Item 1 - Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
COMPANY OVERVIEW
ELECTRIC UTILITY OPERATIONS
Overview
Public Utility Regulation
Capacity and Demand
Energy Sources and Related Transmission Initiatives
Fuel Supply and Costs
Fuel Sources
Wholesale Commodity Marketing Operations
Summary of Recent Federal Regulatory Developments
Electric Operating Statistics
ENVIRONMENTAL MATTERS
EMPLOYEES
Item 1A
Item 1A - Risk Factors
Risks Associated with Our Business
Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies. The state utility commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service and the sale of electric energy in interstate commerce.
Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers. We currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our expenses incurred in a test year. Thus, the rates we are allowed to charge may or may not match our expenses at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers. If all of our costs are not recovered through customer rates, we could incur financial operating losses, which, over the long term, could jeopardize our ability to meet our financial obligations.
Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology. Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs.
We are subject to interest rate risk.
If interest rates increase, we may incur increased interest expense on variable interest debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.
We are subject to capital market risk.
SPS’ operations require significant capital investment in property, plant and equipment; consequently, SPS is an active participant in debt markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous events throughout the world economy. Capital market disruption events, as evidenced by the collapse in the U.S. sub-prime mortgage market and subsequent broad financial market stress, could prevent SPS from issuing new securities or cause SPS to issue securities with less than ideal terms and conditions, such as higher interest rates.
We are subject to credit risks.
Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense. Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.
Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
SPS may at times have direct credit exposure in its short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. SPS may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.
SPS does have additional indirect credit exposures to various financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts. If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long term purchased power contracts, the supplier would need to replace that security with an acceptable substitute. If the security were not replaced, the party would be in technical default under the contract, which would enable SPS to exercise its contractual rights.
We are subject to commodity risks and other risks associated with energy markets.
We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility. We utilize quoted observable market prices to the maximum extent possible in determining the value of these derivative commodity instruments. For positions for which observable market prices are not available, we utilize observable quoted market prices of similar assets or liabilities or indirectly observable prices based on forward price curves of similar markets. For positions for which we have unobservable market prices, we incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions and significant changes from our assumptions could cause significant earnings variability.
If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs. Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric services to our customers.
We are subject to environmental laws and regulations, with which compliance could be difficult and costly.
We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2008, these sites included third party sites, such as landfills, at which we are alleged to be a potentially responsible party that sent hazardous materials and wastes.
We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. These mandates are designed in part to mitigate the potential environmental impacts of utility operations. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our
results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.
In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change.
There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. SPS does not serve any coastal communities so the possibility of sea level rises does not directly affect SPS or its customers. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of the company’s service territory could also have an impact on SPS’ revenues. SPS buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers. Severe weather impacts SPS’ service territories, primarily through thunderstorms, tornadoes and snow or ice storms. We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.
To the extent climate change impacts a region’s economic health, it may also impact SPS’ revenues. SPS’ financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation, would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause SPS to receive less than ideal terms and conditions.
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Likewise, the EPA has issued an Advanced Notice of Proposed Rulemaking that proposes to regulate GHGs under the Clean Air Act. SPS’ electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years. SPS is advocating with state and federal policy makers to design climate change regulation that is effective, flexible, low-cost and consistent with our environmental leadership strategy.
Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a “cap and trade” structure, on SPS and its customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources
and the indirect impact of carbon regulation on natural gas and coal prices. An important factor is SPS’ ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on SPS. If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.
For further discussion see Note 14 to the financial statements.
Economic conditions could negatively impact our business.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the Capital Markets risk section above.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt. It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur. See credit risk section for more related information.
Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.
Our utility operations are subject to long term planning risks.
On a periodic basis, or as needed, our utility operations file long term resource plans with our regulators. These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand.
Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.
The insurance industry has also been affected by these events and the availability of insurance covering risks our competitors and we typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.
A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because our generation and transmission systems are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, or any disruption of work force such as may be caused by flu epidemic) within our operating systems or on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results.
We are subject to business continuity risks associated with our ability to respond to unforeseen events.
The term business continuity refers to the ability of the firm to maintain day-to-day operations in response to unforeseen events, such as those in the preceding section, which describes numerous disruptions to our normal operating environment. While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations. The company’s response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm’s on-going business operations.
Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results. It’s difficult to predict the magnitude of such events and associated impacts.
We are subject to information security risks.
A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information. We are unable to quantify the potential impact of such an event.
Rising energy prices could negatively impact our business.
Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric utility business is seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Act increased the FERC’s civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of $1 million per violation per day. In addition, more than 120 electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by NERC or FERC for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.
Increasing costs associated with our defined benefit retirement plans and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.
We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006, as amended, changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements and related contributions may change in the future.
Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity.
The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position, or liquidity.
As we are a subsidiary of Xcel Energy, we may be negatively affected by events at Xcel Energy and its affiliates. If Xcel Energy were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if Xcel Energy’s credit ratings and access to capital were restricted, this could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such events were to occur, we may need to seek alternative sources of funds to meet our cash needs.
As of Dec. 31, 2008, Xcel Energy had approximately $7.7 billion of long-term debt and $1.0 billion of short-term debt and current maturities. Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.
Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2008, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $67.5 million and $18.2 million of exposure. Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries. The total amount of bonds with these indemnities outstanding as of Dec. 31, 2008, was approximately $27.9 million. Xcel Energy’s total exposure under these indemnities cannot be determined at this time. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
We are a wholly owned subsidiary of Xcel Energy. Xcel Energy can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
Our board of directors, as well as many of our executive officers, are officers of Xcel Energy. Our board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.
We have historically paid quarterly dividends to Xcel Energy. In 2008, 2007 and 2006 we paid $61.8 million, $69.1 million and $78.0 million of dividends to Xcel Energy, respectively. If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs. This could adversely affect our liquidity.
Item 1B
Item 1B - 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, 2008:
SPS had 432 electric utility transmission and distribution substations at Dec. 31, 2008.
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.
Additional Information
For a discussion of legal claims and environmental proceedings, see Note 14 to the financial statements. For a discussion of proceedings involving utility rates, see Public Utility Regulation and Summary of Recent Federal Regulatory Developments under Item 1 and Note 13 to the financial statements.
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 has dividend restrictions imposed by its credit agreement, FERC rules and state regulatory commissions.
· Covenant restrictions under SPS’ credit agreement include a required 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; payment of dividends is allowed out of retained earnings only.
· State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy.
The dividends declared during 2008 and 2007 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 of SPS to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory
initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions, structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of SPS’ Form 10-K for the year ended Dec. 31, 2008.
Results of Operations
SPS’ net income was approximately $31.8 million for 2008, compared with approximately $32.9 million for 2007.
Electric Revenues and Margins
Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power. The fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.
