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
Oversight of Risk and Related Processes
The goal of Xcel Energy’s risk management process, which includes SPS, is to understand and manage material risk; management is responsible for identifying and managing the risks, while directors oversee and hold management accountable. Our risk management process has three parts: identification and analysis, management and mitigation, and communication and disclosure. Our management identifies and analyzes risks to determine materiality and other attributes like timing, probability and controllability.
Management broadly considers our business, the utility industry, the domestic and global economy, and the environment to identify risks. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the securities disclosure process, the hazard risk management process, and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. At the same time, the business planning process identifies areas where a business area may take inappropriate risk to meet goals.
The goal of the risk management process is to mitigate the risks inherent in the implementation of Xcel Energy’s and SPS’ strategy. The process for risk management and mitigation includes our code of conduct and other compliance policies, formal structures and groups, and overall business management. At a threshold level, we have developed a robust compliance program and promotes a culture of compliance, which mitigates risk. In addition to the code of conduct, we have a robust compliance program, including policies, training and reporting options.
Building on the culture of compliance, we manage and mitigate risks through formal structures and groups, including management councils, risk committees, and the services of corporate areas such as internal audit, the corporate controller and legal services. While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.
We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2 and risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for our products and services. Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy’s and SPS’ senior management.
Management provides information to the Xcel Energy’s Board in presentations and communications over the course of the Board calendar. Senior management presents an assessment of key risks to the Board annually. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy’s and SPS’ strategy.
The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees. The standing committees also oversee risk management as part of their charters. Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. The Xcel Energy Board has overall responsibility for risk oversight. As described above, the Board reviews the key risk assessment process presented by senior management. This key risk assessment analyzes the most likely areas of future risk to Xcel Energy. The Xcel Energy Board also reviews the performance and annual goals of each business area. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy.
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 and earn a return on our capital investment in our utility operations. We currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our costs incurred in a test year. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing 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 rate 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.
Our operations require significant capital investment in property, plant and equipment; consequently, we are 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, such as the collapse in the U.S. sub-prime mortgage market and subsequent broad financial market stress, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.
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.
One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. Additional margin requirements could impact our liquidity.
We may at times have direct credit exposure in our short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties. We may also have some indirect credit exposure due to transactions with affiliates that participate in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.
We do 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 us to exercise our contractual rights.
We are subject to commodity risks and other risks associated with energy markets and energy production.
We engage in wholesale sales and purchases of electric capacity, energy, and energy-related products and are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility. Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.
If we encounter market supply shortages, 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. The impact of these cost and reliability issues depends on unique operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.
We are subject to 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, 2009, these sites included third party sites, such as landfills, for 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, including but not limited to regulation of mercury, NOx, SO2, CO2, particulates and coal ash. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change.
There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in 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 our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers. Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. 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 our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.
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 and new interpretations of existing laws through climate change litigation create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. Our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.
The EPA has taken steps to regulate GHGs under the CAA. On Dec. 7, 2009, the EPA issued a finding that GHG emissions endanger public health and welfare and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011. Xcel Energy, our parent company, is also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 14, Commitments and Contingent Liabilities, in our notes to the financial statements. While Xcel Energy believes such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.
Many of the federal and state climate change legislative proposals, such as ACES, 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 emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation will be enacted. The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the United States, any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the 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 with respect to energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, and may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt. 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., and 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. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to implement the NERC critical infrastructure protection standards as they are implemented and clarified.
The insurance industry has also been affected by these events and the availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.
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 the actions of a neighboring utility or 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. 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 an entity to maintain day-to-day operations in response to unforeseen events. 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 is 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, 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 benefits may adversely affect our results of operations, financial position, or liquidity.
We have defined benefit pension and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements and related contributions may change in the future.
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, 2009, Xcel Energy had approximately $7.9 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, 2009, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $76.4 million and $18.0 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, 2009, was approximately $29.9 million. Xcel Energy’s total exposure under these indemnities cannot be estimated 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.
All of the members of 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 2009, 2008 and 2007 we paid $66.8 million, $61.8 million and $69.1 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 Staff Comments
None.
Item 2
Item 2 - Properties
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2009:
SPS had 437 electric utility transmission and distribution substations at Dec. 31, 2009.
Item 3
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against SPS. After consultation with legal counsel, SPS 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 and other regulatory matters, see Item 1 for Public Utility Regulation and Summary of Recent Federal Regulatory Developments and Note 13 to the financial statements.
Item 4
Item 4 - Reserved
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 facility, FERC rules and state regulatory commissions.
· SPS’ credit facility includes a financial covenant that requires the equity-to-total capitalization ratio to be greater than or equal to 35 percent. SPS was in compliance as its equity-to-total capitalization ratio was 51 percent and 48 percent at Dec. 31, 2009 and 2008, respectively.
· 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 2009 and 2008 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. Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including 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; environmental laws and regulations; actions of accounting regulatory bodies; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’s Form 10-K for the year ended Dec. 31, 2009 and Exhibit 99.01 to SPS’ Form 10-K for the year ended Dec. 31, 2009.
Results of Operations
SPS’ net income was approximately $67.8 million for 2009, compared with approximately $31.8 million for 2008.
