

 

 

138 KV

 

 

 

92

 

 

115 KV

 

6,443

 

1,529

 

4,844

 

10,918

 

Less than 115 KV

 

80,534

 

31,561

 

70,471

 

22,519

 

 

Electric utility transmission and distribution substations at Dec. 31, 2005:

 

 

 

NSP-Minnesota

 

NSP-Wisconsin

 

PSCo

 

SPS

 

 

 

 

 

 

 

 

 

 

 

Quantity

 

363

 

202

 

208

 

465

 

 

Gas utility mains at Dec. 31, 2005:

 

 

Miles

 

NSP-Minnesota

 

NSP-Wisconsin

 

PSCo

 

WGI

 

 

 

 

 

 

 

 

 

 

 

Transmission

 

120

 

 

2,300

 

12

 

Distribution

 

9,173

 

2,113

 

20,168

 

 

 

47



 

Item 3 — Legal Proceedings

 

In the normal course of business, various lawsuits and claims have arisen against Xcel Energy in addition to the regulatory matters discussed in Item 1. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

 

Legal Contingencies

 

Nuclear Waste Disposal Litigation — The federal government has the responsibility to dispose of domestic spent nuclear fuel and other high-level radioactive substances. The Nuclear Waste Policy Act (the Act) requires the DOE to implement this disposal program. This includes the siting, licensing, construction and operation of a permanent repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive substances.   The Act and contracts between DOE and domestic utilities obligated DOE to begin to dispose of these materials by Jan. 31, 1998.  The federal government has designated the site as Yucca Mountain in Nevada. The nuclear waste disposal program has resulted in extensive litigation.

 

On June 8, 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting  breach of contract damages in excess of $1 billion for the DOE’s failure to meet the 1998 deadline.  NSP-Minnesota has demanded damages consisting of the added costs of storage of spent nuclear fuel at the Prairie Island and Monticello nuclear generating plants, costs related to the Private Fuel Storage, LLC and certain costs relating to the 1994 and 2003 state legislation relating to the storage of spent nuclear fuel at Prairie Island.  On July 31, 2001, the Court granted NSP-Minnesota’s motion for partial summary judgment on liability.  The Court has set the start of the trial on Oct. 23, 2006.

 

On July 9, 2004, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision in consolidated cases challenging regulations and decisions on the federal nuclear waste program. The Court of Appeals rejected challenges by the state of Nevada and other intervenors with respect to most of the NRC’s challenged repository licensing regulations, the congressional resolution approving Yucca Mountain as the site of the permanent repository, and the DOE and presidential actions leading to the approval of the Yucca Mountain site. The Court of Appeals vacated the 10,000 year compliance period adopted by EPA regulations governing spent nuclear fuel disposal at Yucca Mountain and incorporated in the NRC regulations. Xcel Energy has not ascertained the impact of the decision on its nuclear operations and storage of spent nuclear fuel; however, the decision may result in additional delay and uncertainty around disposal of spent nuclear fuel.

 

Lamb County Electric Cooperative (SPS) — On July 24, 1995, LCEC petitioned the PUCT for a cease and desist order against SPS alleging that SPS was unlawfully providing service to oil field customers in LCEC’s certificated area.  On May 23, 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS was granted a certificate in 1976 to serve the disputed customers.  LCEC appealed the decision to the District Court in Travis County, Texas and on Aug. 12, 2004, the District Court affirmed the decision of the PUCT.  On Sept. 9, 2004, LCEC appealed the District Court’s decision to the Court of Appeals for the Third Supreme Judicial District of the state of Texas, which appeal is currently pending.  Oral arguments in the case were heard March 23, 2005.  SPS is awaiting the Court of Appeals decision.

 

On Oct. 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts alleged in the petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination at the PUCT of the legality of SPS providing electric service to the disputed customers.  The PUCT order of May 23, 2003, found that SPS was legally serving the disputed customers, thus collaterally determining the issue of liability contrary to LCEC’s position in the suit.  An adverse ruling on the appeal of May 23, 2003 PUCT order could result in a re-determination of the legality of SPS’ service to the disputed customers.

 

Manufactured Gas Plant Insurance Coverage Litigation (NSP-Wisconsin) In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire, and LaCrosse, Wis. In lieu of participating in discussions, on Oct. 28, 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Wisconsin court denied the insurers’ motion to stay the Wisconsin case pending resolution of the Minnesota action.  On Jan. 6, 2005, the Minnesota court issued an injunction prohibiting NSP-Wisconsin from prosecuting the Wisconsin action.  On Dec. 27, 2005, the Minnesota Court of Appeals upheld the issuance of the anti-suit injunction.  On January 26, 2006, NSP-Wisconsin submitted for filing its petition for review with the Minnesota Supreme Court.  On January 13, 2006, the Minnesota trial court extended its stay of the anti-suit injunction until February 28, 2006, or until the Minnesota Supreme Court denies NSP-Wisconsin’s petition for review, whichever occurs first.  If the petition for review is accepted

 

48



 

after February 28, 2006, the parties may seek leave to re-instate the stay.  Trial in the Minnesota action is scheduled to commence on November 6, 2006.  A status conference in the Wisconsin action is scheduled for February 23, 2006.  Trial in the Wisconsin action is scheduled to begin in January 2007.

 

On January 10, 2006, NSP-Wisconsin, entered into a confidential settlement agreement with St. Paul Mercury Insurance Company, St. Paul Fire and Marine Insurance Company and The Phoenix Insurance Company (“St. Paul Companies”), and the St. Paul Companies have been dismissed from the Minnesota and Wisconsin actions.   The settlement with the St. Paul Companies will not have a material effect on NSP-Wisconsin shareholders.

 

On Feb. 10, 2006, NSP-Wisconsin filed with the Minnesota court a renewed motion for dismissal under the doctrine of forum non conveniens and a motion for dissolution of the anti-suit injunction.  These motions were based upon the changed circumstances resulting from the dismissal of the St. Paul Companies.  The St. Paul Companies were the only Minnesota-based insurers and provided what the trial court viewed as a pivotal Minnesota connection supporting its issuance of the anti-suit injunction and denial of NSP-Wisconsin’s February 2004 motion to dismiss under the doctrine of forum non conveniens.  These motions are currently set for hearing on March 13, 2006.     

 

The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers. Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to ratepayers, therefore, these lawsuits should not have an impact on shareholders, and no accruals have been made.

 

Hill et al. vs. PSCo et al. - In October 2003, there were two wildfires in Colorado, one in Boulder County and the other in Douglas County.  There was no loss of life, but there was property damage associated with these fires. Parties have asserted that trees falling into Xcel Energy distribution lines may have caused one or both fires.  On Jan. 14, 2004, an action against PSCo relating to the fire in Boulder County was filed in Boulder County District Court. There are now 46 plaintiffs, including individuals and insurance companies, and three co-defendants, including PSCo.  The plaintiffs asserted damages in excess of $35 million.  In June 2005, PSCo reached a confidential settlement with all parties, as well as the United States Forest Service and the Denver Public Schools, settling claims in connection with the fire in Boulder County.  The financial impact of the settlement was not material to Xcel Energy.

 

SchlumbergerSema, Inc. vs. Xcel Energy Inc. (NSP-Minnesota) - Under a 1996 data services agreement, as amended, SchlumbergerSema, Inc. (SLB) provided automated meter reading, distribution automation and other data services to NSP-Minnesota. In September 2002, NSP-Minnesota issued written notice that SLB committed events of default under the agreement, including SLB’s nonpayment of approximately $7.4 million for distribution automation assets. In November 2002, SLB demanded arbitration and asserted various claims against NSP-Minnesota totaling approximately $24 million for alleged breach of an expansion contract and a meter purchasing contract. In the arbitration, NSP-Minnesota asserted counterclaims against SLB, including those related to SLB’s failure to meet performance criteria, improper billing, failure to pay for use of NSP-Minnesota owned property and failure to pay $7.4 million for NSP-Minnesota distribution automation assets, for total claims of approximately $41 million. NSP-Minnesota also sought a declaratory judgment from the arbitrators that would terminate SLB’s rights under the data services agreement. In August 2004, the U.S. Bankruptcy Court for the District of Delaware ruled that claims related to use of certain equipment are barred unless NSP-Minnesota can establish a basis for the claims in SLB’s conduct subsequent to the time of the assumption of this contract by SLB in May 2000.  In June 2005, the U.S. Bankruptcy Court ruled that NSP-Minnesota is barred from asserting any claim or defense against SLB that is based, in whole or in part, on any pre-May 2000 act or omission, including, but not limited to, any act or omission resulting in design or performance defects, by Cellnet Data Systems Inc., the party with which NSP-Minnesota originally contracted and from which SLB assumed the relevant agreements, which act or omission could have been a basis for NSP-Minnesota to assert a breach of contract against Cellnet Data Systems Inc.  On Oct. 31, 2005, the parties submitted this dispute to mediation, and reached a confidential settlement that did not have a material financial impact on Xcel Energy.

 

Additional Information

 

For more discussion of legal claims and environmental proceedings, see Note 14 to the Consolidated Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates and other regulatory matters, see Pending and Recently Concluded Regulatory Proceedings under Item 1, and Management’s Discussion and Analysis under Item 7, incorporated by reference.

 

Item 4 — Submission of Matters to a Vote of Security Holders

 

No issues were submitted for a vote during the fourth quarter of 2005.

