Item 1 B - Unresolved SEC Staff Comments
None
Item 2
Item 2 - Properties
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2005:
SPS had 465 electric utility transmission and distribution substations at Dec. 31, 2005.
Item 3
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against SPS. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.
Other Matters
For more discussion of legal claims and environmental proceedings, see Note 11 to the Financial Statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates, see Pending and Recently Concluded Regulatory Proceedings under Item 1, incorporated by reference.
Item 4
Item 4 - Submission of Matters to a Vote of Security Holders
This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
PART II
Item 5
Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
SPS is a wholly owned subsidiary and there is no market for its common equity securities.
SPS had dividend restrictions imposed by state regulatory commissions and debt agreements limiting the amount of dividends SPS can pay to Xcel Energy. These restrictions included, but may not have been limited to, the following:
• maintenance of a minimum equity ratio of 30 percent;
• payment of dividends only from retained earnings; and
• debt covenant restriction under the credit agreement for the debt to total capital ratio.
Dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts.
The dividends declared during 2005 and 2004 were as follows:
Item 6
Item 6 - Selected Financial Data
This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Item 7
Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations
Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Forward Looking Information
The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of SPS during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the respective accompanying Financial Statements and Notes to the Financial Statements.
Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions. Actual results may vary materially. 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 to obtain financing on favorable terms;
• rating agency actions;
• business conditions in the energy industry;
• competitive factors including the extent and timing of the entry of additional competition;
• unusual weather;
• changes in federal or state legislation;
• geopolitical events, including war and acts of terrorism;
• regulation; and
• the other risk factors listed from time to time by SPS in reports filed with the SEC, including Exhibit 99.01 to this Annual Report on Form 10-K for the year ended Dec. 31, 2005.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
SPS’ net income was approximately $62.4 million for 2005, compared with approximately $54.9 million for 2004.
Electric Utility, Short-Term Wholesale and Commodity Trading Margin
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 cost recovery mechanisms for retail customers, most fluctuations in energy costs do not significantly affect electric margin.
SPS 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 SPS’ generation assets and energy and capacity purchased to serve native load. Commodity trading is not associated with SPS’ generation assets or the energy and capacity purchased to serve native load.
SPS conducts an inconsequential amount of commodity trading. Margins from commodity trading activity are partially redistributed to NSP-Minnesota and PSCo pursuant to the JOA approved by the FERC. Margins received pursuant to the JOA are reflected as part of Base Electric Utility Revenues. Short-term wholesale and commodity trading margins reflect the impact of regulatory sharing, if applicable. Trading revenues, as discussed in Note 1 to the Financial Statements, are reported net of trading costs (i.e., on a margin basis) in the Statements of Income. Commodity trading costs include fuel, purchased power, transmission and other related costs. The following table details base electric utility and short-term wholesale activities:
The following summarizes the components of the changes in base electric revenue and base electric margin for the year ended Dec. 31:
Base Electric Revenue
Base Electric Margin
Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is subject to periodic approval by the PUCT.
Non-Fuel Operating Expense and Other Costs - The following summarizes the components of the changes in other utility operating and maintenance expense for the year ended Dec. 31:
Depreciation and amortization expense increased by approximately $4.4 million, or 4.8 percent, for 2005 compared with 2004, primarily due to plant additions and software amortization.
Taxes (other than income taxes) decreased by approximately $0.6 million, or 1.2 percent, for 2005 compared with 2004, primarily due to the receipt of the updated annual Texas franchise tax apportionment.
Interest and other income increased by $3.1 million, for 2005 compared with 2004, primarily due to a $2.2 million gain on the sale of water rights.
Interest charges and financing costs increased by approximately $0.4 million, or 0.8 percent, for 2005 compared with 2004. The increase is primarily due to increased borrowing under a five-year credit facility.
Income taxes increased by approximately $6.5 million in 2005, compared with 2004. The increase was primarily due to higher income levels. The effective tax rate was 37.7 percent for the year ended Dec. 31, 2005, compared with 36.3 percent for the same period in 2004. The lower effective tax rate in 2004 was primarily due to lower income levels and income tax benefits recorded in 2004 related
to successful resolution of audit issues and other adjustments to current and deferred taxes.
Item 7A
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
Derivatives, Risk Management and Market Risk
In the normal course of business, SPS is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. These risks, as applicable to SPS, are discussed in further detail below.
Commodity Price Risk - SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products, and for various fuels used in the generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. SPS’ risk management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.
Short-Term Wholesale and Commodity Trading Risk - SPS conducts an immaterial amount of short-term wholesale and commodity-marketing activities, including the purchase and sale of capacity, energy and energy related instruments. These marketing activities are primarily focused on specific regions where market knowledge and experience have been obtained. SPS’ risk-management policy allows management to conduct the marketing activities within approved guidelines and limitations as approved by the company’s risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.