Electric - The following tables detail the electric revenues and margin:
The following summarizes the components of the changes in electric revenues and electric margin for the year ended Dec. 31:
Electric Revenues
Electric Margin
Fuel and purchased capacity costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is subject to periodic approval by the PUCT. See Note 13 to the financial statements for further discussion.
Operating and Maintenance Expenses - Operating and maintenance expenses for 2008 increased $4.0 million, or 1.9 percent, compared to 2007. The following summarizes the components of the changes for the year ended Dec. 31:
Depreciation and Amortization - Depreciation and amortization increased by approximately $10.1 million, or 10.6 percent, for 2008 compared with 2007, primarily due to implementation of approved rates from the New Mexico rate case settlement, an increase in the amortization of DSM expenses and overall system growth.
Interest and Other Income, net - Interest and other income increased by $2.7 million, or 83.4 percent, for 2008 compared with 2007. The increase was primarily due to increased interest income collected on the Texas deferred fuel balance.
Income Taxes - Income tax expense decreased by approximately $1.7 million in 2008 compared with 2007. The decrease was primarily due to lower pretax income in 2008. The effective tax rate was 39.8 percent for 2008, compared with 40.8 percent for 2007.
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 or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. These risks, as applicable to SPS, are discussed in further detail in Note 10 to the financial statements.
Commodity Price Risk - SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in the generation and distribution activities. 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 trading activities, including the purchase and sale of electric capacity, energy and energy related instruments. These marketing activities generally have terms of less than one year in length. SPS’ risk-management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.
SPS did conduct limited commodity trading activities during 2008. However, the quantity and duration of activity had no material impact on the reported Value-at-Risk (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.
Credit Risk - SPS is also 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. The recent volatility in financial markets could increase our credit risk.
Item 8
Item 8 - Financial Statements and Supplementary Data
Management Report on Internal Controls Over Financial Reporting
The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting. SPS’ internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
SPS management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2008. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2008, the company’s internal control over financial reporting is effective based on those criteria.
This annual report does not include an attestation report of SPS’ registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SPS’ registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit SPS to provide only management’s report in this annual report.
/S/ DAVID L. EVES
/S/ BENJAMIN G.S. FOWKE III
David L. Eves
Benjamin G.S. Fowke III
President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
March 2, 2009
March 2, 2009
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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.
As discussed in Note 7 to the financial statements, the Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109,” as of January 1, 2007.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 2, 2009
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME (amounts in thousands of dollars)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS
(amounts in thousands of dollars)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS (amounts in thousands of dollars)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME
(amounts in thousands of dollars, except share data)
See Notes to Financial Statements
SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CAPITALIZATION
(amounts in 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 generation, purchase, transmission, distribution and sale of electricity. SPS is subject to 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.
Revenue Recognition - Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. SPS presents its revenue net of any excise or other fiduciary-type taxes or fees.
SPS has various rate-adjustment mechanisms in place that currently provide for the recovery of purchased natural gas and electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates, and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred. Where applicable under governing state regulatory commission rate orders, fuel costs over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. A summary of significant rate-adjustment mechanisms follows:
· In Texas, SPS recovers fuel and purchased energy costs through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. The Texas retail fuel factors change each November and May based on the projected costs of natural gas. 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. Certain of 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 Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133). In addition, commodity trading results include the impact of all margin-sharing mechanisms. For more information, see Note 10 to the financial statements.
Fair Value Measurements - SPS presents cash equivalents and interest rate derivatives at estimated fair values in its financial statements. Cash equivalents are recorded at cost plus accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents, including commercial paper and money market funds, are also monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost. For interest rate derivatives, quoted prices based primarily on observable market price curves are used as a primary input to establish fair value.
Types of and Accounting for Derivative Instruments - SPS uses 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 designated and qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133 are recorded on the balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation.
Gains or losses on hedging transactions for the 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.
Cash Flow Hedges - Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The designation of a cash flow hedge permits changes in fair value to be recorded within other comprehensive income (OCI), to the extent the hedge is effective, or deferred as a regulatory asset or liability.
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 all hedging relationships in accordance with SFAS No. 133. The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedging transaction. In addition, at inception and on a quarterly basis, SPS formally assesses whether the derivative instruments being used are highly effective in offsetting changes in the cash flows of the hedged items.
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability until earnings are affected by the hedged transaction. SPS discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. To test the effectiveness of hedges, a hypothetical hedge is used to mirror all the critical terms of the hedged transaction and the dollar-offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis. Gains and losses related to discontinued hedges that were previously deferred in OCI or deferred as regulatory assets or liabilities will remain deferred until the hedged transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, in which case associated deferred amounts are immediately recognized in current earnings.
Normal Purchases and Normal Sales - SPS enters into contracts for the purchase and sale of commodities for use in their business operations. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales.
SPS evaluates all of its contracts at inception to determine if they are derivatives and, if so, if they qualify to meet the normal purchases and normal sales designation requirements under SFAS No. 133. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.
For further discussion of SPS’ risk management and derivative activities, see Note 10 to the financial statements.
Property, Plant and Equipment and Depreciation - Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Regulatory obligations to incur removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repair and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use.
SPS records depreciation expense related to its plant by using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2008, 2007 and 2006 was 2.8 percent, 2.6 percent and 2.8 percent, respectively.
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 nonoperating 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 on an undiscounted basis when it is probable SPS is liable for the costs and the liability can reasonably be 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 SPS’ expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.
Legal Costs - Litigation accruals are recorded when it is probable SPS is liable for the costs and the liability can be reasonably estimated. External legal fees related to settlements are expensed as incurred.
Income Taxes - SPS accounts for income taxes using the asset and liability method under FAS 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. SPS defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. SPS uses the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.
Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 15 to the financial statements. For more information on income taxes, see Note 7 to the financial statements.
In July 2006, the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax positions that such company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, SPS adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which was reported as an adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.
SPS reports interest and penalties related to income taxes within the interest charges section in the statements of income.
Xcel Energy and its subsidiaries, including SPS, file consolidated federal income tax returns and combined and separate state income tax returns. Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state filings. The holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company.
Use of Estimates - In recording transactions and balances resulting from business operations, SPS uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, AROs, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.
Cash and Cash Equivalents - SPS considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.
Inventory - All inventory is 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 (SFAS No. 71). 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 15 to the financial statements.
Deferred Financing Costs - Other assets include deferred financing costs, net of amortization, of approximately $7.6 million and $6.4 million at Dec. 31, 2008 and 2007, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.
Debt premiums, discounts, expenses and amounts received or paid to settle hedges are amortized over the life of the related debt. The premiums and costs associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. If SPS extinguishes the debt, all unamortized balances shall be expensed at the time of the redemption.
Accounts Receivable and Allowance for Bad Debts - Accounts receivable are stated at the actual billed amount net of write-offs and an allowance for bad debts. SPS establishes an allowance for uncollectible receivables based on a reserve policy that reflects its expected exposure to the credit risk of customers.