 

49



 

PART II

 

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

 

Quarterly Stock Data

 

Xcel Energy’s common stock is listed on the New York Stock Exchange (NYSE), the Chicago Stock Exchange and the Pacific Stock Exchange. The trading symbol is XEL. The following are the reported high and low sales prices based on the NYSE Composite Transactions for the quarters of 2005 and 2004 and the dividends declared per share during those quarters.

 

 

2005

 

High

 

Low

 

Dividends

 

 

 

 

 

 

 

 

 

First Quarter

 

$

18.41

 

$

16.50

 

$

0.2075

 

Second Quarter

 

$

19.65

 

$

16.83

 

$

0.2150

 

Third Quarter

 

$

20.19

 

$

18.44

 

$

0.2150

 

Fourth Quarter

 

$

19.83

 

$

17.81

 

$

0.2150

 

 

2004

 

High

 

Low

 

Dividends

 

 

 

 

 

 

 

 

 

First Quarter

 

$

18.33

 

$

16.88

 

$

0.1875

 

Second Quarter

 

$

18.04

 

$

15.48

 

$

0.2075

 

Third Quarter

 

$

17.70

 

$

16.32

 

$

0.2075

 

Fourth Quarter

 

$

18.78

 

$

16.96

 

$

0.2075

 

 

Book value per share at Dec. 31, 2005, was $13.37. The number of common shareholders of record as of Dec. 31, 2005 was 115,000.

 

Xcel Energy’s Restated Articles of Incorporation provide for certain restrictions on the payment of cash dividends on common stock. At Dec. 31, 2005 and 2004, the payment of cash dividends on common stock was not restricted.  For further discussion of Xcel Energy’s dividend policy, see Liquidity and Capital Resources under Item 7.

 

See Item 12 for information concerning securities authorized for issuance under equity compensation plans.

 

Item 6 — Selected Financial Data

 

 

(Millions of Dollars, Except Share and Per-Share Data)

 

2005

 

2004

 

2003

 

2002

 

2001

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues (a)

 

$

9,625

 

$

8,216

 

$

7,731

 

$

6,893

 

$

8,527

 

Operating expenses (a)

 

$

8,533

 

$

7,140

 

$

6,607

 

$

5,717

 

$

7,272

 

Income from continuing operations (a)

 

$

499

 

$

522

 

$

523

 

$

549

 

$

596

 

Net income (loss)

 

$

513

 

$

356

 

$

622

 

$

(2,218

)

$

795

 

Earnings available for common stock

 

$

509

 

$

352

 

$

618

 

$

(2,222

)

$

791

 

Average number of common shares outstanding (000’s)

 

402,330

 

399,456

 

398,765

 

382,051

 

342,952

 

Average number of common and potentially dilutive shares outstanding (000’s) (e)

 

425,671

 

423,334

 

418,912

 

384,646

 

343,742

 

Earnings per share from continuing operations - basic (a)

 

$

1.23

 

$

1.30

 

$

1.30

 

$

1.43

 

$

1.73

 

Earnings per share-basic

 

$

1.26

 

$

0.88

 

$

1.55

 

$

(5.82

)

$

2.31

 

Earnings per share-diluted (e)

 

$

1.23

 

$

0.87

 

$

1.50

 

$

(5.77

)

$

2.30

 

Dividends declared per share

 

$

0.85

 

$

0.81

 

$

0.75

 

$

1.13

 

$

1.50

 

Total assets (c)

 

$

21,648

 

$

20,305

 

$

20,205

 

$

29,436

 

$

28,754

 

Long-term debt (d)

 

$

5,898

 

$

6,493

 

$

6,494

 

$

5,294

 

$

4,201

 

Book value per share

 

$

13.37

 

$

12.99

 

$

12.95

 

$

11.70

 

$

17.91

 

Return on average common equity

 

9.6

%

6.8

%

12.6

%

(41.0

)%

13.5

%

Ratio of earnings to fixed charges (b)

 

2.2

 

2.2

 

2.2

 

2.5

 

2.9

 

 

50



 


(a)   Operating revenues and expenses for 2001 through 2004 include reclassifications to conform to the 2005 presentation. These reclassifications relate to reporting electric and natural gas trading revenues and costs on a net basis, reporting fees collected from customers on behalf of governmental agencies net of the related payments made to the agencies and to presenting the results of discontinued operations separately. These reclassifications had no effect on net income.

(b)   Excludes undistributed equity income and includes allowance for funds used during construction.

(c)   Total assets for 2005, 2004, 2003 and 2002 reflect the classification of accrued future plant removal costs as a component of regulatory liabilities.  In 2001, accrued future plant removal costs are reflected as a component of accumulated depreciation. Accrued future removal costs were $896 million, $891 million, $852 million and $800 million in 2005, 2004, 2003 and 2002, respectively.

(d)  Long-term debt includes only debt of continuing operations.

(e)           The 2002 average number of common and potentially dilutive shares has been restated to include the effect of dilutive securities, which were excluded in 2002 due to Xcel Energy’s loss from continuing operations. Including these securities would have been antidilutive, or would have reduced the reported loss per share. In 2002, the loss from continuing operations that was caused by NRG made some securities “antidilutive” or would have reduced the reported loss per share. In 2003, NRG’s results were reclassified to discontinued operations.

 

51



 

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

 

BUSINESS SEGMENTS AND ORGANIZATIONAL OVERVIEW

 

Xcel Energy Inc. (Xcel Energy), a Minnesota corporation, is a public utility holding company. In 2005, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Co. (SPS). These utilities serve customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin.  Along with WestGas InterState Inc. (WGI), an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations. 

 

Xcel Energy’s nonregulated subsidiaries reported in continuing operations include Eloigne Co. (investments in rental housing projects that qualify for low-income housing tax reported credits).  

 

Discontinued utility operations include Viking Gas Transmission Co. (Viking), an interstate natural gas pipeline company that was sold in January 2003; Black Mountain Gas Co. (BMG), a regulated natural gas and propane distribution company that was sold in October 2003; and Cheyenne Light, Fuel and Power Co. (Cheyenne), a regulated electric and natural gas utility that was sold in January 2005.

 

During 2003, Planergy International, Inc. (Planergy) (energy management solutions) closed, with final dissolution completed in 2004.  Several nonregulated subsidiaries are presented as a component of discontinued operations.  They include Utility Engineering (UE), an engineering, design and construction management firm; Quixx Corp., a former subsidiary of UE that partners in cogeneration projects; Seren Innovations, Inc. (Seren), a broadband communications services company; NRG Energy, Inc. (NRG), an independent power producer; Xcel Energy International, Inc., an international independent power producer; and e prime inc. (e prime), a natural gas marketing and trading company. 

 

Discontinued operations classifications are the result of sales or plans to sell by management.  See Note 2 to the Consolidated Financial Statements for further discussion of discontinued operations.

 

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. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy 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; structures that affect the speed and degree to which competition enters the electric and natural gas markets; the higher risk associated with Xcel Energy’s nonregulated businesses compared with its regulated businesses; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission (SEC), including “Risk Factors” in Item 1A of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Exhibit 99.01 to Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005.

 

MANAGEMENT’S STRATEGIC PLAN

 

Xcel Energy’s strategy, which we call Building the Core, is to invest in our core utility businesses and earn the return authorized by our regulatory commissions.  We plan to invest approximately $7 billion over the next five years in our core operations to grow our business in response to an increase in customer demand.  We anticipate a need for additional energy supply in both Colorado and Minnesota during the next 15 years.  Additionally, we continue to focus on enhancing the reliability of our electrical system, which includes making significant investment in our transmission and distribution systems.

 

Over the past five years, we’ve divested 10 businesses or subsidiaries that were not closely linked to our core electric and natural gas businesses, realizing cash proceeds of nearly $440 million.  Today, we’re a vertically integrated utility and we intend to stay that way. 

 

52



 

Our strategy of Building the Core has three phases.  The first phase is obtaining legislative and regulatory support for our large investment initiatives prior to making the investment.  To avoid excessive risk for the company, it is critical to reduce regulatory uncertainty before making large capital investments.  We accomplished this for both the Metropoliton Emission Reduction Project (MERP) in Minnesota and the Comanche 3 coal plant in Colorado.  Transmission legislation has been passed in Minnesota, allowing that state’s regulatory commission to approve recovery for transmission investments without filing a general rate case.  In Texas, the legislature authorized annual recovery for transmission infrastructure improvements.  Both pieces of legislation will support necessary new investment in our transmission system.

 

The second phase is making those investments.  In a normal year, we spend approximately $1 billion on capital projects.  In addition to our base level of capital investment, we expect to spend approximately $1 billion on MERP and $1 billion on Comanche 3 through 2010.  As a result of these investments, as well as continued investments in our transmission and distribution system, to ensure continued reliability and to meet our customer growth requirements, we expect that our rate base, or the amount on which we earn a return, will grow annually by slightly more than 4 percent on average.  Finally, such investments will always be made with a clear focus on optimizing environmental protection, a significant priority for Xcel Energy.

 

The third phase is earning a fair return on our investments.  To ensure that we earn a fair return, our regulatory strategy is to receive regulatory approval for rate riders as well as general rate cases.  A rate rider is a mechanism that allows us to recover certain costs and returns on investments without the costs and delays of filing a rate case.  These riders allow for timely revenue recovery and are good mechanisms to recover the costs of large projects or other costs that vary over time.  As an example, a rider for MERP went into effect in January 2006, allowing us to earn a return on the project while the facility is being constructed.