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
Non-Fuel Operating Expense and Other Items
Other Operating and Maintenance Expenses - Other operating and maintenance expenses for 2009 increased $13.9 million, or 6.7 percent, compared to 2008. The following summarizes the components of the changes for the year ended Dec. 31:
Demand Side Management (DSM) Program Expenses - DSM program expenses for 2009 decreased by approximately $1.4 million, or 16.2 percent, compared with 2008. This decrease was due to the settlement of the Texas rate case in 2009 which extended the amortization period from 4 years to 10 years. DSM program expenses are recovered through riders or base rates.
Depreciation and Amortization - Depreciation and amortization increased by approximately $5.9 million, or 6 percent, for 2009 compared with 2008, primarily due to the amortization of rate case expenses and regulatory assets and overall system growth.
Other Income, Net - Other income, net, decreased by $5.6 million for 2009 compared with 2008. The decrease was primarily due to lower interest income in 2009.
Allowance for Funds Used During Construction, Debt and Equity (AFUDC) - AFUDC increased by approximately $4.3 million for 2009 compared with 2008. The increase was due to the debt to equity split that began in January of 2009.
Interest Charges - Interest charges increased by $10.6 million, or 17.3 percent, for 2009 compared with 2008. The increase was primarily due to increased long-term debt levels necessary to repay short-term borrowings and to fund capital investments throughout 2009 compared to 2008.
Income Taxes - Income tax expense increased by approximately $19.5 million for 2009, compared with 2008. The effective tax rate was 37.4 percent for 2009, compared with 39.8 percent for 2008. The increase in tax expense and the lower effective tax rate for 2009 were primarily due to higher pretax income in 2009.
The effective tax rate for 2009 differs from the statutory federal income tax rate, primarily due to state income tax expense. The effective tax rate for 2008 differs from the statutory federal income tax rate, primarily due to state income tax expense and plant related regulatory tax expense, partially offset by prior year state tax benefit. See Note 7 to the financial statements.
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.
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 its risk management committee, which is made up of management personnel not directly involved in the activities governed by the 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.
Credit Risk - SPS is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance of their 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. Distress in the financial markets could increase SPS’ credit risk.
Item 8
Item 8 - Financial Statements and Supplementary Data
See 15-1 in Part IV for an index of financial statements included herein.
See Note 18 to the financial statements for summarized quarterly financial 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, 2009. 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, 2009, the company’s internal control over financial reporting is effective based on those criteria.
SPS’ independent auditors have issued an audit report on the company’s internal control over financial reporting. Their report appears herein.
/s/ C. RILEY HILL
/s/ DAVID M. SPARBY
C. Riley Hill
David M. Sparby
President and Chief Executive Officer
Vice President and Chief Financial Officer
March 1,
March 1,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholder
Southwestern Public Service Company
We have audited the accompanying balance sheets and statements of capitalization of Southwestern Public Service Company (the “Company”) as of December 31, 2009 and 2008, 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, 2009. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 1,
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholder
Southwestern Public Service Company
We have audited the internal control over financial reporting of Southwestern Public Service Company (the “Company”) as of December 31, 2009, based on criteria established Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the financial statements and financial statement schedule as of and for the year ended December 31, 2009 of the Company and our report dated March 1, 2010 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
March 1,
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 natural gas and other electric fuel costs, as well as purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred. Where applicable, under governing state regulatory commission rate orders, fuel 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 can change up to three times per year based on the projected costs of natural gas. In January 2010, the PUCT approved recovery of certain transmission investments and other transmission costs through the TCRF rider. 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 ASC 815 Derivatives and Hedging. 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, interest rate derivatives, and commodity 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 interest rate curves are used to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts, or internally prepared valuation models to determine 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 ASC 815 Derivatives and Hedging 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 sale of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; 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 accounting for derivatives 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 this guidance. 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 based on recovery mechanisms 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. ASC 815 Derivatives and Hedging requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting as normal purchases or normal sales.
SPS evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.
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, 2009, 2008 and 2007 was 2.6, 2.8 and 2.6 percent, respectively.
AFUDC - AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in SPS’ rate base for establishing utility service rates.
Environmental Costs - Environmental costs are recorded when it is probable SPS is liable for the costs and the liability can 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, 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 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.
SPS follows the guidance in ASC 740 Income Taxes to measure and disclose uncertain tax positions that SPS has taken or expects to take in its income tax returns. In accordance with this guidance, SPS recognizes a tax position in its financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
SPS reports interest and penalties related to income taxes within the other income and interest charges sections 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 ASC 980 Regulated Operations. Under this guidance:
· 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 in Note 15 to the financial statements.
Deferred Financing Costs - Other assets included deferred financing costs, net of amortization, of approximately $6.9 million and $7.6 million at Dec. 31, 2009 and 2008, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.
Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.
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 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 load obligations, they are recorded as inventory at cost. RECs acquired for trading purposes are recorded as other investments and are also recorded at cost. The cost of RECs that are retired for compliance purposes is 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, SPS reduces recoverable fuel costs for the value of certain RECs and records the cost of RECs to satisfy future compliance requirements that are recoverable in future rates as regulatory assets.
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.
Reclassifications - Demand side management program expenses were reclassified as a separate item from both other operating and maintenance expenses and depreciation and amortization on the statements of income. Demand side management program expenses were reclassified as a separate item from depreciation and amortization expenses within the statements of cash flows. These reclassifications did not have an impact on total operating expenses or net cash provided by operating activities.