Renewable Energy Credits (RECs) - RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPSs enacted by those states that are encouraging construction and consumption of renewable energy, but can also be sold separately from the energy produced. Currently, SPS acquires RECs from the generation or purchase of renewable power.
When RECs are acquired in the course of generation or purchase as a result of meeting the load obligation, they are recorded as inventory at actual cost. RECs acquired for trading purposes are recorded as other investments at actual cost. The cost of RECs that are retired for compliance purposes are recorded as electric fuel and purchased power expense. The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues net of any margin sharing requirements. As a result of state regulatory orders, we reduce recoverable fuel costs for the value of certain RECs and record the cost of RECs to satisfy future compliance requirements that are recoverable in future rates as regulatory assets under the criteria of SFAS No. 71.
Emission Allowances - Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA. SPS follows the inventory accounting model for all allowances. The sales of allowances are reported in the operating activities section of the statements of cash flows. The net margin on sales of emission allowances is included in electric utility operating revenues as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.
Reclassification - Activity from the allowance for bad debts was reclassified from the change in accounts receivable on the statements of cash flows. The reclassification did not have an impact on net cash provided by operating activities.
2. Accounting Pronouncements
Recently Issued
Business Combinations (SFAS No. 141 (revised 2007)) - In December 2007, the FASB issued SFAS No. 141R, which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. SPS will apply SFAS No. 141R to business combinations occurring subsequent to Jan. 1, 2009.
Disclosures about Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133 (SFAS No. 161) - In March 2008, the FASB issued SFAS No. 161, which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, to require disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008, with early application encouraged. SPS does not expect the implementation of SFAS No. 161 to have a material impact on its financial statements.
Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) - In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to expand an employer’s required disclosures about plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk. FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009. SPS does not expect the implementation of FSP FAS 132(R)-1 to have a material impact on its financial statements.
Recently Adopted
Fair Value Measurements (SFAS No. 157) - In September 2006, the FASB issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.
On Jan. 1, 2008, SPS adopted SFAS No. 157 for all assets and liabilities measured at fair value except for non-financial assets and non-financial liabilities measured at fair value on a non-recurring basis, as permitted by FSP FAS 157-2, Effective Date of FASB Statement No. 157. The adoption did not have a material impact on SPS’ financial statements. For additional discussion and SFAS No. 157 required disclosures, see Note 12 to the financial statements.
The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (SFAS No. 159) - In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement was effective for fiscal years beginning after Nov. 15, 2007. SPS adopted SFAS No. 159 on Jan. 1, 2008, and the adoption did not have a material impact on its financial statements.
Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active (FSP FAS 157-3) - In October 2008, the FASB issued FSP FAS 157-3, which clarifies the application of SFAS No. 157 in a market that is not active. FSP FAS 157-3 was effective immediately upon issuance, and applied to prior periods for which financial statements had not yet been issued. SPS adopted FSP FAS 157-3 as of Sept. 30, 2008, and the adoption did not have a material impact on its financial statements.
Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance
Arrangements (Emerging Issues Task Force (EITF) Issue No. 06-4) - In June 2006, the EITF reached a consensus on EITF No. 06-4, which provides guidance on the recognition of a liability and related compensation costs for endorsement split-dollar life insurance policies that provide a benefit to an employee that extends to postretirement periods. Therefore, this EITF would not apply to a split-dollar life insurance arrangement that provides a specified benefit to an employee that is limited to the employee’s active service period with an employer. EITF No. 06-4 was effective for fiscal years beginning after Dec. 15, 2007, with earlier application permitted. Upon adoption of EITF No. 06-4 on Jan. 1, 2008, SPS recorded a liability of $0.3 million, net of tax, as a reduction of retained earnings. Thereafter, changes in the liability are reflected in operating results.
Amendment of FASB Interpretation No. 39 (FSP FIN 39-1) - In April 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, Offsetting of Amounts Related to Certain Contracts, to permit companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. FSP FIN 39-1 was effective for fiscal years beginning after Nov. 15, 2007. SPS adopted FSP FIN 39-1 on Jan. 1, 2008, and the adoption did not have a material impact on its financial statements.
Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11) - In June 2007, the EITF reached a consensus on EITF No. 06-11, which states that an entity should recognize a realized tax benefit associated with dividends on nonvested equity shares and nonvested equity share units charged to retained earnings as an increase in additional paid in capital. The amount recognized in additional paid in capital should be included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards. EITF No. 06-11 was to be applied prospectively to income tax benefits of dividends on equity-classified share-based payment awards that were declared in fiscal years beginning after Dec. 15, 2007. SPS adopted EITF No. 06-11 on Jan. 1, 2008, and the adoption did not have a material impact on its financial statements.
The Hierarchy of GAAP (SFAS No. 162) - In May 2008, the FASB issued SFAS No. 162, which establishes the GAAP hierarchy, identifying the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements. SFAS No. 162 was effective Nov. 15, 2008. SPS adopted SFAS No. 162 on Dec. 31, 2008, and the adoption did not have a material impact on its financial statements.
Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities (FSP FAS 140-4 and FIN 46(R)-8) - In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, which amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to require public entities to provide additional disclosures about transfers of financial assets. It also amends FIN 46 (revised December 2003), Consolidation of Variable Interest Entities, to require public enterprises, including sponsors that have a variable interest in a variable interest entity, to provide additional disclosures about their involvement with variable interest entities. FSP FAS 140-4 and FIN 46(R)-8 was effective for the interim and annual periods ending after Dec. 15, 2008. SPS adopted FSP FAS 140-4 and FIN 46(R)-8 on Dec. 31, 2008, and the adoption did not have a material impact on its financial statements.
3. Selected Balance Sheet Data
4. Short-Term Borrowings
Commercial Paper - At Dec. 31, 2007, SPS had commercial paper outstanding of $123.0 million with a weighted average interest rate of 5.58 percent. SPS had no commercial paper outstanding at Dec. 31, 2008. SPS has board approval to issue up to $250 million of commercial paper.
Money Pool - Xcel Energy and its utility subsidiaries have established a utility money pool arrangement that 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. At Dec. 31, 2008 and 2007, SPS had money pool loans outstanding of $90.5 million and money pool borrowings of $5.5 million, respectively. The weighted average interest rates at Dec. 31, 2008 and 2007, were 3.50 percent and 5.64 percent, respectively.
5. Long-Term Debt
Credit Facilities - At Dec. 31, 2008, SPS had the following committed credit facility in effect, 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 was in compliance at Dec. 31, 2008 and 2007. If SPS does not comply with the covenant, it is deemed an event of default and any outstanding amounts due under the facility can be declared due by the lender.
· The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as based on SPS’ senior unsecured credit ratings from Moody, Standard & Poor and Fitch. The commitment fees are calculated for the unused portion of the credit facility at 8 basis points for SPS.
· At Dec. 31, 2008, SPS had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $11.6 million of letters of credit.