 

We also are filing general rate cases to increase revenue recovery in most of the states in which we operate.  In 2005, we filed several rate cases as part of our regulatory strategy.  These rate cases, and others that we plan to file in 2006, are some of the building blocks of our earnings growth plan.  Following is the current status of these initiatives:

      We reached constructive decisions in the Colorado natural gas case and Wisconsin electric and natural gas cases, which will increase revenue in 2006 (see Factors Affecting Results of Continuing Operations for further discussion). 

      We are on track with the Minnesota electric case, where interim rates, subject to refund, went into effect in January 2006.  We expect a decision in the third quarter of this year. 

      Later in the year we plan to file electric cases in Colorado, Texas, New Mexico, and possibly North Dakota and South Dakota.  If we are successful, these cases should increase revenue and earnings in 2007.

 

Our regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on our utility investments.  We believe that our commissions will provide us with reasonable recovery, and it’s important to note that our financial plans include this assumption.  Recent constructive results, along with past rulings, are evidence of reasonable regulatory treatment and give us confidence that we are pursuing the right strategy.

 

With any strategic plan, there are goals and objectives. We feel the following financial objectives are both realistic and achievable:

      Annual earnings-per-share growth rate target of 5 percent to 7 percent from 2005-2009;

      Annual dividend increases of 2 percent to 4 percent; and

      Senior unsecured debt credit ratings in the BBB+ to A range.

 

Successful execution of our Building the Core strategic plan should allow us to achieve our financial objectives, which in turn should provide investors with an attractive total return on a low-risk investment. 

 

FINANCIAL REVIEW

 

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’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. All note references refer to the Notes to Consolidated Financial Statements.

 

Summary of Financial Results

 

The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of generally accepted accounting principles (GAAP). Continuing operations consist of the following:

 

      Regulated utility subsidiaries, operating in the electric and natural gas segments; and

      Several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

 

53



 

Discontinued operations consist of the following:

 

      Quixx Corp., which was classified as held for sale in the third quarter of 2005 based on a decision to divest this investment;

      Utility Engineering Corp., which was sold in April 2005;

      Seren, a portion of which was sold in November 2005 with the remainder sold in January 2006;

      Viking and BMG, which were sold in 2003;

      Cheyenne, which was sold in January 2005;

      NRG, which emerged from bankruptcy and was divested in late 2003; and

      Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.

 

Certain items in the statements of operations have been reclassified from prior-period presentation to conform to the 2005 presentation.  See Note 2 to the Consolidated Financial Statements for a further discussion of discontinued operations.

 

 

 

 

Contribution to earnings

 

(Millions of Dollars)

 

2005

 

2004

 

2003

 

GAAP income (loss) by segment

 

 

 

 

 

 

 

Regulated electric utility segment income — continuing operations

 

$

440.6

 

$

466.3

 

$

461.3

 

Regulated natural gas utility segment income — continuing operations

 

71.2

 

86.1

 

94.1

 

Other utility results (a)

 

27.6

 

6.1

 

6.0

 

Total utility segment income — continuing operations

 

539.4

 

558.5

 

561.4

 

Holding company costs and other results (a)

 

(40.3

)

(36.2

)

(38.6

)

Total income — continuing operations

 

499.1

 

522.3

 

522.8

 

Regulated utility income (loss) — discontinued operations

 

0.2

 

(9.0

)

26.8

 

NRG loss — discontinued operations

 

(1.1

)

 

(251.4

)

Other nonregulated income (loss) — discontinued operations (b)

 

14.8

 

(157.3

)

324.2

 

Total income (loss) — discontinued operations

 

13.9

 

(166.3

)

99.6

 

Total GAAP net income

 

$

513.0

 

$

356.0

 

$

622.4

 

 

 

 

Contribution to earnings per share

 

 

 

2005

 

2004

 

2003

 

GAAP earnings (loss) per share contribution by segment

 

 

 

 

 

 

 

Regulated electric utility segment — continuing operations

 

$

1.04

 

$

1.10

 

$

1.10

 

Regulated natural gas utility segment — continuing operations

 

0.17

 

0.20

 

0.22

 

Other utility results (a)

 

0.06

 

0.02

 

0.01

 

Total utility segment earnings per share — continuing operations

 

1.27

 

1.32

 

1.33

 

Holding company costs and other results (a)

 

(0.07

)

(0.06

)

(0.07

)

Total earnings per share — continuing operations

 

1.20

 

1.26

 

1.26

 

Regulated utility earnings (loss) — discontinued operations

 

 

(0.02

)

0.06

 

NRG loss — discontinued operations

 

 

 

(0.60

)

Other nonregulated earnings (loss) — discontinued operations (b)

 

0.03

 

(0.37

)

0.78

 

Total earnings (loss) per share — discontinued operations

 

0.03

 

(0.39

)

0.24

 

Total GAAP earnings per share — diluted

 

$

1.23

 

$

0.87

 

$

1.50

 

 


(a) Not a reportable segment. Included in All Other segment results in Note 17 to the Consolidated Financial Statements.

 

(b) Includes tax benefit related to NRG. See Note 2 to the Consolidated Financial Statements.

 

Earnings from continuing operations for 2005 were lower than in 2004.  The 2005 results had higher operating margins, which were offset by higher operating and maintenance expenses, including scheduled nuclear plant outages in 2005, higher employee benefit costs, higher uncollectible receivable expense and higher depreciation expense.  In addition, tax expense recorded in 2005 was higher than 2004, primarily attributable to tax benefits recorded in 2004 related to the successful resolution of various income tax audit issues.

 

While earnings from continuing operations for 2004 were flat compared with 2003, 2004 results were favorably impacted by electric sales growth, short-term wholesale markets and lower depreciation, offset by the negative impact of unfavorable weather, legal settlement costs and the impact of certain regulatory accruals, compared with the same period in 2003.

 

Income from discontinued operations in 2005 includes the positive impact of a $17 million tax benefit recorded to reflect the final resolution of Xcel Energy’s divested interest in NRG.  This was partially offset by Seren’s operating losses during 2005.

 

54



 

The loss from discontinued operations in 2004 is largely due to an after-tax impairment charge of $143 million, or 34 cents per share, related to Seren. In addition, the loss from discontinued operations in 2004 is attributable in part to an after-tax loss of $13 million, or 3 cents per share, associated with the disposition of Cheyenne.

 

The earnings in 2003 from discontinued operations are primarily due to an adjustment to previously estimated tax benefits related to Xcel Energy’s write-off of its investment in NRG. Results from discontinued operations are discussed in the Discontinued Operations section later.

 

Weather — Xcel Energy’s earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and natural gas sales, but also can increase expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce expenses.  The impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity the average customer historically has used per degree of temperature.

 

The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from historical averages:

 

    Weather in 2005 increased earnings by an estimated 3 cents per share;

    Weather in 2004 decreased earnings by an estimated 8 cents per share; and

    Weather in 2003 was close to normal and had minimal impact on earnings per share.

 

Statement of Operations Analysis — Continuing Operations

 

The following discussion summarizes the items that affected the individual revenue and expense items reported in the Consolidated Statements of Operations.

 

Electric Utility, Short-Term Wholesale and Commodity Trading Margins

 

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

 

Xcel Energy has two distinct forms of wholesale sales: short-term wholesale and commodity trading.  Short-term wholesale refers to energy-related purchase and sales activity, and the use of certain financial instruments associated with the fuel required for, and energy produced from, Xcel Energy’s generation assets or the energy and capacity purchased to serve native load.  Commodity trading is not associated with Xcel Energy’s generation assets or the energy and capacity purchased to serve native load.  Short-term wholesale and commodity trading activities are considered part of the electric utility segment.

 

Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing, if applicable.  Commodity trading revenues are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Operations. Commodity trading costs include purchased power, transmission, broker fees and other related costs. 

 

55



 

 

The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities:

 

 

(Millions of Dollars)

 

Base
Electric
Utility

 

Short-Term
Wholesale

 

Commodity
Trading

 

Consolidated
Totals

 

 

 

 

 

 

 

 

 

 

 

2005

 

 

 

 

 

 

 

 

 

Electric utility revenue (excluding commodity trading)

 

$

7,038

 

$

196

 

$

 

$

7,234

 

Fuel and purchased power

 

(3,802

)

(120

)

 

(3,922

)

Commodity trading revenue

 

 

 

730

 

730

 

Commodity trading costs

 

 

 

(720

)

(720

)

Gross margin before operating expenses

 

$

3,236

 

$

76

 

$

10

 

$

3,322

 

Margin as a percentage of revenue

 

46.0

%

38.8

%

1.4

%

41.7

%

 

 

 

 

 

 

 

 

 

 

2004

 

 

 

 

 

 

 

 

 

Electric utility revenue (excluding commodity trading)

 

$

5,989

 

$

220

 

$

 

$

6,209

 

Fuel and purchased power

 

(2,916

)

(125

)

 

(3,041

)

Commodity trading revenue

 

 

 

610

 

610

 

Commodity trading costs

 

 

 

(594

)

(594

)

Gross margin before operating expenses

 

$

3,073

 

$

95

 

$

16

 

$

3,184

 

Margin as a percentage of revenue

 

51.3

%

43.2

%

2.6

%

46.7

%

 

 

 

 

 

 

 

 

 

 

2003

 

 

 

 

 

 

 

 

 

Electric utility revenue (excluding commodity trading)