Subsequent Events - Management has evaluated the impact of events occurring after Dec. 31, 2009 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
2. Accounting Pronouncements
Recently Adopted
Business Combinations - In December 2007, the FASB issued new guidance on business combinations 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. This new guidance 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 implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its financial statements.
Noncontrolling Interests - Also in December 2007, the FASB issued new guidance on noncontrolling interests in consolidated financial statements which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This new guidance was effective for fiscal years beginning on or after Dec. 15, 2008. SPS implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its financial statements.
Derivatives and Hedging Disclosures - In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities 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. The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts. This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008. SPS implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its financial statements. For further discussion and the required disclosures, see Note 10 to the financial statements.
Interim Fair Value Disclosures - In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements. This new guidance was effective for interim periods ending after June 15, 2009. SPS implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its financial statements.
Fair Value in Inactive Markets - Also in April 2009, the FASB issued new guidance for identifying market transactions that are not orderly and determining fair value when market trading activity has decreased significantly. The new guidance emphasizes that even if there has been a significant decrease in the volume and level of market activity for an asset or liability, fair value still represents the exit price in an orderly transaction between market participants. This new guidance was effective for interim and annual periods ending after June 15, 2009. SPS implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its financial statements.
Other-Than-Temporary Impairments - Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. This new guidance was effective for interim and annual periods ending after June 15, 2009. SPS implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its financial statements.
Accounting Standards Codification - In June 2009, the FASB issued Topic 105 - Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 - The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB ASC to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC. All other accounting literature not included in the Codification is to be considered non-authoritative. The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009. SPS implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009. The implementation did not have a material impact on its financial statements.
Postretirement Benefit Plans - In December 2008, the FASB issued new guidance on employers’ disclosures about postretirement benefit plan assets. The guidance amends and expand previous disclosure requirements for plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, and information regarding fair value measurements. This new guidance was effective for disclosures for fiscal years ending after Dec. 15, 2009. SPS implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its financial statements. For further discussion and the required disclosures, see Note 8 to the financial statements.
Fair Value of Liabilities - In August 2009, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Measuring Liabilities at Fair Value (ASU No. 2009-05), which updates the Codification with clarifications for measuring the fair value of liabilities. The liability-specific guidance includes clarifications and guidelines for using, when available, the most observable prices in active markets for identical liabilities or similar liabilities, or the prices of identical liabilities or similar liabilities traded as assets, rather than more complex and less observable valuation techniques and inputs such as those used in a present value model. The updates to the Codification contained in ASU No. 2009-05 were effective for interim and annual periods beginning after its August, 2009 issuance. SPS implemented the guidance on Sept. 1, 2009, and the implementation did not have a material impact on its financial statements.
Recently Issued
Consolidation of Variable Interest Entities - In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. This new guidance is effective for interim and annual periods beginning after Nov. 15, 2009. SPS does not expect the implementation of the guidance to have a material impact on its financial statements.
Fair Value Measurement Disclosures - In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. SPS does not expect the implementation of the guidance to have a material impact on its financial statements.
3. Selected Balance Sheet Data
4. Short-Term Borrowings
Commercial Paper - SPS had no commercial paper outstanding at Dec. 31, 2009 and 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 investments in and borrowings from the utility subsidiaries between each other. The Holding Company may make investments in the utility subsidiaries at market-based interest rates. However, the money pool arrangement does not allow the utility subsidiaries to make investments in the Holding Company. SPS has approval to borrow up to $100 million under the arrangement. At Dec. 31, 2009 and 2008, SPS had money pool investments of $77.0 million and $90.5 million, respectively. The weighted average interest rates at Dec. 31, 2009 and 2008, were 0.36 percent and 3.50 percent, respectively.
5. Long-Term Debt
Credit Facilities - At Dec. 31, 2009, SPS had the following committed credit facility in effect, in millions of dollars:
* Includes direct borrowings, outstanding commercial paper and issued and outstanding letters of credit.
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. SPS was in compliance as its debt-to-total capitalization ratio was 49 percent and 52 percent at Dec. 31, 2009 and 2008, respectively. 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, 2009, SPS had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $10.0 million of letters of credit. 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.
Certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.
In February 2010, SPS redeemed its $25 million pollution control obligations, securing pollution control revenue bonds, due July 1, 2016.
In November 2008, SPS issued $250 million of 8.75 percent senior notes, series due 2018. The proceeds from this offering were used to repay short-term debt.
During the next five years, SPS has long-term debt maturities of $45 million due in 2011.
6. Preferred Stock
SPS has authorized the issuance of preferred stock.
7. Income Taxes
Federal Audit - SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 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. The statute of limitations applicable to Xcel Energy’s 2004 and 2005 federal income tax returns expired on Dec. 31, 2009. The IRS commenced an examination of tax years 2006 and 2007 in 2008, and this audit is expected to be completed in the first quarter of 2010. As of Dec. 31, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.
State Audits - SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. In 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, 2009, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2005. The state of Texas has notified SPS of its intent to audit tax years 2006 and 2007. As of Dec. 31, 2009, the Texas audit had not been scheduled. There currently are no other state income tax audits in progress.