· At Dec. 31, 2007, SPS had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $123.0 million of commercial paper outstanding and $7.0 million of letters of credit.
Certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.
On Nov. 14, 2008, SPS issued $250 million of 8.75 percent senior notes, series due 2018. The senior notes are redeemable by SPS upon 30 days notice with payment of a make-whole premium. The proceeds from this offering were used to repay short-term debt.
Maturities of long-term debt are:
6. Preferred Stock
SPS has authorized the issuance of preferred stock.
7. Income Taxes
Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48) - SPS is a member of the Xcel Energy affiliated group that files consolidated income tax returns. In the first quarter of 2008, the IRS completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those tax years. Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009. In the third quarter of 2008, the IRS commenced an examination of tax years 2006 and 2007. As of Dec. 31, 2008, the IRS had not proposed any material adjustments to tax years 2006 and 2007.
In the first quarter of 2008, the state of Texas concluded an income tax audit through tax year 2005. No material adjustments were proposed for this audit. As of Dec. 31, 2008, SPS’ earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.
The amount of unrecognized tax benefits was $2.3 million and $3.5 million on Dec. 31, 2007 and 2008, respectively. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
These unrecognized tax benefit amounts were reduced by the tax benefits associated with tax credit carryovers of $0.1 million and $0.1 million as of Dec. 31, 2007 and 2008, respectively.
The unrecognized tax benefit balance included $0.3 million and $0.3 million of tax positions on Dec. 31, 2007 and 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $2.0 million and $3.2 million of tax positions on Dec. 31, 2007 and 2008, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
The increase in the unrecognized tax benefit balance of $1.2 million from Dec. 31, 2007 to Dec. 31, 2008, was due to the addition of similar uncertain tax positions related to ongoing activity. SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and when state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.
The liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with tax credit carryovers. The amount of interest income related to unrecognized tax benefits reported within interest charges in 2007 was $0.5 million. The amount of interest expense related to unrecognized tax benefits reported within interest charges in 2008 was $0.2 million. The liability for interest related to unrecognized tax benefits was $0.1 and $0.3 million on Dec. 31, 2007 and 2008, respectively. No amounts were accrued for penalties as of Dec. 31, 2007 and 2008.
Other Income Tax Matters - SPS’ federal net operating loss carryforward is estimated to be $5.0 million and $4.7 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. SPS’ federal tax credit carryforward is estimated to be $0.6 million and $0.6 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. The carryforward periods expire between 2021 and 2028. SPS also has state net operating loss carryforwards of $5.4 million and $6.1 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively. The state carryforward periods expire between 2009 and 2022. SPS has a valuation allowance for its state net operating loss carryforwards of $1.0 million as of Dec. 31, 2008.
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:
The components of income tax expense for the years ending Dec. 31 were:
The components of deferred income tax at Dec. 31 were:
The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:
8. Benefit Plans and Other Postretirement Benefits
Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to SPS.
Xcel Energy offers various benefit plans to its employees, including those of SPS. Approximately 50 percent of Xcel Energy employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2008, SPS had 804 bargaining employees covered under a collective-bargaining agreement, which expires in October 2011.
Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R) (SFAS No. 158) - In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income. SPS applied regulatory accounting treatment for unrecognized amounts of regulated utility subsidiary employees, which allowed recognition as a regulatory asset or liability rather than as a charge to accumulated other comprehensive income, as future costs are expected to be included in rates. The effect of adopting in 2006 for the remaining unrecognized amounts had no net effect on accumulated other comprehensive income.
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. The target range for our pension asset allocation is 52 percent in equity investments, 25 percent in fixed income investments and 23 percent in nontraditional investments, such as real estate, 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 9.56 percent, which is greater than the current assumption level. The pension cost determination assumes 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. A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year. Investment returns in 2008 and 2007 were below the assumed level of 8.75 percent while returns in 2006 exceeded the assumed level of 8.75 percent. Xcel Energy continually reviews its pension assumptions. In 2009, Xcel Energy will use an investment-return assumption of 8.50 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:
At Dec. 31, 2008, one of Xcel Energy’s pension plans had plan assets of $259.9 million, which exceeded projected benefit obligations of $244.3 million. At Dec. 31, 2007, the plan assets of $369.8 million exceeded projected benefit obligations of $253.6 million. All other Xcel Energy plans in the aggregate had plan assets of $1.9 billion and $2.8 billion and projected benefit obligations of $2.4 billion and $2.4 billion on Dec. 31, 2008 and 2007.
Cash Flows - Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2006 through 2008 for Xcel Energy’s pension plans and are not expected to require cash funding in 2009.
· Voluntary contributions were made to the PSCo Bargaining Pension Plan of $35 million in 2008, $35 million in 2007 and $30 million in 2006.
· Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $2 million in 2006. No voluntary contributions were made to the plan during 2007 or 2008.
· Xcel Energy projects cash funding of $70 million to $130 million in 2009. Pension funding contributions for 2010, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $150 million to $250 million.
Plan Changes - The Pension Protection Act of 2006 (PPA) was effective Dec. 31, 2006. PPA requires a change in the conversion basis for lump-sum payments and three-year vesting for plans with account balance or pension equity benefits. These changes are reflected as a plan amendment for purposes of SFAS No. 87, Employers’ Accounting for Pensions.
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 2009 pension cost calculations will be 8.50 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.
Xcel Energy 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 $1.2 million in 2008, $1.5 million in 2007 and $1.1 million in 2006.
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 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. 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, 2008, Xcel Energy reduced its initial medical trend assumption from 8.0 percent to 7.4 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is five 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:
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 contributed $55.6 million during 2008 and expects to contribute approximately $63.1 million during 2009.
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.
9. Detail of Interest and Other Income (Expense), Net
Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 consisted of the following:
10. Derivative Instruments
In the normal course of business, SPS is exposed to a variety of market risks. Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity. SPS utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations.
Commodity Price Risk - SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products for various fuels used for generation of electricity. 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 trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk-management policy allows management to conduct these activities within guidelines and limitations as approved by the 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, subject to regulatory approval when required.
Types of and Accounting for Derivative Instruments
SPS uses 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 designated and qualifying for the normal purchases and normal sales exception, as defined by FAS No. 133, are recorded to the balance sheets as derivative instruments valuation.
Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow. The types of qualifying hedging transactions that SPS is currently engaged in are discussed below.
Cash Flow Hedges
Interest Rate Cash Flow Hedges - SPS enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.
At Dec. 31, 2008, SPS had $0.6 million of net losses in accumulated other comprehensive income related to interest rate hedges that are expected to be recognized in earnings during the next 12 months.
SPS had no ineffectiveness related to interest rate cash flow hedges during 2008 and 2007.
The following table shows the major components of the derivative instruments valuation in the balance sheets at Dec. 31:
In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, SPS began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During the first quarter of 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Financial Impact of Qualifying Cash Flow Hedges - The impact of qualifying cash flow hedges on SPS’ accumulated other comprehensive income, included in the statements of common stockholder’s equity and comprehensive income, is detailed in the following table:
11. 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. The fair value 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, 2008 and 2007. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date and current estimates of fair value 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, 2008 and 2007, there were $11.6 million and $7.0 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.