 

$

5,724

 

$

179

 

$

 

$

5,903

 

Fuel and purchased power

 

(2,588

)

(118

)

 

(2,706

)

Commodity trading revenue

 

 

 

333

 

333

 

Commodity trading costs

 

 

 

(316

)

(316

)

Gross margin before operating expenses

 

$

3,136

 

$

61

 

$

17

 

$

3,214

 

Margin as a percentage of revenue

 

54.8

%

34.1

%

5.1

%

51.5

%

 

The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the years ended Dec. 31:

 

Base Electric Utility Revenue

 

(Millions of Dollars)

 

2005 vs. 2004

 

2004 vs. 2003

 

Sales growth (excluding weather impact)

 

$

57

 

$

73

 

Estimated impact of weather

 

91

 

(74

)

Fuel and purchased power cost recovery

 

706

 

230

 

Firm wholesale

 

67

 

62

 

Capacity sales

 

15

 

(2

)

Quality of service obligations

 

7

 

(12

)

Conservation and non-fuel riders

 

16

 

(5

)

Texas fuel reconciliation settlement

 

21

 

(25

)

Other

 

69

 

18

 

Total base electric utility revenue increase

 

$

1,049

 

$

265

 

 

2005 Comparison with 2004 — Base electric revenues increased due to higher fuel and purchased power costs, which are largely recovered from customers; weather-normalized retail sales growth of approximately 1.4 percent; higher sales attributable to warmer than normal summer temperatures in 2005; higher revenues from firm wholesale customers and lower regulatory accruals related to the Texas fuel reconciliation settlement.

 

56



 

2004 Comparison with 2003 — Base electric utility revenues increased due to higher fuel and purchased power costs, which are largely recovered from customers; weather-normalized retail sales growth of approximately 1.8 percent; and higher revenues from firm wholesale customers.  Partially offsetting the higher revenues was the impact of significantly cooler summer temperatures in 2004, compared with the summer of 2003, as well as estimated customer refunds related to quality-of-service obligations in Colorado and the estimated Texas fuel reconciliation settlement.

 

Base Electric Utility Margin

 

 

(Millions of Dollars)

 

2005 vs. 2004

 

2004 vs. 2003

 

Estimated impact of weather on sales

 

$

75

 

$

(56

)

Sales growth (excluding weather impact)

 

42

 

55

 

Conservation and non-fuel revenue

 

16

 

(6

)

Texas fuel reconciliation settlement

 

21

 

(25

)

Quality-of-service obligations

 

7

 

(12

)

Under-recovery of fuel costs (NSP-Wisconsin)

 

(15

)

(10

)

Under-recovery and timing of recovery of fuel costs (other jurisdictions)

 

(14

)

(20

)

Firm wholesale

 

23

 

27

 

Pricing and other

 

8

 

(16

)

Total base electric utility margin increase (decrease)

 

$

163

 

$

(63

)

 

2005 Comparison to 2004 — Base electric utility margin increased due to the impact of weather, weather-normalized sales growth, higher firm wholesale margins, higher conservation and non-fuel rider revenues and lower accruals related to the fuel reconciliation proceedings in Texas, partially offset by higher amortization expense and lower regulatory accruals associated with potential customer refunds related to service-quality obligations in Colorado.  These increases were partially offset by higher fuel and purchased energy costs not recovered through direct pass-through recovery mechanisms.

 

2004 Comparison to 2003 — Base electric utility margin decreased due to the impact of weather, higher fuel and purchased energy costs not recovered through direct pass-through recovery mechanisms, and regulatory accruals associated with potential customer refunds related to service-quality obligations in Colorado and fuel-reconciliation proceedings in Texas.   These decreases were partially offset by weather-normalized sales growth.

 

Short-Term Wholesale and Commodity Trading Margin

 

2005 Comparison to 2004 — Short-term wholesale and commodity trading margins decreased $25 million for 2005 compared with 2004.  The higher 2004 results reflect the impact of more favorable market conditions and higher levels of surplus generation available to sell.  In addition, a preexisting contract contributed $17 million of margin in the first quarter of 2004 and expired at that time.

 

2004 Comparison to 2003 — Short-term wholesale and commodity trading margins increased approximately $33 million in 2004 compared with 2003.  The increase reflects a number of market factors, including higher market prices and additional resources available for sale and the pre-existing contract described above.

 

Natural Gas Utility Margins

 

The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost-recovery mechanisms for sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin.  See further discussion under Factors Affecting Results of Continuing Operations.

 

 

(Millions of Dollars)

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Natural gas utility revenue

 

$

2,307

 

$

1,916

 

$

1,678

 

Cost of natural gas purchased and transported

 

(1,823

)

(1,446

)

(1,191

)

Natural gas utility margin

 

$

484

 

$

470

 

$

487

 

 

57



 

 

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

 

Natural Gas Revenue

 

 

(Millions of Dollars)

 

2005 vs. 2004

 

2004 vs. 2003

 

Sales growth (excluding weather impact)

 

$

 

$

(3

)

Purchased natural gas adjustment clause recovery

 

397

 

257

 

Rate changes — Colorado, Minnesota and North Dakota

 

6

 

(15

)

Estimated impact of weather

 

(5

)

(10

)

Transportation and other

 

(7

)

9

 

Total natural gas revenue increase

 

$

391

 

$

238

 

 

 

2005 Comparison to 2004 — Natural gas revenue increased primarily due to higher natural gas costs in 2005, which are recovered from customers.  Retail natural gas weather-normalized sales were flat when compared to 2004, largely due to the rising cost of natural gas and its impact on customer usage.

 

2004 Comparison to 2003 — Natural gas revenue increased primarily due to higher natural gas costs in 2004, which are recovered from customers.  Retail natural gas weather-normalized sales declined in 2004, largely due to the rising cost of natural gas and its impact on customer usage.

 

Natural Gas Margin

 

(Millions of Dollars)

 

2005 vs. 2004

 

2004 vs. 2003

 

Sales growth (excluding weather impact)

 

$

1

 

$

 

Estimated impact of weather on firm sales

 

(2

)

(5

)

Rate changes — Colorado, Minnesota and North Dakota

 

6

 

(15

)

Transportation

 

6

 

1

 

Other

 

3

 

2

 

Total natural gas margin increase (decrease)

 

$

14

 

$

(17

)

 

2005 Comparison to 2004 — Natural gas margin increased due to rate changes in Minnesota and North Dakota, and higher transportation margins, partially offset by the impact of warmer winter temperatures in 2005 compared with 2004.

 

2004 Comparison to 2003 — Natural gas margin decreased due to a full year of a base rate decrease in Colorado, which was effective July 1, 2003, and the impact of warmer winter temperatures in 2004 compared with 2003. 

 

Nonregulated Operating Margins

 

The following table details the changes in nonregulated revenue and margin included in continuing operations:

 

(Millions of Dollars)

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Nonregulated and other revenue

 

$

74

 

$

75

 

$

134

 

Nonregulated cost of goods sold

 

(25

)

(29

)

(81

)

Nonregulated margin

 

$

49

 

$

46

 

$

53

 

 

2004 Comparison to 2003 — Nonregulated revenue decreased in 2004, due primarily to the discontinued consolidation of an investment in an independent power-producing entity that was no longer majority owned.

 

Non-Fuel Operating Expenses and Other Items

 

Other Utility Operating and Maintenance Expenses — Other operating and maintenance expenses for 2005 increased by approximately $87 million, or 5.5 percent, compared with 2004.  An outage at the Monticello nuclear plant and higher outage costs at Prairie Island in 2005 increased costs by approximately $26 million.  Employee benefit costs were higher in 2005, primarily due to increased pension benefits and long-term disability costs.  Also contributing to the increase was higher uncollectible receivable costs, attributable in part, to modifications to the bankruptcy laws, higher fuel prices and certain changes in the credit and collection process.

 

58



 

Other operating and maintenance expenses for 2004 increased by approximately $21 million, or 1.4 percent, compared with 2003.  Of the increase, $12 million was incurred to assist with the storm damage repair in Florida and was offset by increased revenue.  The remaining increase of $9 million is primarily due to higher electric service reliability costs, higher information technology costs, higher plant-related costs, higher costs related to a customer billing system conversion and increased costs primarily related to compliance with the Sarbanes-Oxley Act of 2002.  The higher costs were partially offset by lower employee benefit and compensation costs and lower nuclear plant outage costs.

 

(Millions of Dollars)

 

2005 vs. 2004

 

2004 vs. 2003

 

Higher (lower) employee benefit costs

 

$

31

 

$

(12

)

Higher (lower) nuclear plant outage costs

 

26

 

(13

)

Higher uncollectible receivable costs

 

19

 

2

 

Higher donations to energy assistance programs

 

4

 

1

 

Higher mutual aid assistance costs

 

1

 

12

 

Higher electric service reliability costs

 

9

 

9

 

Higher (lower) information technology costs

 

(6

)

8

 

Higher (lower) plant-related costs

 

(7

)

4

 

Higher costs related to customer billing system conversion

 

4

 

4

 

Higher costs to comply with Sarbanes-Oxley Act of 2002

 

 

4

 

Other

 

6

 

2

 

Total operating and maintenance expense increase

 

$

87

 

$

21

 

 

Other Nonregulated Operating and Maintenance Expenses — Other nonregulated operating and maintenance expenses decreased $16 million, or 35.4 percent, in 2005 compared with 2004, primarily due to the accrual of $18 million in 2004 for a settlement agreement related to shareholder lawsuits.