Certain contracts within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 - “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133).
See Note 9 to the Financial Statements for a discussion of the hedging contracts of SPS.
SPS did conduct limited commodity trading activities during 2005. However, the quantity and duration of activity had no material impact on the reported VaR for the short-term wholesale and commodity trading activities for Xcel Energy.
Interest Rate Risk - SPS is subject to the risk of fluctuating interest rates in the normal course of business. SPS’ risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options, subject to regulatory approval when required.
SPS may engage in hedges of cash flow exposure. The fair value of interest rate swaps designated as cash flow hedges is initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument, and generally offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. To test the effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis, if required. The fair value of interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.
At Dec. 31, 2005 and 2004, a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would impact pretax interest expense by approximately $0.7 million and $0.2 million, respectively. See Note 9 to the Financial Statements for a discussion of SPS’ interest rate swaps.
Credit Risk - In addition to the risks discussed previously, SPS is exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. SPS maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
SPS conducts standard credit reviews for all counterparties. SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.
Item 8
Item 8 - Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholder
Southwestern Public Service Company
We have audited the accompanying balance sheets and statements of capitalization of Southwestern Public Service Company (the “Company”) as of December 31, 2005 and 2004, and the related statements of income, common stockholder’s equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Southwestern Public Service Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME (Thousands of Dollars)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS
(Thousand of Dollars)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS (Thousands of Dollars)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME
(Dollars in Thousands)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CAPITALIZATION
(Thousands of Dollars)
See Notes to Financial Statements
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Business and System of Accounts - SPS is principally engaged in the purchase, transmission, distribution and sale of electricity. SPS was subject to the regulatory provisions of the PUHCA and regulation by the FERC and state utility commissions. All of SPS’ accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
On Aug. 8, 2005, President Bush signed into law the Energy Act, significantly changing many federal energy statutes. The Energy Act is expected to have a substantial long-term effect on energy markets, energy investment, and regulation of public utilities and holding company systems by the FERC, the SEC and the DOE. The FERC was directed by the Energy Act to address many areas previously regulated by other governmental entities under the statutes and determine whether changes to such previous regulations are warranted. The issues that the FERC has been required to consider associated with the repeal of the PUHCA include, but are not limited to, the expansion of the FERC authority to review mergers and sales of public utility companies and the expansion of the FERC authority over the books and records of holding companies and public utility companies previously governed by the SEC and the appropriate cost standard for the provision of non-power goods and services by service companies. The FERC is in various stages of rulemaking on these and other issues. Xcel Energy cannot predict the impact the new rulemakings will have on its operations or financial results, if any.
Principles of Consolidation - Prior to January 2004, SPS consolidated a subsidiary, for which all significant intercompany transactions and balances were eliminated.
Revenue Recognition - Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated.
SPS has various rate adjustment mechanisms in place that currently provide for the recovery of certain purchased natural gas and electric energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total amount collected under the clauses and the recoverable costs incurred. In addition, SPS presents its revenue net of any excise or other fiduciary-type taxes or fees. A summary of significant rate adjustment mechanisms follows:
• In Texas, SPS may request periodic adjustments to provide electric fuel and purchased energy cost recovery. In New Mexico, SPS has a monthly fuel and purchased power cost-recovery factor.
• SPS sells firm power and energy in wholesale markets, which are regulated by the FERC. These rates include monthly wholesale fuel cost recovery mechanisms.
Commodity Trading Operations - All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the Statements of Income.
Pursuant to the JOA approved by the FERC, some of the commodity trading margins from SPS are apportioned to NSP-Minnesota and PSCo. Commodity trading activities are not associated with energy produced from SPS’ generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value in accordance with SFAS No. 133. In addition, commodity-trading results include the impacts of any margin-sharing mechanisms, if applicable. For more information, see Note 9 to the Financial Statements.
Derivative Financial Instruments - SPS utilizes a variety of derivatives, including interest rate swaps and locks, and physical based commodity contracts to reduce exposure to commodity price and interest rate risks. These contracts consist mainly of commodity futures and options, index or fixed price swaps and basis swaps. For more information on SPS’ risk management and derivative activities, see Note 9 to the Financial Statements.
Property, Plant, Equipment and Depreciation - Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Removal costs associated with regulatory obligations are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred.
Property, plant and equipment also includes costs associated with other property held for future use.
SPS determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s useful life. Depreciation expense, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2005, 2004 and 2003 was 2.8 percent, 2.8 percent and 2.7 percent, respectively.
Allowance for Funds Used During Construction (AFDC) - AFDC represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in SPS’ rate base for establishing utility service rates.
Environmental Costs - Environmental costs are recorded when it is probable SPS is liable for the costs and the liability can be reasonably estimated. Costs may be deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.
Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for the utility subsidiary share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.