12. Fair Value Measurements
Effective Jan. 1, 2008, SPS adopted SFAS No. 157 for recurring fair value measurements. SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
Level 2 - Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.
Level 3 - Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation.
SPS had one investment in a money market fund included in cash equivalents and measured at fair value on a recurring basis as of Dec. 31, 2008. Money market funds are recorded at cost plus estimated accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of money market funds are also monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost. Given the observability of the primary inputs to pricing, the $50.0 million investment in a money market fund at Dec. 31, 2008 was assigned a Level 2 under the SFAS No. 157 hierarchy.
SPS had one interest rate derivative contract measured at fair value on a recurring basis as of Dec. 31, 2008. SPS uses quoted prices, based primarily on observable benchmark interest rate forecasts, to measure the fair value of interest rate derivatives. Given the observability of the primary inputs to pricing, the interest rate derivative liability of $8.5 million at Dec. 31, 2008, was assigned a Level 2 under the SFAS No. 157 hierarchy.
13. Rate Matters
Pending and Recently Concluded Regulatory Proceedings - PUCT
Base Rate
Texas Retail Base Rate Case - On June 12, 2008, SPS filed a rate case with the PUCT seeking an annual rate increase of approximately $61.3 million, or approximately 5.9 percent. Base revenues are proposed to increase by $94.4 million, while fuel and purchased power revenue would decline by $33.1 million, primarily due to fuel savings from the LPP purchase power agreement.
The rate filing is based on a 2007 test-year adjusted for known and measurable changes, a requested ROE of 11.25 percent, an electric rate base of $989.4 million and an equity ratio of 51.0 percent. Interim rates of $18 million for costs associated with the LPP power purchase agreement went into effect in September 2008.
On Jan. 30, 2009, SPS filed an agreed upon motion to begin collecting interim rates of $57.4 million effective Feb. 1, 2009 for consumption occurring on or after that date. The ALJs issued an order authorizing this interim rate increase, which supersedes the $18 million interim rate increase that became effective in September 2008. On Feb. 20, 2009, the parties filed a unanimous settlement with the ALJs. The settlement:
· Provides for a base rate increase of $57.4 million;
· Approves depreciation rates that reduced depreciation expense by $5.6 million from currently authorized rates;
· Includes a mechanism for tracking and deferral of $2.6 million in renewable energy credit expenses until its next rate case;
· Provides that $3.2 million of annual energy efficiency expenses that SPS had requested through a rider be recovered through base rates (the parties agreed to litigate whether there should be a mechanism to address recovery of actual energy efficiency expenses to the extent that they are different than the amount included in the settlement rates);
· Allows SPS to implement the transmission cost recovery factor in 2009;
· Precludes SPS from filing to seek any other change in base rates until Feb. 15, 2010; and
· Resolves all fuel reconciliation issues for 2006-07 with one adjustment for $0.6 million related to the sharing of certain wholesale sales revenues.
The case and settlement will be remanded to the PUCT with action on the settlement expected later this spring.
John Deere Wind Complaint - In June 2007, several John Deere Wind Energy subsidiaries (JD Wind) filed a complaint against SPS disputing SPS’ payments to JD Wind for energy produced from the JD Wind projects. SPS responded that the payments to JD Wind for energy produced from its QF is appropriate and in accordance with SPS’ filed tariffs with the PUCT. The PUCT referred the complaint to the State Office of Administrative Hearings. On Aug. 14, 2008, JD Wind filed testimony claiming SPS has been underpaying JD Wind for its energy. Testimony has been filed and hearings were held. The ALJ will then recommend to the PUCT on how the dispute should be ruled. There is no deadline for the PUCT to take action.
Electric and Resource Adjustment Clauses
TCR Factor Rulemaking - In November 2007, the PUCT adopted new rules relating to TCR factor outside of a base rate case. The rule establishes the mechanism by which SPS can request annual recovery of its reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges that are not included in existing rates. This new rule allows SPS more timely recovery of transmission cost increases between base rate cases.
Pending and Recently Concluded Regulatory Proceedings - NMPRC
Base Rate
2007 New Mexico Retail Electric Rate Case - In July 2007, SPS filed with the NMPRC requesting a New Mexico retail electric general rate increase of $17.3 million annually, or 6.6 percent. The rate filing was based on a 2006 test year adjusted for known and measurable changes and included a requested ROE of 11.0 percent, an electric rate base of approximately $307.3 million and an equity ratio of 51.2 percent.
In August 2008, the NMPRC issued its final order authorizing an overall rate increase of $10.8 million based on a 10.18 percent ROE. This increase is based on a $7 million electric base rate increase and a rider to recover $3.8 million of restructuring costs. The NMPRC disallowed $3.5 million in rate base for historical DSM expenditures and certain rate case and prepaid pension expenses. SPS implemented the base rates on Sept. 14, 2008.
2008 New Mexico Retail Electric Rate Case - On Dec. 18, 2008, SPS filed with the NMPRC a request to increase electric rates in New Mexico by approximately $24.6 million, or 5.1 percent. The request is based on a historic test year (split year based on year-ending June 30, 2008), an electric rate base of $321 million, and an equity ratio of 50 percent and a requested ROE of 12 percent. SPS also requested interim rates to allow it to begin recovering the cost of the LPP facility of approximately $7.6 million per year. The NMPRC has suspended the proposed rate request until Oct. 17, 2009 and has set the interim rate request for hearing on March 19, 2009. The NMPRC has assigned the main part of the case to a hearing examiner and has set a mandatory mediation with a settlement judge for March 12, 2009. The following procedural schedule has been established:
· Staff and intervenor direct testimony on May 8, 2009;
· SPS rebuttal testimony on May 29, 2009; and
· the hearing on the merits is expected to begin on June 8, 2009.
On Jan. 12, 2009, the NMPRC staff and the attorney general (AG) requested that the NMPRC suspend SPS’ advice notice and deny the request for interim relief. The staff stated that the standard for interim relief requires clear and convincing evidence of a financial emergency, which SPS has failed to provide and stated that the proposal entails piecemeal and retroactive ratemaking. The AG stated that SPS’ testimony does not rise to the level required for the NMPRC to grant interim relief.
Electric and Resource Adjustment Clauses
New Mexico Fuel Factor Continuation Filing - In August 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) and current monthly factor cost recovery methodology. This filing was required by NMPRC rule.
Testimony was filed in the case by staff and intervenors objecting to SPS’ assignment of system average fuel costs to certain wholesale sales and the inclusion of certain purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on SPS’ future use of the FPPCAC. Related to these issues, some intervenors requested disallowances for past periods, which in the aggregate total approximately $45 million. This claim was for the period from Oct. 1, 2001
through May 31, 2005 and does not include the value of incremental cost assigned for wholesale transactions from that date forward. Other issues in the case include the treatment of renewable energy certificates and SO2 allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause.