 

Other nonregulated operating and maintenance expenses decreased $9 million, or 17.5 percent, in 2004 compared with 2003.  This decrease resulted from the dissolution of Planergy International and the discontinued consolidation of an investment in an independent power producing entity that was no longer majority owned after the divestiture of NRG.

 

Depreciation and Amortization — Depreciation and amortization expense for 2005 increased by approximately $61 million, or 8.7 percent, compared with 2004.  The changes were primarily due to the installation of new steam generators at Unit 1 of the Prairie Island nuclear plant and software system additions, both of which have relatively short depreciable lives compared with other capital additions.  The Prairie Island steam generators are being depreciated over the remaining life of the plant operating license, which expires in 2013.  In addition, the Minnesota Renewable Development Fund and renewable cost-recovery amortization, which is recovered in revenue as a non-fuel rider and does not have an impact on net income, increased over 2004.  The increase was partially offset by the changes in useful lives and net salvage rates approved by Minnesota regulators in August 2005. 

 

Depreciation and amortization expense for 2004 decreased by $21 million, or 2.9 percent, compared with 2003.  The reduction is largely due to several regulatory decisions.  In 2004, as a result of a Minnesota Public Utilities Commission (MPUC) order, NSP-Minnesota modified its decommissioning expense recognition, which served to reduce decommissioning accruals by approximately $18 million in 2004 compared with 2003.

 

In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility plant at PSCo as a part of the general Colorado rate case, reducing annual depreciation expense by $20 million.  PSCo experienced the full impact of the annual reduction in 2004, resulting in a decrease in depreciation expense of $10 million for 2004 compared with 2003.  These decreases were partially offset by plant additions.

 

Interest and Other Income (Expense) Net — Interest and other income (expense) net decreased $8 million in 2005 compared with 2004.  The decrease is due to interest income related to the finalization of prior-period IRS audits of $10.5 million in 2004, partially offset by a $2.2 million gain on the sale of water rights in 2005.

 

Interest and other income, net of nonoperating expenses increased $15 million in 2004 compared with 2003.  The increase is due mostly to interest income related to the finalization of prior-period IRS audits of $10.5 million. 

 

Interest and Financing Costs — The 2005 interest charges and financing costs increased approximately $8 million, or 1.9 percent when compared with 2004, primarily due to increased short term borrowing levels.

 

The 2004 interest charges and financing costs decreased approximately $17 million, or 3.7 percent when compared with 2003.  The decrease for the year reflects savings from refinancing higher coupon debt during 2003 and lower credit line fees, partially offset by interest expense related to prior-period IRS audits.

 

59



 

Income Tax Expense — The effective income tax rate for continuing operations was 25.8 percent for 2005, compared with 23.7 percent in 2004.  Income taxes recorded in 2005 reflect tax benefits of $10.0 million, primarily from increased research credits and a net operating loss carry back.  Excluding the tax benefits, the effective rate for 2005 would have been 27.3 percent.

 

In 2004, income tax benefits of $37.1 million were recorded, which included $22.3 million related to the successful resolution of various audit issues and other adjustments to current and deferred taxes.  The effective income tax rate for continuing operations was 23.7 percent for 2004, compared with 24.6 percent for the same period in 2003.  Excluding the tax benefits, the effective rate for 2004 would have been 29.1 percent. 

 

See Note 8 to the Consolidated Financial Statements.

 

Holding Company and Other Results

 

The following tables summarize the net income and earnings-per-share contributions of the continuing operations of Xcel Energy’s nonregulated businesses and holding company results:

 

 

(Millions of Dollars)

 

Contribution to Xcel Energy’s
earnings

 

 

 

2005

 

2004

 

2003

 

Eloigne Company

 

$

6.2

 

$

8.5

 

$

7.7

 

Financing costs — holding company

 

(52.7

)

(44.7

)

(44.1

)

Holding company and other results

 

6.2

 

 

(2.2

)

Total nonregulated/holding company loss — continuing operations

 

$

(40.3

)

$

(36.2

)

$

(38.6

)

 

 

 

Contribution to Xcel Energy’s
earnings per share

 

 

 

2005

 

2004

 

2003

 

Eloigne Company

 

$

0.01

 

$

0.02

 

$

0.02

 

Financing costs and preferred dividends — holding company

 

(0.09

)

(0.08

)

(0.09

)

Holding company and other results

 

0.01

 

 

 

Total nonregulated/holding company loss per share — continuing operations

 

$

(0.07

)

$

(0.06

)

$

(0.07

)

 

Financing Costs and Preferred Dividends — Nonregulated results include interest expense and the earnings-per-share impact of preferred dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual subsidiaries.

 

The earnings-per-share impact of financing costs and preferred dividends for 2005, 2004 and 2003 included above reflects dilutive securities, as discussed further in Note 9 to the Consolidated Financial Statements. The impact of the dilutive securities, if converted, is a reduction of interest expense resulting in an increase in net income of approximately $14 million, or 3 cents per share, in 2005; $15 million, or 4 cents per share, in 2004; and $11 million, or 3 cents per share, in 2003.

 

60



Statement of Operations Analysis — Discontinued Operations (Net of Tax)

 

A summary of the various components of discontinued operations is as follows for the years ended Dec. 31:

 

 

 

2005

 

2004

 

2003

 

 

 

 

 

 

 

 

 

Income (loss) in millions

 

 

 

 

 

 

 

Viking Gas Transmission Co.

 

$

 

$

1.3

 

$

21.9

 

Black Mountain Gas

 

 

 

2.4

 

Cheyenne Light, Fuel and Power Co.

 

0.2

 

(10.3

)

2.5

 

Regulated utility segments — income (loss)

 

0.2

 

(9.0

)

26.8

 

 

 

 

 

 

 

 

 

NRG segment — loss

 

(1.1

)

 

(251.4

)

 

 

 

 

 

 

 

 

NRG-related tax benefits (expense)

 

17.2

 

(12.8

)

404.4

 

Xcel Energy International

 

0.1

 

7.3

 

(45.5

)

e prime

 

(0.1

)

(1.8

)

(17.8

)

Seren

 

1.8

 

(156.6

)

(18.3

)

Utility Engineering, Corp. / Quixx Corp.

 

(4.4

)

4.7

 

3.0

 

Other

 

0.2

 

1.9

 

(1.6

)

Nonregulated/other — income (loss)

 

14.8

 

(157.3

)

324.2

 

Total income (loss) from discontinued operations

 

$

13.9

 

$

(166.3

)

$

99.6

 

 

 

 

 

 

 

 

 

Income (loss) per share

 

 

 

 

 

 

 

Viking Gas Transmission Co.

 

$

 

$

 

$

0.05

 

Black Mountain Gas

 

 

 

0.01

 

Cheyenne Light, Fuel and Power Co.

 

 

(0.02

)

 

Regulated utility segments — income per share

 

 

(0.02

)

0.06

 

 

 

 

 

 

 

 

 

NRG segment — loss per share

 

 

 

(0.60

)

 

 

 

 

 

 

 

 

NRG-related tax benefits (expense)

 

0.04

 

(0.03

)

0.96

 

Xcel Energy International

 

 

0.02

 

(0.11

)

e prime

 

 

 

(0.04

)

Seren

 

 

(0.37

)

(0.04

)

Utility Engineering, Corp. / Quixx Corp.

 

(0.01

)

0.01

 

0.01

 

Other

 

 

 

 

Nonregulated/other — income (loss) per share

 

0.03

 

(0.37

)

0.78

 

Total income (loss) per share from discontinued operations

 

$

0.03

 

$

(0.39

)

$

0.24

 

 

Regulated Utility Results — Discontinued Operations

 

In January 2004, Xcel Energy agreed to sell Cheyenne.  Consequently, Xcel Energy reported Cheyenne results as a component of discontinued operations for all periods presented.  The sale was completed in January 2005 and resulted in an after-tax loss of approximately $13 million, or 3 cents per share, which was accrued in December 2004.

 

During 2003, Xcel Energy sold Viking and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded, primarily related to the sale of Viking.  Xcel Energy recorded minimal income related to Viking in 2003, due to its sale in January of that year.

 

NRG Results — Discontinued Operations

 

Xcel Energy’s share of NRG results for 2003 is shown as a component of discontinued operations due to NRG’s emergence from bankruptcy in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG.  Xcel Energy financial statements do not contain any results of NRG operations in 2005 and 2004.

 

61



 

NRG’s results included in Xcel Energy’s earnings for 2003 were as follows:

 

(Millions of Dollars)

 

Six months ended
June 30, 2003

 

Total NRG loss

 

$

(621

)

Losses not recorded by Xcel Energy under the equity method*

 

370

 

Equity in losses of NRG included in Xcel Energy results for 2003

 

$

(251

)

 


*            These represent NRG losses incurred in the first and second quarters of 2003 that were in excess of the amounts recordable by Xcel Energy under the equity method of accounting limitations.

 

As of the bankruptcy filing date (May 14, 2003), Xcel Energy had recognized $263 million of NRG’s impairments and related charges as these charges were recorded by NRG prior to May 14, 2003. Consequently, Xcel Energy recorded its equity in NRG results in excess of its financial commitment to NRG under the settlement agreement reached in March 2003 among Xcel Energy, NRG and NRG’s creditors. These excess losses were reversed upon NRG’s emergence from bankruptcy in December 2003.