Unrecognized Tax Benefits - The amount of unrecognized tax benefits was $2.9 million and $3.5 million on Dec. 31, 2009 and Dec. 31, 2008, respectively. A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
The tax benefits associated with net operating loss (NOL) and tax credit carryovers were $0.1 million as of Dec. 31, 2009 and Dec. 31, 2008.
The unrecognized tax benefit balance included $0.2 million and $0.3 million of tax positions on Dec. 31, 2009 and Dec. 31, 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $2.7 million and $3.2 million of tax positions on Dec. 31, 2009 and Dec. 31, 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 decrease in the unrecognized tax benefit balance of $0.6 million in 2009 was due to the resolution of certain federal audit matters, partially offset by an increase 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 Texas audit begins and when the IRS and other 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.
A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:
No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2009 or Dec. 31, 2008.
Other Income Tax Matters - NOL and tax credit carryforwards as of Dec. 31, 2009 and 2008 were as follows:
The federal carryforward periods expire between 2021 and 2029. The state carryforward periods expire between 2010 and 2027.
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
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, which includes SPS, offers various benefit plans to its employees. At Dec. 31, 2009, SPS had 795 bargaining employees covered under a collective-bargaining agreement, which expires in October 2011.
Effective Jan. 1, 2009, Xcel Energy and SPS adopted new guidance on employers’ disclosures about pension and postretirement benefit plan assets. The new guidance expands employers’ disclosure requirements for benefit plan assets, including investment policies and strategies, major categories of plan assets, and information regarding fair value measurements consistent with the disclosures for entities’ recurring fair value measurements prescribed by ASC 820 Fair Value Measurements.
ASC 820 Fair Value Measurements establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels defined by the hierarchy and examples of each level are as follows:
Level 1 - Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as common stocks listed by the New York Stock Exchange.
Level 2 - Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs, such as corporate bonds with pricing based on market interest rate curves and recent trades of similarly rated securities.
Level 3 - Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation, such as asset and mortgage backed securities, for which subjective risk-based adjustments to estimated yield and forecasted prepayments are significant inputs.
Pension Benefits
Xcel Energy, which includes SPS, has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and social security benefits. Xcel Energy’s and SPS’s policy is to fully fund the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws, into an external trust over time.
Xcel Energy and SPS base investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the actual historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the portfolio of pension investments is 8.98 percent, which is greater than the current assumption level. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns in 2009 were above the assumed level of 8.50 percent while returns in 2008 and 2007 were below the assumed level of 8.75 percent. Xcel Energy and SPS continually review pension assumptions. In 2010, Xcel Energy will use an investment-return assumption, for all pension plans in aggregate, of 7.79 percent.
The assets are invested in a portfolio according to Xcel Energy’s and SPS’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity, however, a higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year.
The following table presents the target pension asset allocation for 2009 and 2008:
In 2009, Xcel Energy and SPS engaged J.P. Morgan’s Pension Advisory Group to evaluate the allocation of the total assets in the master pension trust, taking into consideration the funded status of each individual pension plan. The investment strategy employed during 2009 is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of short-to-intermediate term and long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.
Pension Plan Assets
The following table presents, for each of the fair value hierarchy levels, pension plan assets that are measured at fair value as of Dec. 31, 2009:
The following table presents the changes in Level 3 pension plan assets for the year ended Dec. 31, 2009:
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, 2009, Xcel Energy’s pension plans, in the aggregate, had plan assets of $2.4 billion and projected benefit obligations of $2.8 billion. At Dec. 31, 2008, one of the pension plans had plan assets of $259.9 million, which exceeded projected benefit obligations of $244.3 million and all other plans in the aggregate had plan assets of $1.9 billion and projected benefit obligations of $2.4 billion.
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 2007 through 2009 for the pension plans and are not expected to require cash funding in 2010.
Xcel Energy accelerated its planned 2010 contribution of $100 million based on available liquidity, bringing its total pension contributions to $200 million during 2009.
· Voluntary contributions were made to the PSCo Bargaining Pension Plan of $173 million in 2009, $35 million in 2008 and $35 million in 2007.
· Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $27 million in 2009. No voluntary contributions were made to the plan during 2007 or 2008.
· Pension funding contributions for 2011, 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 $100 million to $150 million.
Plan Amendments - The decrease in the projected benefit obligation for the plan amendment is due to a change in the average earnings calculation resulting from negotiations with the PSCo Bargaining Pension Plan.
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 2010 pension cost calculations will be 7.79 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including SPS, 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, which includes SPS, also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of operating cash flows.
Defined Contribution Plans
Xcel Energy, including SPS, maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for SPS were approximately $1.4 million in 2009, $1.2 million in 2008 and $1.5 million in 2007.
Postretirement Health Care Benefits
Xcel Energy, which includes SPS, has a contributory health and welfare benefit plan that provides health care and death benefits to most 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 health care program with no employer subsidy.
In 1993, Xcel Energy and SPS adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.
Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs under the new guidance.
Plan Assets -Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.
Xcel Energy and SPS base investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. The assets are invested in a portfolio according to Xcel Energy’s and SPS’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Investment-return volatility is not considered to be a material factor in postretirement health care costs.