In December 2007, SPS, the NMPRC, Occidental Permian Ltd. and the New Mexico Industrial Energy Consumers filed an uncontested settlement of this matter with the NMPRC.
· The settlement resolves all issues in the fuel continuation proceeding for total consideration of $15 million, which includes customer refunds of $11.7 million.
· At Dec. 31, 2007, a reserve had been previously established for this potential exposure, with no further expense accrual required.
· The settlement would also provide for significantly greater certainty surrounding system average fuel cost assignment on a going forward basis and reduce percentages of system average cost wholesale sales between now and 2019 on a stepped down basis.
· Under the terms of the settlement, SPS anticipates additional fuel cost disallowances in 2008 and a portion of 2009 of approximately $2 million per year. It does not anticipate any future disallowances beyond this period.
· Finally, the settlement provides for SPS to continue its use of the FPPCAC subject to additional reporting provisions.
On Aug. 26, 2008, the NMPRC issued a final order approving the unanimous stipulation.
Investigation of SPS Participation in SPP - In October 2007, the NMPRC issued an order initiating an investigation to consider the prudence and reasonableness of SPS’ participation in the SPP RTO. The investigation will consider the costs and benefits of RTO participation to SPS customers in New Mexico. SPS filed its direct testimony on July 31, 2008.
Pending and Recently Concluded Regulatory Proceedings - FERC
Wholesale Rate Complaints - In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the Complaint). Among other things, the complainants asserted that SPS had inappropriately allocated average fuel and purchased power costs to other wholesale customers, effectively raising the fuel cost charges to complainants. Cap Rock Energy Corporation (Cap Rock), another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS’ largest retail customer, intervened in the proceeding.
In May 2006, a FERC ALJ issued an initial decision in the proceeding. The ALJ found that SPS should recalculate its FCAC billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the complaining customers by deducting from such costs the incremental fuel costs attributed to SPS’ sales of system firm capacity and associated energy to other wholesale customers served under market-based rates during this period based on the view that such sales should be treated as opportunity sales made out of temporarily excess capacity. In addition, the ALJ made recommendations on a number of base rate issues including a 9.64 percent ROE and the use of a 3-month coincident peak (3CP) demand allocator.
Golden Spread Complaint Settlement - In December 2007, SPS reached a settlement with Golden Spread (which now includes Lyntegar Electric) and Occidental regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding. In December 2007, this comprehensive offer of settlement (the Settlement) was filed with the FERC. On April 21, 2008, the FERC approved the Settlement with a minor modification to the formula rate proposed by the FERC and accepted by the parties. The Settlement provides for:
· A $1.25 million payment by SPS to Golden Spread related to resolve a dispute concerning the quantities Golden Spread was entitled to take under its existing partial requirements agreement for the years 2006 and 2007. The Settlement caps those quantities for the period 2008 through 2011. SPS is not required to make any fuel refunds to Golden Spread that were the subject of the Complaint under the terms of the Settlement.
· An extended partial requirements contract at system average cost, with a capacity amount that ramps down over the period 2012 through 2019 from 500 MW to 200 MW. Golden Spread agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed sale and SPS agreed to contingent payments ranging from $3 million to a maximum of $12 million, payable in 2012, in the event that there is an adverse cost assignment decision or a failure to obtain state approvals.
· Resolution of base rates in the Complaint without any adjustment to the existing rates for the period January 2005 through June 30, 2006. The Settlement also resolves all base rate issues in SPS’ subsequent proceeding related to the period July 1, 2006 through Sept. 30, 2008, other than the method to be used to allocate demand related costs and provided for two sets of agreed-on rates that are dependent on the ultimate resolution of that issue.
· For July 1, 2008 and beyond, Golden Spread will be under a formula rate for power supply service. The rate will be based on actual data the most recent historic year adjusted for known and measurable changes and trued up to the actual performance in the subsequent calendar year.
Order on Wholesale Rate Complaints - In April 2008, the FERC issued its Order on the Complaint applied to the remaining non-settling parties. The Order addresses base rate issues for the period from Jan. 1, 2005 through June 30, 2006, for SPS’ full requirements customers who pay traditional cost-based rates and requires certain refunds.
· Base Rates: The FERC determined: (1) the ROE should be 9.33 percent; (2) rates should be based on a 12 CP allocator; and (3) the treatment of market based rate contracts in the test year should be to credit revenues to the cost of service rather than allocating costs to the agreements. The revenue requirement established by the FERC results in proposed revenues that are estimated to be approximately $25 million, or approximately $6.9 million below the level charged these customers during this 18-month period. Rates for full requirements customers, the New Mexico Cooperatives and Cap Rock, as well as an interruptible contract with PNM for the period beginning July 1, 2006, are the subject of settlements that have either been approved or are pending before the FERC. These settlements are described in Wholesale 2005 Power Base Rate Application below.
· Fuel Clause: The FERC determined that the method for calculating fuel and purchased energy cost charges to the complaining customer is to deduct from such costs incremental fuel and purchased energy costs, which it is attributing to SPS’ market based intersystem sales on the basis that these are “opportunity” sales under its precedent. The FERC ordered that refunds of fuel cost charges based on this method of determining the FCAC should begin as of Jan. 1, 2005 (the refund effective date in the case). The FERC ordered SPS to file a compliance filing calculating its refund obligation and implement the instructions in the order in calculating its FCAC charges going forward from that date. While the order is subject to interpretation with respect to aspects of the calculation of the refund obligation, SPS does not expect its refund obligation to its full requirements customers from Jan. 1, 2005 through March 31, 2008, to exceed $11 million. PNM has filed a separate complaint that any refund obligation to PNM will be determined in that docket. SPS is reviewing the Order and has not yet determined whether to seek rehearing.
· The FERC also ruled on two other FCA issues. First, it required that wind contracts be evaluated on an individual contract basis rather than in aggregate. Second, the FERC determined that an after-the-fact screen should be applied to all QF purchases to determine if they are economic. While this review will require additional effort, it is not expected that this will result in additional refunds as all of the individual wind contracts as well as the QF purchases are typically economic when compared to market energy prices.
Several parties, including SPS, filed requests for rehearing on the order. These requests are pending before the FERC. In July 2008, SPS submitted its compliance report to the FERC. In the report, SPS has calculated the base rate refund for the 18-month period to be equal to $6.1 million and the fuel refund to be equal to $4.4 million. Several wholesale customers have protested the calculations. Once the final refund amounts are approved by the FERC, interest will be added to the refund due the full requirements customers. As of Dec. 31, 2008, SPS has accrued an amount sufficient to cover the estimated refund obligation.