Legal Costs - Litigation accruals are recorded when it is probable SPS is liable for the costs and the liability can be reasonably estimated. Legal accruals are recorded net of insurance recovery. Legal costs related to settlements are not accrued, but expensed as incurred.
Income Taxes - Xcel Energy and its utility subsidiaries, including SPS, file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss. In accordance with the PUHCA requirements, the holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company in the consolidated federal or combined state returns. SPS defers income taxes for all temporary differences between the book and tax bases of assets and liabilities. The tax rates used are those that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.
Investment tax credits are deferred and their benefits amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12 to the Financial Statements. For more information on income taxes, see Note 6 to the Financial Statements.
Use of Estimates - In recording transactions and balances resulting from business operations, SPS uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, asset retirement obligations, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information is obtained or actual amounts are determinable. Those revisions can affect operating results. Each year the depreciable lives of certain plant assets are reviewed and revised, if appropriate.
Cash and Cash Equivalents - SPS considers investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Those instruments are primarily commercial paper and money market funds.
Inventory - All inventories are recorded at average cost.
Regulatory Accounting - SPS accounts for certain income and expense items in accordance with SFAS No. 71 - “Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71:
• certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and
• certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they
will be returned to customers in future rates.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.
If restructuring or other changes in the regulatory environment occur, SPS 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 SPS’ results of operations in the period the write-off is recorded. See more discussion of regulatory assets and liabilities at Note 12 to the Financial Statements.
Deferred Financing Costs - Other assets include deferred financing costs, which are amortized over the remaining maturity periods of the related debt. SPS’ deferred financing costs, net of amortization at Dec. 31, 2005 and 2004 were $3.7 million and $4.7 million, respectively.
Accounts Receivable and Allowance for Uncollectibles - Accounts receivable are stated at the actual billed amount net of write-offs and allowance for uncollectibles. SPS establishes an allowance for uncollectibles based on a reserve policy that reflects its expected exposure to the credit risk of customers.
2. Short-Term Borrowings
Notes Payable and Commercial Paper - During 2005, SPS resumed short-term borrowings in the commercial paper market. Information regarding notes payable and commercial paper for the years ended Dec. 31, 2005 and 2004 are presented in the following table:
Money Pool - Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals. The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. SPS has approval to borrow up to $100 million under the arrangement. SPS had no borrowings or loans outstanding under the arrangement at Dec. 31, 2005. As a consequence of the repeal of PUHCA and the recent amendments to the Federal Power Act, it may be necessary for SPS to submit its existing money pool arrangement to FERC for its approval. SPS is presently evaluating the situation.
3. Long-Term Debt
Credit Facilities - At Dec. 31, 2005, SPS had the following committed credit facility available, in millions of dollars:
* Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings.
The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. SPS has the right to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval. The credit facility has one financial covenant requiring that SPS’ debt to total capitalization ratio be less than or equal to 65 percent with which SPS is in compliance. The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as determined by SPS’ senior unsecured credit ratings from Moody, Standard & Poor and Fitch.
As of Dec. 31, 2005, SPS had no direct borrowings on this line of credit, however this credit facility served as back-up support for SPS’ commercial paper and letters of credit. Also, $0.6 million of letters of credit were outstanding at Dec. 31, 2005, as discussed in Note 10 to the Financial Statements, of which approximately $0.6 million were outstanding under the above credit facility and are included in the above table.
Certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.
Maturities of long-term debt are:
Future Financing Plans - SPS plans to refinance existing long-term debt or scheduled long-term debt maturities based on prevailing market conditions. To facilitate potential long-term debt issuances, SPS intends to file a long-term debt shelf registration statement with the SEC for up to $500 million in 2006.
4. Preferred Stock
SPS has authorized the issuance of preferred stock.
5. Mandatorily Redeemable Preferred Securities of Subsidiary Trusts
SPS Capital I, a wholly owned, special-purpose subsidiary trust of SPS, had $100 million of 7.85-percent trust preferred securities issued and outstanding that were originally scheduled to mature in 2036. The securities were redeemable at the option of SPS, at 100 percent of the principal amount plus accrued interest. On Oct. 15, 2003, SPS redeemed the $100 million of trust preferred securities. A certificate of cancellation was filed to dissolve SPS Capital I on Jan. 5, 2004.
Distributions paid to preferred security holders are reflected as a financing cost in the accompanying Statements of Income along with interest expense.
6. Income Taxes
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following is a table reconciling such differences for the years ending Dec. 31:
Income taxes comprise the following expense (benefit) items for the years ending Dec. 31:
The components of deferred income tax were:
The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:
7. Benefit Plans and Other Postretirement Benefits
Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to SPS.
Xcel Energy offers various benefit plans to its employees, including those of SPS. Approximately 56 percent of Xcel Energy benefit employees are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2005, SPS had 733 bargaining employees covered under a collective-bargaining agreement, which expires in October 2008.
Pension Benefits
Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees, including those of SPS. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.
Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
Pension Plan Assets - Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. In 2004, Xcel Energy completed a review of its pension plan asset allocation and adopted revised asset allocation targets. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments and 20 percent in nontraditional investments, such as real estate, timber ventures, private equity and a diversified commodities index.
The actual composition of pension plan assets at Dec. 31 was:
Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted
average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 12.0 percent, which is greater than the current assumption level. The pension cost determinations assume the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments that can provide a higher-than-average return. As is the experience in recent years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year. Investment returns in 2005, 2004 and 2003 exceeded the assumed levels of 8.75 percent, 9.0 percent and 9.25 percent, respectively. Xcel Energy continually reviews its pension assumptions. In 2006, Xcel Energy will continue to use an investment return assumption of 8.75 percent.
Benefit Obligations - A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:
Cash Flows - Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding in the years 2003 through 2005 for Xcel Energy’s pension plans and are not expected to require cash funding in 2006. SPS vountarily contributed $1.5 million to the NCE nonbargaining plan in 2005.
Benefit Costs - The components of net periodic pension cost (credit) are:
Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2006 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets, which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.
Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.
Defined Contribution Plans
Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for SPS were approximately $1.1 million in 2005, $1.1 million in 2004 and $1.4 million in 2003.
Postretirement Health Care Benefits
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. Employees of the former New Century Energies, Inc (NCE) who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE, who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
In conjunction with the 1993 adoption of SFAS No. 106 - “Employers’ Accounting for Postretirement Benefits Other Than Pension,” Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.
Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106.
Plan Assets - Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates. In 2004, the investment strategy for the union asset fund was changed to increase the exposure to equity funds. Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.
The actual composition of postretirement benefit plan assets at Dec. 31 was:
Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs.
Benefit Obligations - A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:
Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend assumption from 5.5 percent to 5.0 percent. The period until the ultimate rate is reached was also increased from two years to six years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.
A 1-percent change in the assumed health care cost trend rate would have the following effects on SPS:
The employer subsidy for retiree medical coverage was eliminated for former NCE. non-bargaining employees who retire after July 1, 2003. Curtailment and settlement gains resulted from activities of some of Xcel Energy’s nonregulated subsidiaries.
Cash Flows - The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash
funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $75 million during 2006.
Benefit Costs - The components of net periodic postretirement benefit cost are:
Projected Benefit Payments
The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans.
8. Detail of Interest and Other Income, net of Nonoperating Expenses
Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 consists of the following:
9. Derivative Instruments
In the normal course of business, SPS is exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of changes in the market or fair value of a particular instrument or commodity. SPS utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance our operations. The use of these derivative instruments is discussed in further detail below.
Utility Commodity Price Risk - SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products. Commodity risk also is managed through the use of financial derivative instruments. SPS utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though regulatory jurisdiction may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is done consistently with the local jurisdictional cost recovery mechanism. SPS’ risk-management policy allows it to manage market price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.
Short-Term Wholesale and Commodity Trading Risk - SPS conducts an immaterial amount of short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and other energy-related instruments. These activities are primarily focused on specific regions where market knowledge and experience have been obtained. SPS’ risk-management policy allows management to conduct the marketing activity within approved guidelines and limitations as approved by our risk-management committee, which is made up of management personnel not directly involved in the activities governed by this policy.
Interest Rate Risk - SPS is subject to the risk of fluctuating interest rates in the normal course of business. SPS’ risk-management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
Types of and Accounting for Derivative Instruments
SPS uses a number of different derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, as amended, are recorded at fair value. The classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship. The fair values of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Statements of Income, to the extent effective.
SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. SPS formally documents hedging relationships, including, among other things, the identification of the hedging instrument and the hedged transaction, as well as the risk-management objectives and strategies for undertaking the hedged transaction. SPS also formally assesses, both at inception and on an ongoing basis, if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of the hedged items.
Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs and interest rate hedging transactions are recorded as a component of interest expense. SPS is allowed to recover in electric rates the costs of certain financial instruments acquired to reduce commodity cost volatility.
Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions that SPS is currently engaged in are discussed below.
Cash Flow Hedges
The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recognized in Other Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.
Interest Rate Cash Flow Hedges - SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes.
As of Dec. 31, 2005, SPS had net losses of approximately $0.5 million in Accumulated Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.
SPS also enters into interest rate lock agreements, including treasury-rate locks and forward starting swaps, that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.
SPS had no ineffectiveness related to interest rate cash flow hedges during the years ended Dec. 31, 2005 and 2004, respectively.
Financial Impacts of Qualifying Cash Flow Hedges - The impact of qualifying cash flow hedges on SPS’ Other Comprehensive Income, included in the Statements of Stockholder’s Equity, is detailed in the following table:
Fair Value Hedges
The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of a derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings. At Dec. 31, 2005, SPS had no fair value hedges.