 

Other Nonregulated Results — Discontinued Operations

 

In April 2005, Zachry Group, Inc. acquired all of the outstanding shares of UE, a nonregulated subsidiary.  In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration projects that was not included in the sale of UE to Zachry.  As a result, Xcel Energy is reporting UE and Quixx as components of discontinued operations for all periods presented.

 

In September 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren.  As a result of the decision, Seren is accounted for as discontinued operations.  In November 2005, Xcel Energy sold Seren’s California assets to WaveDivision Holdings, LLC.  In January 2006, Xcel Energy sold Seren’s Minnesota assets to Charter Communications.

 

During 2003, Xcel Energy’s board of directors approved management’s plan to exit businesses conducted by e prime and Xcel Energy International.  e prime ceased conducting business in 2004.  Also during 2004, Xcel Energy completed the sales of the Argentina subsidiaries of Xcel Energy International.

 

2005 Nonregulated Results Compared with 2004 — Results of discontinued nonregulated operations in 2005 include the impact of a $5 million reduction to the original asset impairment for Seren and the positive impact of a $17 million tax benefit recorded to reflect the final resolution of Xcel Energy’s divested interest in NRG.  In 2004, the NRG tax basis study was updated and previously recognized tax benefits were reduced by $13 million.

 

2004 Nonregulated Results Compared with 2003 — Results of discontinued nonregulated operations in 2004 include the impact of the sales of the Argentina subsidiaries of Xcel Energy International.  The sales were completed in three transactions, with a total sales price of approximately $31 million.  In addition to the sales price, Xcel Energy also received approximately $21 million at the closing of one transaction as redemption of its capital investment.  The sales resulted in a gain of approximately $8 million, including approximately $7 million of income tax benefits realizable upon the sale of the Xcel Energy International assets.

 

In addition, 2004 results from discontinued operations include the impact of an after-tax impairment charge for Seren, of $143 million, or 34 cents per share.  The impairment charge was recorded based on operating results, market conditions and preliminary feedback from prospective buyers.

 

Tax Benefits Related to Investment in NRG — Xcel Energy has recognized tax benefits related to the divestiture of NRG.  Since these tax benefits are related to Xcel Energy’s investment in discontinued NRG operations, they are reported as discontinued operations.

 

During 2002, Xcel Energy recognized an initial estimate of the expected tax benefits of $706 million.  Based on the results of a 2003 preliminary tax basis study of NRG, Xcel Energy recorded $404 million of additional tax benefits in 2003.  In 2004, the NRG basis study was updated and previously recognized tax benefits were reduced by $13 million.  In 2005, a $17 million tax benefit was recorded to reflect the final federal income tax resolution of Xcel Energy’s divested interest in NRG.

 

62



 

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. In 2005, 2004 and 2003, Xcel Energy used $24 million, $345 million, and $116 million, respectively, of these tax benefits, and expects to use $180 million in 2006. The remainder of the tax benefit carry forward is expected to be used over subsequent years.

 

Factors Affecting Results of Continuing Operations

 

Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions and affect Xcel Energy’s ability to recover its costs from customers. The historical and future trends of Xcel Energy’s operating results have been, and are expected to be, affected by a number of factors, including the following:

 

General Economic Conditions

 

Economic conditions may have a material impact on Xcel Energy’s operating results. The United States economy continues to grow as measured by projected growth in the gross domestic product. Management cannot predict the impact of a future economic slowdown, fluctuating energy prices, terrorist activity, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its results of operations, future growth or ability to raise capital resulting from a general slowdown in future economic growth or a significant increase in interest rates.

 

Sales Growth

 

In addition to the impact of weather, customer sales levels in Xcel Energy’s utility businesses can vary with economic conditions, energy prices, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was 1.4 percent in 2005 compared with 2004, and 1.8 percent in 2004 compared with 2003. Weather-normalized sales growth for firm natural gas utility customers was approximately 0.2 percent in 2005 compared with 2004, and (1.9) percent in 2004 compared with 2003. Projections indicate that weather-normalized sales growth in 2006 compared with 2005 will range between 1.3 percent and 1.7 percent for retail electric utility customers and 0.0 percent to 1.0 percent for firm natural gas utility customers.

 

Fuel Supply and Costs

 

Coal Deliverability- Xcel Energy’s operating utilities have varying dependence on coal-fired generation.  At the utilities, coal-fired generation comprises between 60 percent and 85 percent of the total annual generation.  Approximately 70 percent of the annual coal requirements are supplied from the Powder River Basin in Wyoming.  Delivery of coal from the Powder River Basin has been disrupted by train derailments and other operational problems purportedly caused by deteriorated rail track beds of approximately 140 miles in length in Wyoming. The BNSF Railway Co. (BNSF) and the Union Pacific Railroad (UPRR) jointly own the rail line.  The BNSF operates and maintains the rail line.

 

The coal delivery issues began in the first half of 2005.  Based on discussions with the railroads, Xcel Energy expects that disrupted coal deliveries will continue at least through the first part of 2006.  Xcel Energy has taken a number of steps to mitigate the impact of the reduced coal deliveries.  These steps include modifying the dispatch of certain generation facilities to conserve coal inventories. This modified dispatch was in place during the second half of 2005 and has continued in 2006 to date.  In response to this reduced coal dispatch, Xcel Energy has increased purchases from third parties and has increased the use of natural gas for electric generation.  In addition, Xcel Energy negotiated for the acquisition of additional, higher capacity rail cars and is working to upgrade certain coal –handling facilities.  Delivery of the new cars began in January 2006 and will continue over the course of the year.  The upgrades to the coal handling facilities are expected to be completed in the first half of 2006.

 

Despite these efforts, coal inventories have declined to below target levels. While Xcel Energy has secured, under contract, approximately 99 percent of anticipated 2006 coal requirements, it cannot predict the likelihood of receiving the required coal.  While Xcel Energy is planning to rebuild inventories during the year, there is no guarantee that it will be able to do so.  The ultimate impact of coal availability cannot be fully assessed at this time, but could impact future financial results.

 

The cost of purchased power and natural gas for electric generation is higher than for coal-fired electric generation.  The use of these sources to replace coal-fired electric generation increased the price of electricity for retail and wholesale customers.

 

63



 

Xcel Energy’s utility subsidiaries have discussed this situation with their respective state regulatory commissions.

 

In Colorado, PSCo is subject to a retail electric adjustment clause that recovers fuel, purchased energy and resource costs.  The Electric Commodity Adjustment (ECA) is an incentive adjustment mechanism that compares actual fuel and purchased energy expenses in a calendar year to a benchmark formula.  The benchmark formula increases with natural gas prices, but not necessarily with increased volumes of natural gas usage due to coal supply disruption.  Therefore, any disruption in coal supply could adversely affect fuel cost recovery.  For 2005, PSCo recorded an incentive accrual of $8.5 million.  The ECA provides for an $11.25 million cap on any cost sharing over or under the allowed ECA formula rate.  Any cost in excess of the $11.25 million cap is completely recovered from customers, while any savings in excess of the $11.25 million cap is completely refunded to customers.  Subject to the terms of the ECA, PSCo anticipates it would recover any increased fuel and purchased energy costs greater than the cap from its customers.

 

Natural gas prices in 2005 were higher than projected when the ECA tariff rates were set in January 2005.  On Oct. 5, 2005, PSCo filed an application to adjust the ECA rate for November and December 2005 to reduce the ECA deferred balance and to update its projection of natural gas prices.  This application was granted, which resulted in an increase to 2005 electric revenue of approximately $70 million, including unbilled revenues.  As of Dec. 31, 2005, PSCo was carrying a deferred ECA balance, including unbilled revenue, of approximately $15 million.

 

In Texas, fuel and purchased energy costs are recovered through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates.  If SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action by the Public Utility Commission of Texas (PUCT).  The regulations require surcharging of under-recovered amounts, including interest, when they exceed 4 percent of SPS’ annual fuel and purchased energy costs, as allowed by the PUCT, if the condition is expected to continue.  On Dec. 21, 2005 SPS reached a settlement with various parties that set the fuel surcharge request at $76.9 million, to be recovered over a 15-month period.  The PUCT approved this settlement on Feb. 9, 2006, and the surcharge went into effect Feb. 13, 2006.

 

In New Mexico, increases and decreases in fuel and purchased energy costs, including deferred amounts, are recovered through a monthly fuel and purchased power clause with a two-month lag.  Wholesale customers, under the Federal Energy Regulatory Commission (FERC) jurisdiction also pay a monthly fuel cost adjustment calculated on actual fuel and purchased power costs in accordance with the FERC’s fuel clause regulations.

 

While SPS believes that it should be allowed to recover these higher costs, the ultimate success of recovery could significantly impact the future of SPS and possibly Xcel Energy.

 

NSP-Minnesota’s retail electric rate schedules in the Minnesota, North Dakota and South Dakota jurisdictions include a fuel clause adjustment (FCA) to billings and revenues 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 individually approved by the regulators in each jurisdiction.  The FCA mechanisms allow NSP-Minnesota to bill customers for the cost of fuel and fuel-related items used to generate electricity at its plants and energy purchased from other suppliers.  In general, capacity costs are not recovered through the FCA.  NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.  NSP-Minnesota anticipates it will recover increased costs resulting from its mitigation plan through the FCA.