The following table presents, for each of the fair value hierarchy levels, postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2009:
The following table presents the changes in Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2009:
Benefit Obligations - A comparison of the actuarially computed benefit obligation and plan assets, on a combined basis, is presented in the following table:
Effective Dec. 31, 2009, Xcel Energy, including SPS, reduced the initial medical trend assumption from 7.4 percent to 6.8 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is three years. Xcel Energy and SPS base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.
A 1-percent change in the assumed health care cost trend rate would have the following effects on 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, which includes SPS, contributed $62.2 million during 2009 and $55.6 million during 2008 and expects to contribute approximately $45.4 million during 2010.
Plan Amendments - The decrease in the projected benefit obligation for the plan amendment is due to a change in the medical experience rate resulting from negotiations with the PSCo Bargaining Postretirement Health Care Plan.
Benefit Costs - The components of net periodic postretirement benefit cost are:
Projected Benefit Payments - The following table lists the projected benefit payments for the pension and postretirement benefit plans.
9. Other Income, Net
Other income (expense), net for the years ended Dec. 31 consisted of the following:
10. Derivative Instruments
Effective Jan. 1, 2009, SPS adopted new guidance on disclosures about derivative instruments and hedging activities contained in ASC 815 Derivatives and Hedging, which requires additional disclosures regarding why an entity uses derivative instruments, the volume of an entity’s derivative activities, the fair value amounts recorded to the balance sheet for derivatives, the gains and losses on derivative instruments included in the statement of income or deferred, and information regarding certain credit-risk-related contingent features in derivative contracts.
SPS may enter into derivative instruments, including forward contracts, futures, swaps and options, to reduce risk in connection with changes in interest rates and electric utility commodity prices. See additional information pertaining to the valuation of derivative instruments in Note 12 to the financial statements.
Interest Rate Derivatives - SPS may enter 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 generally designated as cash flow hedges for accounting purposes.
At Dec. 31, 2009, accumulated other comprehensive losses related to interest rate derivatives included $0.6 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.
Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during the year ended Dec. 31, 2009 were $5.8 million.
During the fourth quarter of 2009, SPS settled a $25 million notional value interest rate swap. The interest rate swap was not designated as a hedging instrument, and as such, $2.5 million of changes in fair value of the swap were recorded to earnings for the swap during the year ended Dec. 31, 2009.
Commodity Derivatives - SPS may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations. This could include the purchase or sale of energy or energy-related products. At Dec. 31, 2009 and Dec. 31, 2008, SPS held no commodity derivatives. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.
The following table shows the major components of derivative instruments valuation in the balance sheets:
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, 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 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 interest rate cash flow hedges on SPS’ accumulated other comprehensive income, included as a component of common stockholder’s equity, is detailed in the following tables:
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, 2009 and 2008. 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, 2009 and 2008, there were $10.0 million and $11.6 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair values and are subject to fees determined in the marketplace.
12. Fair Value Measurements
Effective Jan. 1, 2008, SPS adopted new guidance for recurring fair value measurements contained in ASC 820 Fair Value Measurements and Disclosures which provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. A hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value was established by this guidance. The three levels in the hierarchy and examples of each level are as follows:
Level 1 - Quoted prices are available in active markets for identical assets 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 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 hierarchy.
SPS had no interest rate derivative contracts or cash equivalents measured at fair value on a recurring basis as of Dec. 31, 2009.
13. Rate Matters
Pending and Recently Concluded Regulatory Proceedings - PUCT
Base Rate
Texas Retail Base Rate Case - In June 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 Lea Power Partners (LPP) purchase power agreement. The rate filing was 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.
In January 2009, a settlement agreement was reached with various intervenors, which provided for a base rate increase of $57.4 million, a reduced depreciation expense of $5.6 million, allowed SPS to implement the transmission rider in 2009 and precludes SPS from filing to seek any other change in base rates until Feb. 15, 2010. In January 2009, an ALJ approved interim rates effective February 2009. On June 2, 2009, the PUCT issued its order approving the settlement.
John Deere Wind Complaint - In June 2007, several John Deere Wind Energy subsidiaries (JD Wind) filed a complaint against SPS disputing SPS’ payments for energy produced from the JD Wind projects. SPS responded that the payments to JD Wind are appropriate and in accordance with SPS’ filed tariffs. In March 2009, the ALJ recommended that SPS payment methodology to JD Wind is proper and that JD Wind’s complaint be denied.
In May 2009 the PUCT issued a final order denying JD Wind’s request for relief against SPS. In June 2009, JD Wind filed a petition for review of the final order in Texas District Court. In July 2009, the PUCT filed an answer to JD Wind’s petition in Texas District Court in which the PUCT denied all allegations contained in the JD Wind petition. The case is pending in Texas District Court.
In November 2009, the FERC declined to rule on a request to overturn the PUCT decision by JD Wind but did issue a declaratory order stating that the PUCT’s order denying JD Wind’s complaint is not consistent with the FERC’s regulations. In December 2009, SPS requested that the FERC reconsider its November 2009 declaratory order. In December 2009, JD Wind filed a complaint against the PUCT in U. S. District Court seeking federal law enforcement, including declaratory and injunctive relief to enforce and give proper effect to the PURPA. JD Wind requests a declaration that the PUCT’s order does not implement PURPA and FERC PURPA rules and is preempted by federal law. The complaint also requests that the PUCT be required to revise its order and be enjoined from enforcing its current order. SPS intends to intervene in this case and defend the PUCT’s order. On Jan. 28, 2010, JD Wind filed a damage suit against SPS in Texas state district court to toll the statute of limitations while the above cases are being decided.