Wholesale 2005 Power Base Rate Application - In December 2005, SPS filed for a $2.5 million increase in wholesale power rates to certain electric cooperatives. In January 2006, the FERC conditionally accepted the proposed rates for filing and the $2.5 million power rate increase became effective on July 1, 2006, subject to refund. In September 2006, offers of settlement with respect to the five full-requirements customers and with respect to PNM were filed for approval. In September 2007, the FERC accepted the settlement with the full-requirements customers. In September 2008, the FERC issued an order accepting the contested partial settlement with PNM.
SPS Formula Transmission Rate Case - In December 2007, Xcel Energy submitted an application to implement a transmission formula rate for the SPS zone of the Xcel Energy Open Access Transmission Tariff (OATT). The changed rates will affect all wholesale transmission service customers using the SPS transmission network under either the SPP Regional OATT or the Xcel Energy OATT.
The proposed rates would be updated annually each July 1 based on SPS’ prior year actual costs and loads plus the revenue requirements associated with projected current year transmission plant additions. The proposed ROE is 12.7 percent,
including a 50 basis point adder for SPS’ participation in the SPP RTO. The proposed rates would provide first year incremental annual transmission revenue for SPS of approximately $5.5 million.
In February 2008, the FERC accepted the proposed rates, suspending the effective date to July 6, 2008, and setting the rate filing for hearings and settlement procedures. The FERC granted a 50 basis point adder to the ROE that it will determine in this proceeding as a result of SPS’ participation in the SPP RTO. The filed rates, updated for 2007 actual costs and projected 2008 transmission plant additions, were placed into effect on July 6, 2008, subject to refund. The SPS and SPP rate filings are now in settlement procedures. The ultimate outcome of the rate filings is not known at this time.
SPS 2008 Wholesale Rate Case - On March 31, 2008, SPS filed a wholesale rate case seeking an annual revenue increase of $14.9 million or an overall 5.14 percent increase, based on 12.20 percent requested ROE. On April 21, 2008, a motion for dismissal and protest was filed by the four eastern New Mexico cooperatives.
In SPS’ answer to the motions to intervene and protest, SPS renewed its request for a nominal suspension of 60 days and asked the FERC to consider such a nominal suspension in exchange for SPS’ acceptance of two conditions. The first condition was that SPS would agree to a ROE of no more than 10.25 percent and second, SPS would agree to use a 12 CP demand allocator for the period the rates will be in effect. The SPS answer would result in an annual revenue increase of $9.9 million or an overall 3.4 percent increase.
On May 30, 2008, the FERC conditionally accepted and suspended the rates and established hearing and settlement procedures. The FERC granted a one-day suspension of rates instead of 180 days. The LPP plant achieved commercial operations in September 2008 and the proposed base rates, based on a 10.25 percent ROE and a 12-CP demand allocator, became effective, subject to refund. A pre-hearing conference was held Jan. 29, 2009, where a procedural schedule for the hearing was established and a preliminary joint list of issues was discussed.
14. Commitments and Contingent Liabilities
Capital Commitments - As of Dec. 31, 2008, the estimated cost of the capital expenditure programs and other capital requirements of SPS is approximately $210 million in 2009, $245 million in 2010 and $205 million in 2011.
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’ long-term energy needs. In addition, SPS’ 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 2009 and 2033. SPS may be required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs.
The estimated minimum purchase for SPS under these contracts as of Dec. 31, 2008, 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 indices. However, the effects of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.
At Dec. 31, 2008, the estimated future payments for capacity, accounted for as executory contracts, that SPS was obligated to purchase, subject to availability, were as follows:
Variable Interest Entities (VIE) - SPS has certain long-term power purchase agreements with independent power producing entities that contain tolling arrangements under which Xcel Energy procures the fuel required to produce the energy purchased. Xcel Energy enters into these agreements to meet electric system capacity and energy needs. Xcel Energy is not subject to risk of loss from the operations of these potential VIEs. Xcel Energy has evaluated such entities for possible consolidation under FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) and has concluded that these entities are not required to be consolidated in Xcel Energy’s consolidated financial statements. The significant qualitative factors considered evaluating purchase power agreements under FIN 46R include length and terms of the contract and operational, fuel price and financing risk. When necessary, a quantitative analysis demonstrated that Xcel Energy would absorb less than 50 percent of the expected gains or losses. Significant assumptions used in the quantitative analysis by Xcel Energy, to determine the primary beneficiary, include an inflation rate equal to the Bureau of Labor Statistics 10 year average, estimated future fuel and electricity prices, future operating cash flows, an incremental borrowing rate, the expected life of the plant, and a debt to equity financing ratio.
Leases - SPS leases a variety of equipment and facilities used in the normal course of business, which are accounted for as operating leases. Total rental expense under operating lease obligations was approximately $18.6 million, $4.3 million and $4.2 million for 2008, 2007 and 2006, respectively. Included in total rental expense were purchase power agreement payments of $14.2 million in 2008.
Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with Emerging Issues Task Force 01-8, Determining whether an Arrangement Contains a Lease and SFAS No. 13, Accounting for Leases. Future commitments under operating leases are:
(a) Amounts not included in purchase power agreement estimated future payments above.
(b) Purchase power agreement operating leases contractually expire through 2033.
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 believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, SPS is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) 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.
Site Remediation - SPS must pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including third party sites, to which SPS is alleged to be a PRP that sent hazardous materials and wastes. At Dec. 31, 2008, the liability for the cost of remediating these sites was estimated to be $0.1 million.
Third Party and Other Environmental Site Remediation
Asbestos Removal - Some of SPS’ 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 below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.
Other Environmental Requirements
CAIR - In March 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The objective of CAIR was to cap emissions of SO2 and NOx in the eastern United States, including Texas. In July 2008, the U. S. Court of Appeals for the District of Columbia vacated CAIR and remanded the rule to EPA. On Dec. 23, 2008, the court reinstated CAIR while the EPA develops new regulations in accordance with the court’s July opinion.
As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.
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. The remaining capital investments for NOx controls in the SPS region are estimated at $4.5 million. For 2009, the estimated NOx allowance compliance costs are $2.5 million. Annual purchases of SO2 allowances are estimated in the range of $3 million to $17 million each year, beginning in 2013, for phase I, based on expected allowance costs and fuel quality at the end of 2008.
CAMR - In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. The TCEQ has adopted by reference the EPA model program. In February 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements but not necessarily state-only rules. At this time, Texas has not adopted any state-only mercury requirements.
Regional Haze Rules - In June 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze. Some of SPS’ generating facilities will be subject to BART requirements. Some of these facilities are located in regions where CAIR is effective. The TCEQ had determined that facilities may use CAIR as a substitute for BART for NOx and SO2.
Maddox Station Groundwater - The New Mexico Environment Department is requiring wastewater activity at Maddox Station to be permitted. SPS is developing the engineering wastewater management facilities and submitted the permit application in July 2008. The estimated cost of the project is $1.8 million with an anticipated completion date in June 2009.