 

In Wisconsin, NSP-Wisconsin does not have an automatic electric fuel clause adjustment for Wisconsin retail customers.  NSP-Wisconsin may seek deferred accounting treatment and future rate recovery of increased costs due to an “emergency” event, if that event causes fuel and purchased power costs to exceed the amount included in rates on an annual basis by more than 2 percent.  Coal deliverability has not resulted in an emergency event to date.

 

Natural Gas Costs - A variety of market factors have contributed to significantly higher natural gas prices.  The direct impact of these higher costs is generally mitigated for Xcel Energy through recovery of such costs from customers through various fuel cost-recovery mechanisms.  However, higher fuel costs could significantly impact the results of operations, if requests for recovery are unsuccessful.  In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on Xcel Energy’s results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases are expected to have an impact on the cash flows of Xcel Energy.  Xcel Energy is unable to predict the future natural gas prices or the ultimate impact of such prices on its results of operations or cash flows.

 

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Pension Plan Costs and Assumptions

 

Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return level that pension investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present value obligation for financial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. Note 10 to the Consolidated Financial Statements discusses the rate of return and discount rate used in the calculation of pension costs and obligations in the accompanying financial statements.

 

Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower-than-expected investment returns experienced in prior years and decreases in interest rates used to discount benefit obligations. While investment returns exceeded the assumed level of 8.75 percent in 2005, 9.0 percent in 2004 and 9.25 percent in 2003, investment returns in 2002 and 2001 were below the assumed level of 9.5 percent, and discount rates have declined from the 7.25-percent to 8-percent levels used in the 1999 through 2002 cost determinations, to 6.0 percent used in 2005. Xcel Energy continually reviews its pension assumptions and, in 2006, expects to maintain the investment return assumption at 8.75 percent and to lower the discount rate assumption to 5.75 percent.

 

The investment gains or losses resulting from the difference between the expected pension returns assumed on asset levels and actual returns earned are deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs by using a five-year, moving-average value of pension assets to measure expected asset returns in the cost—determination process, and by amortizing deferred investment gains or losses over the subsequent five-year period. Based on current assumptions and the recognition of past investment gains and losses over the next five years, Xcel Energy currently projects that the pension costs recognized for financial reporting purposes in continuing operations will increase from a credit, or negative expense, of  $2.4 million in 2005 to an expense of $15.3 million in 2006 and $18.7 million in 2007. Pension costs were a credit in 2005 due to the recognized investment asset returns exceeding the other pension cost components, such as benefits earned for current service and interest costs for the effects of the passage of time on discounted obligations.

 

Xcel Energy bases its discount rate assumption on benchmark interest rates from Moody’s Investors Service (Moody’s), and has consistently benchmarked the interest rate used to derive the discount rate to the movements in the long-term corporate bond indices for bonds rated Aaa through Baa by Moody’s, which have a period to maturity comparable to our projected benefit obligations. At Dec. 31, 2005, the annualized Moody’s Baa index rate was 6.21 percent, and the Aaa index rate was 5.26 percent.  Accordingly, Xcel Energy lowered the discount rate to 5.75 percent as of Dec. 31, 2005.  This rate was used to value the actuarial benefit obligations at that date, and will be used in 2006 pension cost determinations.  At Dec. 31, 2004, the annualized Moody’s Baa index rate was 6.10 percent and the Aaa index rate was 5.43 percent.  The corresponding pension discount rate was 6.00 percent.

 

If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1-percent change would result in the following impact on the estimated pension costs recognized by Xcel Energy:

 

               A 100 basis point higher rate of return, 9.75 percent, would decrease 2006 recognized pension costs by $17.0 million;

               A 100 basis point lower rate of return, 7.75 percent, would increase 2006 recognized pension costs by $17.0 million;

               A 100 basis point higher discount rate, 6.75 percent, would decrease 2006 recognized pension costs by $5.4 million; and

               A 100 basis point lower discount rate, 4.75 percent, would increase 2006 recognized pension costs by $7.1 million.

 

Alternative Employee Retirement Income Security Act of 1974 (ERISA) funding assumptions would also change the expected future cash funding requirements for the pension plans. Cash funding requirements can be affected 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 in recent years for Xcel Energy’s pension plans, and do not require funding in 2006. Assuming that future asset return levels equal the actuarial assumption of 8.75 percent for the years 2006 and 2007, Xcel Energy projects, under current funding regulations, that no cash funding would be required for 2006 or 2007. Actual performance can affect these funding requirements significantly. Current funding regulations are under legislative review in 2006 and, if not retained in their current form, could change these funding requirements materially.

 

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Regulation

 

Public Utility Holding Company Act of 1935 (PUHCA) - Historically, Xcel Energy has been a registered holding company under the PUHCA.  As a registered holding company, Xcel Energy, its utility subsidiaries and certain of its nonutility subsidiaries have been subject to extensive regulation by the SEC under the PUHCA with respect to numerous matters, including issuances and sales of securities, acquisitions and sales of certain utility properties, payments of dividends out of capital and surplus, and intra-system sales of certain nonpower goods and services.  In addition, the PUHCA generally limited the ability of registered holding companies to acquire additional public utility systems and to acquire and retain businesses unrelated to the utility operations of the holding company.

 

On Aug. 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), significantly changing many federal statutes and repealing the PUHCA as of Feb. 8, 2006.  However, as part of the repeal of the PUHCA, the FERC was given authority to review the books and records of holding companies and their nonutility subsidiaries to the extent relevant to the charges of jurisdictional utilities, authority to review service company cost allocations, and more authority over the merger and acquisition of public utilities.  With the repeal of PUHCA, state commissions were given similar authority to review the books and records of holding companies and their nonutility subsidiaries.  Despite these increases in the FERC’s authority, Xcel Energy believes that the repeal of the PUHCA will lessen its regulatory burdens and give it more flexibility in the event it were to choose to expand its utility or nonutility businesses.

 

Besides repealing the PUHCA, the Energy Act is also expected to have substantial long-term effects on energy markets, energy investment and regulation of public utilities and holding company systems by the FERC and DOE.  The FERC and the DOE are in various stages of rulemaking in implementing the Energy Policy Act.  While the precise impact of these rulemakings cannot be determined at this time, Xcel Energy generally views the Energy Act as legislation that will enhance the utility industry going forward.

 

Customer Rate Regulation - The FERC and various state regulatory commissions regulate Xcel Energy’s utility subsidiaries.  Decisions by these regulators can significantly impact Xcel Energy’s results of operations. Xcel Energy expects to periodically file for rate changes based on changing energy market and general economic conditions.

 

The electric and natural gas rates charged to customers of Xcel Energy’s utility subsidiaries are approved by the FERC and the regulatory commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an allowed return on investment.  Xcel Energy requests changes in rates for utility services through filings with the governing commissions. Because comprehensive general rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy’s financial results. In addition to changes in operating costs, other factors affecting rate filings are new investments, sales growth, conservation and demand-side management efforts, and the cost of capital.  In addition, the return on equity authorized is set by regulatory commissions in rate proceedings.  The most recently authorized electric utility returns are 11.47 percent for NSP-Minnesota; 11.0 percent for NSP-Wisconsin; 10.75 percent for PSCo; and 11.5 percent for SPS. The most recently authorized natural gas utility returns are 10.4 percent for NSP-Minnesota, 11.0 percent for NSP-Wisconsin and 10.5 percent for PSCo.

 

Wholesale Energy Market Regulation - In April 2005, a Day 2 wholesale energy market operated by the Midwest Independent Transmission System Operator, Inc. (MISO) was implemented to centrally dispatch all regional electric generation and apply a regional transmission congestion management system.  MISO now centrally issues bills and payments for many costs formerly incurred directly by NSP-Minnesota and NSP-Wisconsin.  Both bills and payments from MISO for participation in this centrally dispatched market are received, resulting in a net cost in serving Xcel Energy’s native load obligation.  This net result is recorded as a component of operating and maintenance expenses.  The MPUC issued an interim order in April 2005 allowing MISO Day 2 charges to be recovered through the NSP-Minnesota Fuel Clause Adjustment (FCA) mechanism.  In December 2005, the MPUC issued a second interim order approving the recovery of certain MISO charges through the FCA mechanism but requiring that additional charges either be recovered as part of a general rate case or through an annual review process outside the FCA mechanism, and requiring refunds of non-FCA costs.  However, the December 2005 MPUC order also suspended the refund obligation until such time as it could reconsider the matter.  On Feb. 9, 2006, the MPUC voted to reconsider its December 2005 order.  The MPUC on reconsideration determined that parties be directed to determine which charges are appropriately in the FCA and which are more appropriately established in base rates and report back to the MPUC in 60 days; to grant deferred accounting treatment for costs ultimately determined to be included in base rates for a period of 36 months, with recovery of deferred amounts to be reviewed in a general rate case; and that amounts collected to date through the FCA under the April and December 2005 interim orders are not subject to refund.  As a result, NSP-Minnesota will be allowed to recover its prudently incurred MISO costs either through existing fuel clause mechanisms or in base rates.  In March 2005, the PSCW issued an interim order allowing NSP-Wisconsin deferred accounting treatment of MISO charges.  However, the PSCW staff issued an interpretive memorandum in October 2005 asserting that certain MISO costs may not be recovered through the interim fuel cost mechanism and may not be deferrable.

 

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NSP-Wisconsin and the other Wisconsin utilities contested the PSCW’s interpretation in their November comments to the PSCW.  To date, NSP-Wisconsin has deferred approximately $5.7 million of MISO Day 2 costs as a regulatory asset.