Normal Purchases or Normal Sales Contracts
SPS enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is 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.
SPS evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the commodity trading operations qualify for a normal designation.
Normal purchases and normal sales contracts are accounted for as executory contracts as required under GAAP.
On Dec. 31, 2005 and 2004, SPS had interest rate swaps outstanding with a fair value that was a liability of approximately $5.8 million and $6.7 million, respectively.
10. Financial Instruments
The estimated Dec. 31 fair values of SPS’ recorded financial instruments are as follows:
The fair values of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates. The fair values of SPS’ long-term investments are estimated based on quoted market prices for those or similar investments. The fair value of SPS’ long-term debt is estimated based on the quoted market prices for the same or similar issues or the current rates for debt of the same remaining maturities and credit quality.
The fair value estimates presented are based on information available to management as of Dec. 31, 2005 and 2004. These fair value estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current estimates of fair values may differ significantly.
Letters of Credit
SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2005, there was $0.6 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair values and are subject to fees determined in the marketplace.
11. Commitments and Contingent Liabilities
Leases - SPS leases a variety of equipment and facilities used in the normal course of business. The leases are accounted for as operating leases. Rental expense under operating lease obligations was approximately $4.6 million, $3.1 million and $3.5 million for 2005, 2004 and 2003, respectively.
Future commitments under operating leases are:
Capital Commitments - The estimated cost, as of Dec. 31, 2005, of the capital expenditure programs and other capital requirements of SPS is approximately $99 million in 2006, $127 million in 2007 and $121 million in 2008.
The capital expenditure programs of SPS are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in projected electric load growth, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting SPS’s long-term energy needs. In addition, SPS’s ongoing evaluation of compliance with future requirements to install emission-control equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.
Fuel Contracts - SPS has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2006 and 2017. In addition, SPS is required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs.
The estimated minimum purchase for SPS under these contracts as of Dec. 31, 2005, is as follows:
Purchased Power Agreements - SPS has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. SPS has various pay-for-performance contracts with expiration dates through the year 2024. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on indexes. However, the effect of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.
At Dec. 31, 2005, the estimated future payments for capacity that SPS is obligated to purchase, subject to availability, are as follows (Thousands of Dollars):
Environmental Contingencies
SPS has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, SPS is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such claims. Additionally, where applicable, SPS is pursuing, or intends to pursue, recovery from other potentially responsible parties and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for SPS, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, SPS would be required to recognize an expense for such unrecoverable amounts in its Financial Statements.
Site Remediation - SPS must pay all or a portion of the cost to remediate sites where past activities of SPS and some other parties have caused environmental contamination. At Dec. 31, 2005, SPS was a party to third party and other sites, such as landfills, to which we are alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.
SPS records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially.
To estimate the cost to remediate these sites, assumptions are made where facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.
Estimates are revised as facts become known. At Dec. 31, 2005, the liability for the cost of remediating sites was estimated to be $0.2 million, of which $0.1 million was considered to be a current liability. Some of the cost of remediation may be recovered from:
• insurance coverage;
• other parties that have contributed to the contamination; and
• customers.
Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for SPS’ future costs for these sites.
Third Party and Other Environmental Site Remediation
Asbestos Removal - Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. SPS has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See additional discussion of asset retirement obligations elsewhere in Note 11. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.
Polychlorinated Biphenyl (PCB) Storage and Disposal - In August 2004, SPS received notice from the EPA contending SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contends the fine for the alleged violation is approximately $1.2 million. SPS is contesting the fine and is in discussions with the EPA.
Cunningham Station Groundwater - Cunningham Station is a natural gas-fired power plant constructed in the 1960’s by SPS and has 28 water wells installed on its water rights. The well field provides water for boiler makeup, cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination was identified in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blow down water from the plant. In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blow down ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan is subject to continued compliance with New Mexico regulations and oversight by the NMED. These actions, which are considered future improvements, are estimated to cost approximately $3.8 million through 2008 and will be capitalized or expensed as incurred.
Clean Air Interstate and Mercury Rules-In March 2005, the EPA issued two significant new air quality rules. The Clean Air Interstate Rule (CAIR) further regulates sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions, and the Clean Air Mercury Rule (CAMR) regulates mercury emissions from power plants for the first time.
The objective of the CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Texas. When fully implemented, CAIR will reduce SO2 emissions in 28 eastern states and the District of Columbia by over 70 percent and NOx emissions by over 60 percent from 2003 levels. It is designed to address the transportation of fine particulates, ozone and emission precursors to non-attainment downwind states. CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOX that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.
On July 11, 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD filed a lawsuit against the EPA and a request for reconsideration with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request for reconsideration.
Xcel Energy and SPS advocated that West Texas should be excluded from CAIR, because it does not contribute significantly to nonattainment with the fine particulate matter National Ambient Air Quality Standard in any downwind jurisdiction. They argued that:
• Emissions from plants located in the Texas panhandle are more than 1,000 kilometers away from cities like Chicago, St. Louis and Indianapolis and have no measurable impact on their air quality.