Asset Retirement Obligations
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 in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations, (SFAS No. 143). 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.
Recorded ARO - AROs have been recorded for steam production and electric transmission and distribution. 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. AROs 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 polychlorinated biphenyls (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 using an average service life.
A reconciliation of the beginning and ending aggregate carrying amounts of SPS’ AROs is shown in the table below for the 12 months ended Dec. 31, 2008 and Dec. 31, 2007, respectively:
SPS incurred revisions to prior estimates and new liabilities for asbestos due to a new dismantling cost study. There were revised ash ponds and electric transmission and distribution asset retirement obligations due to new estimates and end of life dates. The Denver City steam plant was demolished in 2008 settling the Denver City steam plant ARO.
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, 2008 and Dec. 31, 2007, were $96 million and $96 million, respectively.
Legal Contingencies
Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on SPS’ financial position and results of operations.
Environmental Litigation
Carbon Dioxide Emissions Lawsuit - In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit. In June 2007 the Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal. Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “pollutant” subject to regulation by the EPA under the CAA. In July 2007, in response to the request of the Court of Appeals, the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.
Comer vs. Xcel Energy Inc. et al. - In April 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. In September 2007, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. Oral arguments were presented to the Court of Appeals on Aug. 6, 2008. Pursuant to the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3, 2008. No explanation was given for the order. The Court of Appeals has taken the matter under advisement.
Native Village of Kivalina vs. Xcel Energy Inc. et al. - In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy, the parent company of SPS, and 23 other utilities, oil, gas and coal companies. The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that Defendants’ emission of CO2 and other greenhouse gases contribute to global warming, which is harming their village. Plaintiffs claim that as a consequence, the entire village must be relocated at a cost of between $95 million and $400 million. Plaintiffs assert a nuisance claim under federal and state common law, as well as a claim asserting “concert of action” in which defendants are alleged to have engaged in tortious acts in concert with each other. Xcel Energy was not named in the civil conspiracy claim. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. The matter has now been fully briefed, with oral arguments set for May 19, 2009. It is unknown when the court will render a decision.
Employment, Tort and Commercial Litigation
Lamb County Electric Cooperative (LCEC) - In 1995, LCEC petitioned the PUCT for a cease and desist order against SPS alleging SPS was unlawfully providing service to oil field customers in LCEC’s certificated area. In May 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS in 1976 was granted a certificate to serve the disputed customers. LCEC appealed the decision to the Texas state court. In August 2004, the court affirmed the decision of the PUCT. In September 2004, LCEC appealed the decision to the Court of Appeals for the Third Supreme Judicial District. In November 2008, the Court of Appeals issued an opinion affirming the decision in favor of SPS. In December 2008, LCEC filed a petition for review with the Supreme Court of Texas. On Feb. 27, 2009, the Supreme Court of Texas denied LCEC’s request for review.
In 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts alleged in the petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination of the legality of SPS providing electric service to the disputed customers. The PUCT order from May 2003, which found SPS was legally serving the disputed customers, collaterally determines the issue of liability contrary to LCEC’s position in the suit. An adverse ruling on the appeal of May 2003 PUCT order could result in a different determination of the legality of SPS’ service to the disputed customers.
15. 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) Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.
(b) Includes the fair value of certain long-term purchased power agreements used to meet energy capacity requirements.
16. Segments and Related Information
SPS has only one reportable segment. SPS is a wholly owned subsidiary of Xcel Energy and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico. Revenues from external customers were $1,992.8 million, $1,652.3 million and $1,686.5 million for the years ended Dec. 31, 2008, 2007 and 2006, respectively.
Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.
17. 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 executed by each subsidiary. Costs are charged directly to the subsidiary which uses the service whenever possible and are allocated if they cannot be directly assigned.
Xcel Energy has established a utility money pool arrangement with the utility subsidiaries. See Note 4 for further discussion of this borrowing arrangement.
In 2006, SPS purchased electricity from Borger Energy Associates (Borger Energy), a former Xcel Energy subsidiary. Xcel Energy sold its interest in Borger Energy in December 2006.
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:
18. Summarized Quarterly Financial Data (Unaudited)
Due to the seasonality of SPS’s electric sales, such interim results are not necessarily an appropriate base from which to project annual results. Summarized quarterly unaudited financial data is as follows:
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 2007 and 2008, 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(T)
Item 9A(T) - 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. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2008, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and the CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.
Internal Controls 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. SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. SPS has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2008, on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, SPS conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, SPS did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.
This annual report does not include an attestation report of SPS’ registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SPS’ registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit SPS to provide only management’s report in this annual report.
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, Executive Officers and Corporate Governance
Item 11
Item 11 - Executive Compensation
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13
Item 13 - Certain Relationships, Related Transactions and Director Independence
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 2009 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV
Item 15
Item 15 - Exhibits, Financial Statement Schedules
1.
Financial Statements
Management Report on Internal Controls - For the year ended Dec. 31, 2008.
Report of Independent Registered Public Accounting Firm - For the years ended Dec. 31, 2008, 2007 and 2006.
Statements of Income - For the three years ended Dec. 31, 2008, 2007 and 2006.
Statements of Cash Flows - For the three years ended Dec. 31, 2008, 2007 and 2006.
Balance Sheets - As of Dec. 31, 2008 and 2007.
2.
Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2008, 2007 and 2006.
3.
Exhibits
*Indicates incorporation by reference
+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
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*
Fourth Supplemental Indenture dated Oct. 1, 2006 between Southwestern Public Service Co. and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
4.06*
Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
4.07*
$250,000,000 Credit Agreement dated Dec. 14, 2006 between SPS and various lenders (Exhibit 99.04 to Form 8-K of Xcel Energy (file no. 001-03034) dated Dec. 14, 2006).
4.08*
Supplemental Trust Indenture dated as of Nov. 1, 2008 between SPS and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $250,000,000 principal amount of Series G Senior Notes, 8.75% due 2018 (Exhibit 4.01 of Form 8-K of SPS, dated Nov. 14, 2008 (file no. 001- 03789)).
10.01*+
Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+
Xcel Energy Inc. Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+
Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+
New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+
Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+
Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+
Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+
Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+
Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended
SCHEDULE II
SOUTHWESTERN PUBLIC SERVICE CO.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2008, 2007 and 2006
(amounts in thousands of dollars)
(1) Recovery of amounts previously written off
(2) Principally bad debts 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.
SOUTHWESTERN PUBLIC SERVICE CO.
/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
March 2,
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 March 2, 2009.
/s/ DAVID L. EVES
/s/ RICHARD C. KELLY
David L. Eves
Richard C. Kelly
President, CEO, and Director
Chairman and Director
/s/ TERESA S. MADDEN
/s/ BENJAMIN G.S. FOWKE III
Teresa S. Madden
Benjamin G.S. Fowke III
Vice President and Controller
Executive Vice President, Chief Financial Officer and
Director
(Principal Accounting Officer)
(Principal Financial Officer)
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.