Texas Jurisdictional Fuel Allocation Methodology - In May 2009, SPS filed an application to revise the calculation of Texas retail jurisdictional fuel and purchased power expense, effective in January 2008. SPS has determined that its current method results in a material amount of unrecovered fuel and purchased power expense. The application seeks approval for a revised methodology, which matches the fuel and purchased power expenses in a month with the fuel factor revenue received from each kilowatt hour used that month.
In November 2009, the PUCT issued a final order approving a unanimous settlement that would allow for the change in the calculation of deferred fuel consistent with the approach proposed by SPS. The estimated impact is expected to result in an approximate $6.5 million increase to fuel and purchased power expenses for the Texas retail jurisdiction for Jan. 1, 2008 to Dec. 31, 2009. SPS has agreed to reduce the new allocated portion by $3 million subsequent to adopting the new methodology going forward.
Texas Transmission Cost Recovery Factor (TCRF) - In 2007, the PUCT implemented rules allowing utilities to request a TCRF in between rate cases for recovery of new transmission investment costs. In June 2009, SPS filed a request to implement a TCRF with proposed revenues of $7.4 million annually. This is SPS’ first filing under that rule.
In November 2009, the parties filed a unanimous stipulation, which allows SPS to recover $4.5 million annually, and the ALJ issued an order approving interim TCRF rates beginning Jan. 1, 2010. In January 2010, the PUCT approved the unanimous stipulation.
Pending and Recently Concluded Regulatory Proceedings -NMPRC
Base Rate
2008 New Mexico Retail Electric Rate Case - In December 2008, SPS filed with the NMPRC a request to increase electric rates in New Mexico by approximately $24.6 million, or 6.2 percent. The request was based on a historic test year (split year based on the year ending June 30, 2008), an electric rate base of $321 million, and an equity ratio of 50.0 percent and a requested ROE of 12.0 percent. SPS also requested interim rates of $7.6 million per year to recover capacity costs of the Lea Power facility, which became operational in September 2008.
In March 2009, the NMPRC approved a partial stipulated settlement between the parties that allows SPS to recover approximately $5.7 million of interim rates, effective May 1, 2009, through an LPP cost rider until the final rates from the remainder of the case are effective.
In July 2009, the NMPRC issued an order approving the stipulation settlement agreement. Under the stipulation, SPS receives a base rate increase of $14.2 million, effective July 1, 2009. SPS has agreed that Dec. 1, 2010 is the earliest date it will file its next base rate case, subject to a force majeure provision triggered by additional environmental compliance costs. SPS implemented the new rates on July 15, 2009.
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 the 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.
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 April 2008, the FERC approved the settlement, which resolved all issues pertaining to Golden Spread that were the subject of the Complaint; implemented a formula rate and extended the term of its partial requirements sale to Golden Spread beginning 2012 at 500 MW and ramping down to 200 MW for the two years prior to the end of the term in 2019. The settlement made the extended purchase contingent on certain state approvals. 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. Request for approvals are currently pending before the NMPRC and the PUCT, and SPS anticipates actions by the state commissions during the first quarter of 2010.
New Mexico Cooperatives’ Complaint Settlement - In January 2010, SPS reached a settlement with Farmers’ Electric Cooperative of New Mexico, Lea County Electric Cooperative, Central Valley Electric Cooperative and Roosevelt County Electric Cooperative, all wholesale customers of SPS located in New Mexico, and Occidental regarding the same base rate and fuel issues raised in the complaint described above. The settlement with these wholesale customers is now pending approval by the FERC. The settlement resolves all issues arising from the complaint docket and implements a replacement contract with a formula production rate at 10.5 percent ROE and extended term of its requirements sale to the four wholesale customers. The four wholesale customers must reduce their system average cost power purchases by 90 to 100 MW in 2012, and implement staged reductions in system average cost power purchases through the term of the agreement, which terminates on May 31, 2026. The settlement made the replacement contract contingent on certain state approvals. In the event all regulatory approvals are not received, the Settlement includes a one time total contingent payment of $12 million by SPS to these wholesale customers. These wholesale customers agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed wholesale power sale.
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.
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 and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $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 to the remaining non-settled customers. As of Dec. 31, 2009, SPS has accrued an amount sufficient to cover the estimated refund obligation.
SPS 2008 Wholesale Rate Case - In March 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. In April 2009, the parties reached a settlement in which SPS will receive an annual revenue increase of approximately $9.6 million or an increase of 3.3 percent. The FERC issued an order approving the uncontested settlement in September 2009.
SPS 2008 Transmission Formula Rate Case - In December 2007, Xcel Energy submitted an application to implement a transmission formula rate for the SPS zone of the Xcel Energy OATT. The changed rates affect all wholesale transmission service customers using the SPS transmission network under either the Xcel Energy OATT or the SPP Regional OATT.