 

Xcel Energy has notified MISO that NSP-Minnesota and NSP-Wisconsin may seek to withdraw from MISO if rate recovery of Day 2 costs is not allowed.  Withdrawal would require FERC approval and could require Xcel Energy to pay a withdrawal fee.

 

In addition, pursuant to FERC orders, NSP-Minnesota and NSP-Wisconsin are billed for certain MISO Day 2 charges associated with the loads of certain wholesale transmission service customers taking service under pre-MISO grandfathered agreements (GFAs).  In March 2005, Xcel Energy filed for the FERC’s approval to pass through these charges to GFA customers.  FERC accepted the filing subject to refund and hearing procedures.  In 2005, NSP-Minnesota and NSP-Wisconsin were billed for $1.1 million of MISO charges, which have not yet been recovered from GFA customers.  The likelihood of full rate-recovery is uncertain at this time.  In addition, Xcel Energy has filed an appeal of the FERC orders.

 

Capital Expenditure Regulation - Xcel Energy’s utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy distribution system. In addition to filing for increases in base rates charged to customers to recover the costs associated with such investments, in 2003 the CPUC and MPUC approved proposals to recover, through a rate surcharge, certain costs to upgrade generation plants and lower emissions in the Denver and Minneapolis-St. Paul metropolitan areas. These rate recovery mechanisms are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis.

 

Future Cost Recovery - Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered from customers in future periods, and to record as regulatory liabilities certain income items that are expected to be refunded to customers in future periods. In contrast, nonregulated enterprises would expense these costs and recognize the income in the current period. If restructuring or other changes in the regulatory environment occur, Xcel Energy may no longer be eligible to apply this accounting treatment, and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on Xcel Energy’s results of operations in the period the write-off is recorded.

 

At Dec. 31, 2005, Xcel Energy reported on its balance sheet regulatory assets of approximately $963 million and regulatory liabilities of approximately $1.7 billion that would be recognized in the statement of operations in the absence of regulation. In addition to a potential write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable under market pricing. See Notes 1 and 16 to the Consolidated Financial Statements for further discussion of regulatory deferrals.

 

Pending and Recently Concluded Regulatory Proceedings

 

NSP-Minnesota Electric Rate Case — In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent.  This increase was based on a requested 11 percent return on common equity, a projected common equity ratio to total capitalization of 51.7 percent and a projected electric rate base of $3.2 billion.  On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006.  The anticipated procedural schedule is as follows:

                    March 2nd — Intervenor Direct Testimony

                    March 30th — Rebuttal Testimony

                    April 13th — Surrebuttal Testimony

                    April 20th — April 28th — Evidentiary Hearings

                    May 24th — Initial Briefs

                    June 6th — Reply Briefs

                    July 6th — Administrative Law Judge Report

                    September 5th — MPUC Order

 

NSP-Wisconsin 2006 General Rate Case — In 2005, NSP-Wisconsin, requested an electric revenue increase of $58.3 million and a natural gas revenue increase of $8.1 million, based on a 2006 test year, an 11.9 percent return on equity and a common equity ratio of 56.32 percent.  On Jan. 5, 2006, the PSCW approved an electric revenue increase of $43.4 million and a natural gas revenue increase of $3.9 million, based on an 11.0 percent return on equity and a 54-percent common equity ratio target.  The new rates were effective Jan. 9, 2006.  The order authorized the deferral of an additional $6.5 million in costs related to nuclear decommissioning and manufactured gas plant site clean up for recovery in the next rate case.  The order also prohibits NSP-Wisconsin from paying dividends above $42.7 million, if its actual calendar year average common equity

 

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ratio is or will fall below 54.03 percent.  It also imposes an asymmetrical electric fuel clause bandwidth of positive 2 percent to negative 0.5 percent outside of which NSP-Wisconsin would be permitted to request or be required to change rates.

 

PSCo Natural Gas Rate Case — In 2005, PSCo filed for an increase of $34.5 million in natural gas base rates in Colorado, based on a return on equity of 11.0 percent with a common equity ratio of 55.49 percent.

 

On Jan. 19, 2006, the CPUC approved a settlement agreement between PSCo and other parties to the case.  Final rates became effective Feb. 6, 2006. The terms of the settlement include:

                    Natural gas revenue increase of $22 million;

                    Return on common equity of 10.5 percent;

                    Earnings over 10.5 percent return on common equity will be refunded back to customers;

                    Common equity ratio of 55.49 percent; and

                    Customer charges for the residential and commercial sales classes of $10 and $20 per month, respectively.

 

Tax Matters

 

Interest Expense Deductibility - PSCo’s wholly owned subsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent life insurance policies, known as COLI policies, on some of PSCo’s employees. At various times, borrowings have been made against the cash values of these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest expense deductions and has disallowed the deductions taken in tax years 1993 through 1999.  Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated $361 million.  In 2004, Xcel Energy received formal notification that the IRS will seek penalties.  If penalties (plus associated interest) are also included, the total exposure through Dec. 31, 2005, is approximately $428 million.  Xcel Energy estimates its annual earnings for 2006 would be reduced by $44 million, after tax, which represents 10 cents per share, if COLI interest expense deductions were no longer available.  See Note 14 to the Consolidated Financial Statements for further discussion.

 

COLI Dow Chemical Court Decision - On Jan. 23, 2006, the 6th Circuit of the U.S. Court of Appeals issued an opinion in a federal income tax case involving the interest deductions for a COLI program at Dow Chemical Company.  The 6th Circuit denied the tax deductions and reversed the decision of the trial court in the case.

 

Xcel Energy has analyzed the impact of the Dow decision on its pending COLI litigation and concluded there are significant factual differences between its case and the Dow case.  The court’s opinion in the Dow case outlined three indicators of potential economic benefits to be examined in a COLI case and noted that the outcome of COLI cases is very fact determinative.  These indicators are:

 

                    Positive pre-deduction cash flows;

 

                    Mortality gains; and

 

                    The buildup of cash values.

 

In a split decision, the 6th Circuit found that the Dow COLI plans possessed none of these indicators of economic substance.  However, in Xcel Energy’s COLI case, the plans were projected to have sizeable pre-deduction cash flows, based upon the relevant assumptions when purchased.  Moreover, the plans presented the opportunity for mortality gains that were not eliminated either retroactively or prospectively.  Xcel Energy’s COLI plans had no provision for giving back any mortality gains that it might realize. In addition, Xcel Energy’s plans had large cash value increases that were not encumbered by loans during the first seven years of the policies.  Consequently, Xcel Energy believes that the facts and circumstances of its case are stronger than Dow’s case and continues to believe its case has strong merits.

 

Environmental Matters

 

Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater environmental awareness and increasingly stringent regulation has caused, and may continue to cause, higher operating expenses and capital expenditures for environmental compliance.

 

In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to operating expenses for environmental monitoring and disposal of hazardous materials and waste were approximately:

 

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                    $147 million in 2005;

 

                    $133 million in 2004; and

 

                    $133 million in 2003.

 

Xcel Energy expects to expense an average of approximately $176 million per year from 2006 through 2010 for similar costs. However, the precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain.

 

Capital expenditures placed in service on environmental improvements at regulated facilities were approximately:

 

                    $37.1 million in 2005;

 

                    $20.9 million in 2004; and

 

                    $58.5 million in 2003.

 

The regulated utilities expect to incur approximately $438 million in capital expenditures for compliance with environmental regulations and environmental improvements in 2006, and approximately $714 million of related expenditures during the period from 2007 through 2010. Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado. Approximately $347 million and $392 million of these expenditures, respectively, are related to modifications to reduce the emissions of NSP-Minnesota’s generating plants located in the Minneapolis-St. Paul metropolitan area pursuant to the MERP, which are recoverable from customers through cost-recovery mechanisms. Expected expenditures related to environmental modifications on Comanche Units 1 and 2 are approximately $26 million in 2006 and $62 million during the period from 2007 through 2010. The remaining expected capital expenditures relate to various other environmental projects. See Note 14 to the Consolidated Financial Statements for further discussion of Xcel Energy’s environmental contingencies.

 

The issue of global climate change is receiving increased attention.  Debate continues concerning the extent to which the earth’s climate is warming, the causes of climate variations that have been observed and the ultimate impact that might result from a changing climate.  There also is considerable debate regarding public policy for the approach that the United States should follow to address the issue.  The United Nations-sponsored Kyoto Protocol, which establishes greenhouse gas reduction targets for developed nations, entered into force on Feb. 16, 2005.  President Bush has declared that the United States will not ratify the protocol and is opposed to legislative mandates, preferring a program based on voluntary efforts and research on new technologies.  Xcel Energy is closely monitoring the issue from both scientific and policy perspectives.  While it is not possible to know the eventual outcome, Xcel Energy believes the issue merits close attention and is taking actions it believes are prudent to be best positioned for a variety of possible outcomes.  Xcel Energy is participating in a voluntary carbon management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009, and to reduce carbon intensity by 7 percent by 2012.  In certain regulatory jurisdictions, the evaluation process for future generating resources incorporates the risk of future carbon limits through the use of a carbon cost adder or externality costs.  Xcel Energy also is involved in other projects to improve available methods for managing carbon.

 

Impact of Nonregulated Investments

 

In the past, Xcel Energy’s investments in nonregulated operations have had a significant impact on its results of operations. As a result of the divestiture of NRG and other nonregulated operations, Xcel Energy does not expect that its investments in nonregulated operations will continue to have such