• The EPA should not arbitrarily include the entire state of Texas in the rule. As a result of its size, there are significant differences in the air quality impacts of plants in the different regions of Texas.
• The EPA has precedent for dividing the state into two regions. As part of the Texas Air Quality strategy, the Texas Commission on Environmental Quality split the state and imposed different requirements on West Texas. The Bush Administration adopted a similar approach in its proposed Clear Skies Act.
• The EPA excluded Oklahoma and Kansas from CAIR, but imposes CAIR’s burdens on plants in West Texas. Emissions from West Texas must pass through Oklahoma and Kansas-and over power plants in those states that are not subject to the rule-before reaching the downwind cities the rule is designed to protect.
Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Based on the preliminary analysis of various scenarios of capital investment and allowance purchase, capital investments could range from $30 million to $300 million and allowance purchases or increased operating and maintenance expenses could range from $20 million to $30 million per year, beginning in 2011 based on the cost of allowance on Feb. 15, 2006. This does not include other costs that SPS will have to incur to comply with EPA’s new mercury emission control regulations, which will apply to SPS’ plants.
These cost estimates represent one potential scenario on complying with CAIR, if West Texas is not excluded. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditure and operating expenses.
While SPS expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. SPS believes the cost of any required capital investment or allowance purchases will be recoverable from customers.
The EPA’s CAMR also uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that are greater than 25 megawatts. Compliance with this rule also occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Similar to CAIR, states can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.
Under CAMR, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury allowances. SPS’ preliminary analysis for Phase I compliance suggests capital costs of approximately $14.3 million and increased operating and maintenance expenses of approximately $6.6 million, beginning in 2010. Further testing is planned during 2006 to confirm these costs or determine whether different measures will be necessary, which could result in higher costs. Additional costs will be incurred to meet Phase II requirements in 2018.
Regional Haze Rules - On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Some of SPS’ generating facilities will be subject to BART requirements. Some of these facilities are located in regions where the CAIR is effective. CAIR has precedence over BART. Therefore, BART requirements will be deemed to be met through compliance with CAIR requirements.
States must develop their implementation plans by December 2007. States will identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. Due to the uncertainties of the many decisions involved in this process, SPS is not able to estimate the cost impact at this time.
Asset Retirement Obligations
SPS adopted Statement of Financial Accounting Standard SFAS No. 143 - “Accounting for Asset Retirement Obligations” Effective Jan. 1, 2003. SPS records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.
In March 2005, the FASB issued FASB Interpretation No. 47- “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47) to clarify the scope and timing of liability recognition for conditional asset retirement obligations pursuant to SFAS No. 143. The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the fair value is estimable, even when the obligation is dependent on a future event. FIN No. 47 further clarified that uncertainty surrounding the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation rather than affect whether a liability should be recognized. SPS implemented FIN No. 47 as of Dec. 31, 2005. Included in these financial statements is the recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis.
Recorded Asset Retirement Obligations (ARO) - Asset retirement obligations have been recorded for steam production and electric transmission and distribution systems. The steam production obligation includes asbestos and ash containment facilities. The asbestos recognition associated with the steam production includes certain plants at SPS. Generally, this asbestos abatement removal obligation originated in 1973 with the Clean Air Act applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. Asset retirement obligations also have been recorded for SPS steam production related to ash containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination date on the ARO recognition for ash containment facilities at steam plants was the in-service date of various facilities.
An ARO was recognized for the removal of electric transmission and distribution equipment at SPS. The electric transmission and distribution ARO consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. These electric assets have many in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured at Dec. 31, 2005. The asset retirement cost was set to this recognized obligation and no cumulative effect adjustment was shown.
A reconciliation of the beginning and ending aggregate carrying amount of SPS’s asset retirement obligations is shown in the table below for the 12 months ended Dec. 31, 2005:
Cumulative Effect of FIN No. 47 - In March 2005, the FASB issued FIN No. 47. The interpretation clarified the term “conditional asset retirement obligation” as used in SFAS No. 143. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. If SPS had implemented FIN No. 47 at Jan. 1, 2004, the liability for asset retirement obligations would have increased by $3.4 million. The same liability at Dec. 31, 2004 would have increased by $3.6 million. A summary of the accounting for the initial adoption of FIN No. 47, as of Dec. 31, 2005 is as follows:
Removal Costs - SPS accrues an obligation for plant removal costs for generation, transmission and distribution facilities. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs as of Dec. 31, 2005 and 2004 are $98 million and $104 million, respectively.
Legal Contingencies
In the normal course of business, SPS is party to routine claims and litigation arising from prior and current operations. SPS is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition when it can be reasonably estimated.