In September 2009, Xcel Energy filed an uncontested offer of settlement with the FERC which resolves all issues in the proceeding with the exception of the ratemaking and rate design treatment for certain radial lines under the SPP OATT. The parties are still formulating the methodology for designating direct assignment of radial transmission lines to wholesale and retail customers pursuant to the SPP OATT.
The settlement provides for a formula rate using a fully forecasted test year effective Jan. 1, 2009, with a stated ROE of 11.27 percent (including the 50 basis point adder for SPP RTO participation). The settlement will result in approximately $0.8 million in additional revenues for 2008 and 2009 in aggregate and will allow SPS to update its transmission rates annually for predicted costs and loads, subject to an annual true-up. In October 2009, SPS announced the 2010 costs and charges pursuant to the formula rate and are expected to provide $2.7 million in additional revenue, subject to true-up. The settlement was approved by the FERC in December 2009, and SPS and SPP are now effectuating the settlement.
14. Commitments and Contingent Liabilities
Capital Commitments - As of Dec. 31, 2009, the estimated cost of the capital expenditure programs and other capital requirements of SPS is approximately $270 million in 2010, $295 million in 2011 and $255 million in 2012.
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 2010 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, 2009, 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 2028. 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, 2009, 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 - SPS has certain long-term purchased power agreements with independent power producing entities that contain tolling arrangements under which SPS procures the fuel required to produce the energy purchased. SPS enters into these agreements to meet electric system capacity and energy needs. SPS is not subject to risk of loss from the operations of these potential VIEs. SPS has evaluated such entities for possible consolidation and has concluded that these entities are not required to be consolidated in SPS’s financial statements. The significant qualitative factors considered evaluating purchase power agreements under ASC 810 Consolidation include length and terms of the contract and operational, fuel price and financing risk. When necessary, a quantitative analysis demonstrated that SPS would absorb less than 50 percent of the expected gains or losses. Significant assumptions used in the quantitative analysis by SPS, 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 $54.6 million, $18.6 million and $4.3 million for 2009, 2008 and 2007, respectively. Included in total rental expense were purchase power agreement payments of $50.3 million and $14.2 million in 2009 and 2008, respectively, and no payments in 2007.
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 ASC 840 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, 2009, the liability for the cost of remediating these sites was estimated to be $0.1 million.
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 ARO. See additional discussion of AROs below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is 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
EPA GHG Endangerment Finding - On Dec. 7, 2009, in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), the EPA issued its “endangerment” finding that greenhouse gas emissions endanger public health and welfare and that emissions from motor vehicles contribute to the greenhouse gases in the atmosphere. This endangerment finding creates a mandatory duty for the EPA to regulate GHGs from light duty vehicles. The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010. Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.
CAIR - In March 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Texas. In response to the decisions by the D.C. Circuit Court of Appeals vacating but reinstating CAIR while the EPA develops revised regulations, the EPA has indicated that a CAIR replacement rule will be proposed in early 2010 with finalization planned for early 2011.
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 NOx allowance compliance costs were $1.7 million. The estimated NOx allowance cost for 2010 is $1.2 million. Annual purchases of SO2 allowances are estimated in the range of $1.7 million to $7.7 million each year, beginning in 2013, for phase I.
Allowance cost estimates for SPS are based on fuel quality and current market data. SPS believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.
CAMR - In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. The Texas Commission on Environmental Quality (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. The EPA has agreed to finalize MACT emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace CAMR. Xcel Energy, the parent company of SPS, anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter. 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.
Cunningham Draft Compliance Order - On Feb. 18, 2010, SPS received a draft compliance order from the New Mexico Environment Department (NMED) for Cunningham Station. In the draft order, NMED alleges that Cunningham exceeded its permit limits for NOx on 7,336 occasions and failed to report these exceedances as required by its permit. The draft order includes a proposed penalty of $16.1 million. SPS denies these allegations and will have an opportunity to discuss the alleged violations and proposed penalty with NMED prior to the issuance of a final order. SPS will vigorously defend its position in negotiations with NMED.
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 ASC 410 Asset Retirement and Environmental Obligations. 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.
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, 2009 and Dec. 31, 2008, respectively:
SPS revised ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.
SPS also 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. Removal costs as of Dec. 31, 2009 and Dec. 31, 2008, were $93 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 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, the parent company of SPS, 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. On Sept. 19, 2005, the court granted a motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit. On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision. On Nov. 5, 2009 the defendants, including Xcel Energy, filed a petition for rehearing and en banc review. It is uncertain when the Court of Appeals will respond to the petition.
Comer vs. Xcel Energy Inc. et al. - In 2006, Xcel Energy, the parent company of SPS, 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. Plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. On Oct. 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court. On Nov. 27, 2009, defendants, including Xcel Energy, filed a petition for en banc review. It is uncertain when the Court of Appeals will respond to the petition.
Native Village of Kivalina vs. Xcel Energy Inc. et al. - In 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. Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. 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. On Oct. 15, 2009, the U. S. District Court dismissed the lawsuit on constitutional grounds. On Nov. 5, 2009, plaintiffs filed a notice of appeal to the U. S. Court of Appeals for the Ninth Circuit.