Carbon Dioxide Emissions Lawsuit - On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. Although SPS is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on SPS. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit should be dismissed because it is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs have filed a notice of appeal.
The issue of global climate change is receiving increased attention. Debate continues in the scientific community concerning the extent to which the earth’s climate is warming, the causes of climate variations that have been observed, and the ultimate impacts 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 future 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 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.
Lamb County Electric Cooperative - On July 24, 1995, Lamb County Electric Cooperative, Inc. (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 October 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts as alleged in its 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 the May 23, 2003 PUCT order could result in a re-determination of the legality of SPS’ service to the disputed customers.
12. Regulatory Assets and Liabilities
SPS’ financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric rates. Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting. If changes in the utility industry or the business of SPS no longer allow for the application of SFAS No. 71 under GAAP, SPS would be required to recognize the write-off of regulatory assets and liabilities in its statement of income. The components of unamortized regulatory assets and liabilities on the balance sheets of SPS are:
(a) Includes the fair value of certain long-term contracts used to meet native energy requirements.
(b) Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
13. Segment and Related Information
SPS has only one reportable segment. SPS operates in the Regulated Electric Utility industry providing wholesale and retail electric service in the states of Texas, New Mexico, Kansas and Oklahoma. Revenues from external customers were $1,627.2 million, $1,333.8 million and $1,201.3 million for the years ended Dec. 31, 2005, 2004 and 2003, respectively.
14. Related Party Transactions
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including SPS. The services are provided and billed to each subsidiary in accordance with Service Agreements approved by the SEC and executed by each subsidiary. Costs are charged directly to the subsidiary which uses the service whenever possible, and are allocated using an SEC approved method if they cannot be directly assigned.
Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory approvals. See Note 2 for further discussion of this borrowing arrangement.
Utility Engineering Corp. (UE), a former Xcel Energy subsidiary, provided construction services to SPS, for which it was paid $3.7 million in 2005, $14.6 million in 2004 and $15.9 million in 2003. SPS purchased 6 substations from UE for approximately $1.3 million prior to UE being sold in April 2005.
SPS purchases electricity from Borger Energy Associates, which is partially owned by one of Xcel Energy’s discontinued subsidiaries.
The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
Accounts receivable and payable with affiliates at Dec. 31 was:
15. Summarized Quarterly Financial Data (Unaudited)
(a) Fourth-quarter results were decreased by a $19.7 million accrual recorded to reflect SPS’ best estimate of any potential liability for the impact of its retail fuel cost recovery proceeding in Texas.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 2004 and 2005, and through the date of this report, there were no disagreements with the independent public accountants for SPS on accounting principles or practices, financial statement disclosures or auditing scope or procedures.
Item 9A
Item 9A - Controls and Procedures
Disclosure Controls and Procedures
SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. As of the end of the period covered by this report, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of its disclosure controls and procedures, the CEO and CFO have concluded that the Company’s disclosure controls and procedures are effective.
Internal Control Over Financial Reporting
No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting.
Item 9B
Item 9B - Other Information
None
PART III
Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for SPS in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.
Item 10
Item 10 - Directors and Executive Officers of the Registrant
Item 11
Item 11 - Executive Compensation
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Item 13
Item 13 - Certain Relationships and Related Transactions
Item 14
Item 14 - Principal Accounting Fees and Services
Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2006 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV
Item 15
Item 15 - Exhibits, Financial Statement Schedules
1.
Financial Statements
Reports of Independent Registered Public Accounting Firm - For the years ended Dec. 31, 2005, 2004 and 2003.
Statements of Income - For the three years ended Dec. 31, 2005, 2004 and 2003.
Statements of Cash Flows - For the three years ended Dec. 31, 2005, 2004 and 2003.
Balance Sheets - As of Dec. 31, 2005 and 2004.
2.
Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2005, 2004 and 2003.
3.
Exhibits
*Indicates incorporation by reference
+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
2.01*
Agreement and Plan of Reorganization dated Aug 22. 1995 (Exhibit 2 to Form 8-K (file no. 001-03789) dated Aug. 22, 1995).
3.01*
Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*
By-laws dated Sept. 29, 1997 (Exhibit 3(b)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
4.01*
Indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.02*
First Supplemental Indenture dated March 1, 1999 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 99.3 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.03*
Second Supplemental Indenture dated Oct. 1, 2001 between Southwestern Public Service Co. and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001).
4.04*
Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between Southwestern Public Service Co. and JPMorgan Chase Bank, as successor trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.05*
Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
4.06*
$250,000,000 Credit Agreement among Southwestern Public Service Company, as Borrower, the several lenders from time to time parties hereto, Barclays Bank PLC and Harris Nexbitt Financing, INC., as documentation agents, The Bank of New York and Wells Fargo Bank, National Association, as syndication agents, and JPMorgan Chase Bank, N.A., as administrative agent dated as of April 21, 2005 (Exhibit 4.03 to Form 10-Q (file no. 001-03034) dated March 31, 2005).