15. Regulatory Assets and Liabilities
SPS’ financial statements are prepared in accordance with the provisions of ASC 980 Regulated Operations, as discussed in Note 1 to the financial statements. Under this guidance, 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 establish regulatory assets and liabilities. If changes in the utility industry or the business of SPS no longer allow for the application of regulatory accounting guidance 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.
(c) Includes the non-qualified pension plan.
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 $1,459.2 million, $1,992.8 million and $1,652.3 million for the years ended Dec. 31, 2009, 2008 and 2007, 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.
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 were:
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:
19. Lubbock Electric Distribution Assets
In November 2009, SPS entered into an asset purchase agreement with the city of Lubbock, Texas (City of Lubbock). This agreement sets forth that SPS will sell its electric distribution system assets within the city limits to LP&L for approximately $87 million. The sale and related transactions will eliminate the inefficiencies of maintaining duplicate distribution systems, one by SPS and the other by the city-owned LP&L. SPS currently serves about 24,000 customers within Lubbock, representing about 25 percent of the total customers in the dually certified service area. As part of this transaction, SPS will continue to provide the wholesale power to meet the electric load for these customers, initially by amending the current wholesale full-requirements contract with West Texas Municipal Power Agency (WTMPA), which provides service to LP&L through 2019 and then for an additional 25 years under a new contract directly with LP&L when the WTMPA contract terminates. Both of these wholesale power agreements provide for formula rates that change annually based on the actual cost of service. The formula rate with WTMPA reflects an initial 10.5 percent ROE. All or portions of this transaction are subject to review and approval by the PUCT, the NMPRC and FERC. This transaction is expected to close late in 2010. It is anticipated that any resulting gain on the sale of assets will be shared with retail customers in Texas.
Additionally, SPS and the City of Lubbock entered into an amended long-term treated sewage effluent water agreement under which SPS will continue to purchase waste water from the city for cooling SPS’s Jones Station southeast of Lubbock. This new waste water agreement will provide a long-term and low cost source for cooling water for SPS. This agreement is not subject to regulatory approval.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During 2008 and 2009, and through the date of this report, there were no disagreements with the independent public accountants for SPS on accounting principles or practices, financial statement disclosures or auditing scope or procedures.
Item 9A
Item 9A - Controls and Procedures
Disclosure Controls and Procedures
SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. 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, 2009, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and 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, 2009, 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.
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 and Related Transactions, and Director Independence
Item 14
Item 14 - Principal Accountant 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 2010 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV
Item 15
Item 15 - Exhibits and Financial Statement Schedules
1.
Financial Statements
Management Report on Internal Controls - For the year ended Dec. 31, 2009.
Report of Independent Registered Public Accounting Firm - For the years ended Dec. 31, 2009, 2008 and 2007.
Statements of Income - For the three years ended Dec. 31, 2009, 2008 and 2007.
Statements of Cash Flows - For the three years ended Dec. 31, 2009, 2008 and 2007.
Balance Sheets - As of Dec. 31, 2009 and 2008.
2.
Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2009, 2008 and 2007.
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 SPS 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 SPS 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 SPS 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 SPS 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 SPS 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*
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 percent 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 Xcel Energy 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*+
Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+
Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+
Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+
Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement of Form 10-K of Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.14*+
Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement of Form 10-K of Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.15*+
Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*+
First Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of Jan. 1, 2009 (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.17*+
First Amendment to the Xcel Energy Inc. Omnibus Incentive Award Plan as of Jan. 1, 2009 (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.18*
Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 - Exhibit 3).
10.19*
Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 - Exhibit 5(A)).
10.20*
Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 - Exhibit 5(B)).
10.21*
Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 - Exhibit 10(b)).
10.22*
Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 - Exhibit 10(c)).
10.23*
Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
10.24*
Amendment dated as of April 13, 2009 to the SPS Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.04 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.25*
Credit Agreement dated Dec. 14, 2006 between SPS and various lenders. (Exhibit 10.04 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.26*+
Second Amendment to the Xcel Energy 2005 Omnibus Incentive Plan (renaming it the Xcel Energy 2005 Long-Term Incentive Plan) (Exhibit 10.05 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.27*+
Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy. Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.28*+
Second Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan (Effective May 25, 2005) (Exhibit 10.07 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.29*+
Xcel Energy Inc. Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.30*
Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 - Exhibit 3).
10.31*+
Xcel Energy Inc. Executive Annual Incentive Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
12.01
Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01
Consent of Independent Registered Public Accounting Firm.
31.01
Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02
Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01
Statement pursuant to Private Securities Litigation Reform Act of 1995.
SCHEDULE II
SOUTHWESTERN PUBLIC SERVICE CO.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2009, 2008 and 2007
(amounts in thousands of dollars)
(a) Recovery of amounts previously written off.
(b) 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/ DAVID M. SPARBY
David M. Sparby
Vice President and Chief Financial Officer
(Principal Financial Officer)
March 1, 2010
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 1, 2010.
/s/ C. RILEY HILL
/s/ RICHARD C. KELLY
C. Riley Hill
Richard C. Kelly
President, CEO, and Director
Chairman and Director
/s/ TERESA S. MADDEN
/s/ DAVID M. SPARBY
Teresa S. Madden
David M. Sparby
Vice President and Controller
Vice President and Chief Financial Officer
(Principal Accounting Officer)
(Principal Financial Officer)
/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Director
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT
SPS has not sent, and does not expect to send, an annual report or proxy statement to its security holder.