4.07*
Registration Rights Agreement dated Oct. 6, 2003 among Southwestern Public Service Co., Citigroup Global Markets Inc. and Credit Suisse First Boston LLC.
10.01*+
Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+
Xcel Energy Executive Annual Incentive Award Plan (Exhibit B to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.03*+
Employment Agreement dated March 24, 1999, among Northern States Power Co. (a Minnesota corporation), New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).
10.04*+
Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.05*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy As Amended and Restated Effective Oct. 1, 1997. (Exhibit 10.15 to NSP-Minnesota Form 10-K (file no. 001-03034) for the year 1997).
10.06*+
Senior Executive Severance Policy, effective March 24, 1999, between New Century Energies, Inc. and Senior Executives (Exhibit 10(a)(2) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).
10.07*+
New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998.
10.08*+
Directors’ Voluntary Deferral Plan (Exhibit 10(d) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec 31, 1998).
10.09*+
Supplemental Executive Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.10*+
Salary Deferral and Supplemental Savings Plan for Executive Officers (Exhibit 10(f) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.11*+
Salary Deferral and Supplemental Savings Plan for Key Managers (Exhibit 10(g) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.12*+
Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1991).
10.13*+
Form of Key Executive Severance Agreement, as amended on Aug. 22, and Nov. 27, 1995. (Exhibit 10(e)(4) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1995).
10.14*+
Supplemental Retirement Income Plan as amended July 23, 1991 (Exhibit 10(d) to SPS Form 10-K, (file no. 001-03789) dated Aug. 31, 1996).
10.15*+
Xcel Energy Senior Executive Severance and Change-in-Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004).
10.16*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2004 (Exhibit B to Form DEF-14A (file no. 001-03034) dated Apr. 9, 2004).
10.17*+
Xcel Energy Nonqualified Deferred Compensation Plan (2002 restatement) (Exhibit 10.23 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.18*+
Xcel Energy Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.19*+
Xcel Energy 401(k) Savings Plan, amended and restated as of Jan. 1, 2002 (Exhibit 10.19 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
10.20*+
New Century Energies, Inc. Employee Investment Plan for Bargaining Unit Employees and Former Non-bargaining Unit Employees, as amended and restated effective Jan. 1, 2004 but with certain retroactive amendments (Exhibit 10.20 to SPS Form S-4 (file no. 333-112032) dated Jan. 21, 2004).
10.21*
Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.22*
Securities Litigation Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.23*
ERISA Actions Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.24*
Shareholder Derivative Action Settlement Agreement as of Dec. 31, 2004 and approved Jan. 14, 2005 (Exhibit 10.03 to Form 8-K (file no. 001-03034) dated Jan. 14, 2005).
10.25*+
Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.26*+
Compensation and reimbursement practices for Xcel Energy non-employee directors (Exhibit 10.01 to Xcel Energy Form 10-Q (file no. 001-03034) dated Sept. 30, 2005.
10.27*+
Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2005 (Exhibit 10.27 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.28*+
Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.28 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.29*+
Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.30*+
Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.31*+
Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.32*+
Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.33*+
Xcel Energy Omnibus 2005 Incentive Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.34*+
Xcel Energy Executive Annual Incentive Award Plan (Exhibit 10.02 to Form 8-K (file no. 001-03034) dated May 25, 2005).
10.35*+
Xcel Energy Amended Employment Agreement, between Xcel Energy Inc. and Wayne H. Brunetti (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated June 29, 2005).
10.36*+
Xcel Energy Supplemental Executive Retirement Plan (Exhibit 10.01 to Form 8-K (file no. 001-03034) dated Dec. 13, 2005).
10.37+
Xcel Energy executive officer salaries, annual bonus targets and long-term compensation awards for 2006
10.38+
Amended Schedule of Participants for Xcel Energy Senior Executive Severance and Change-in-Control Policy
10.39*
Coal Supply Agreement (Harrington Station) between Southwestern Public Service Co. and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 - Exhibit 3).
10.40*
Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 - Exhibit 5(A)).
10.41*
Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 - Exhibit 5(B)).
10.42*
Coal Supply Agreement (Tolk Station) between Southwestern Public Service Co. and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 - Exhibit 10(b)).
10.43*
Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 - Exhibit 10(c)).
10.44*
Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and Southwestern Public Service Co.
12.01
Statement of Computation of Ratio of Earnings to Fixed Charges.
31.01
Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02
Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01
Statement pursuant to Private Securities Litigation Reform Act of 1995.
SCHEDULE II
SOUTHWESTERN PUBLIC SERVICE COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2005, 2004 and 2003
(Thousands of Dollars)
(1) Recovery of amounts previously written off.
(2) Principally uncollectible accounts written off or transferred.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
February 24,
Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
SPS has not sent, and does not expect to send, an annual report or proxy statement to its security holder.