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 Regulatory Developments
Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Public Utility Regulation
Capability and Demand
Natural Gas Supply and Costs
Natural Gas 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 PSCo, 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 PSCo’s 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 promote 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 PSCo’s 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 PSCo’s strategy.
The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees. The standing committees also oversee risk management as part of their charters. Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. 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 commission regulates many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service, the sale of electric energy in interstate commerce and certain natural gas transactions in interstate commerce.
Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated 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 participation 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 and/or natural gas 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 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:
· Sites of former MGPs operated by us, our predecessors, or other entities; and
· Third party sites, such as landfills, for which we are alleged to be a 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 15 Commitments and Contingent Liabilities, in our notes to the consolidated 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 15 to the consolidated 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, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.
Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, and may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt. It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur. See credit risk section for more related information.
Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.
Our utility operations are subject to long-term planning risks.
On a periodic basis, or as needed, our utility operations file long-term resource plans with our regulators. These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand.
Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel. 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, transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material 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’s difficult to predict the magnitude of such events and associated impacts.
We are subject to information security risks.
A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information. We are unable to quantify the potential impact of such an event.
Rising energy prices could negatively impact our business.
Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, 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 and natural gas utility businesses are seasonal businesses, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory, and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.
Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.
There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.
The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.
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 event 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 $266.2 million, $271.0 million and $263.9 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. The amount of dividends that we can pay is limited to some extent by our indenture for our first mortgage bonds.
Item 1B
Item 1B - Unresolved Staff Comments
None.
Item 2
Item 2 - Properties
Virtually all of the electric utility plant of PSCo is subject to the lien of its first mortgage bond indenture.
Electric utility generating stations:
(a) Construction of Comanche Unit 3, a 750 MW coal-fired unit, is expected to be completed in the first quarter of 2010. PSCo will own 500 MW of the completed unit.
(b) Based on PSCo’s ownership interest of 9.7 percent.
(c) Based on PSCo’s ownership interest of 75.5 percent of Unit 1 and 37.4 percent of Unit 2.
(d) Amount represents nameplate rating capacity.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2009:
PSCo had 221 electric utility transmission and distribution substations at Dec. 31, 2009.
Natural gas utility mains at Dec. 31, 2009:
Item 3
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against PSCo. After consultation with legal counsel, PSCo 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 15 to the consolidated 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 14 to the consolidated 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
PSCo is a wholly owned subsidiary of Xcel Energy and there is no market for its common equity securities.
PSCo had dividend restrictions imposed by its credit facility and FERC rules.
· PSCo’s credit facility includes a financial covenant that requires the equity-to-total capitalization ratio to be greater than or equal to 35 percent. PSCo was in compliance as its equity-to-total capitalization ratio was 56 percent and 58 percent at Dec. 31, 2009 and 2008, respectively.
· Dividends are also subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.
The 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 PSCo 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 PSCo 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 consolidated financial statements and notes to the consolidated 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 PSCo 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 PSCo; 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 PSCo in reports filed with the SEC, including “Risk Factors” in Item 1A of PSCo’s Form 10-K for the year ended Dec. 31, 2009 and Exhibit 99.01 to PSCo’s Form 10-K for the year ended Dec. 31, 2009.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Results of Operations
PSCo’s net income was approximately $323.3 million for 2009, compared with approximately $339.8 million for 2008.
Electric Revenues and Margin
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers, fluctuations in these costs do not materially affect electric margin.
Electric - The following tables detail the electric revenues and margin:
The following summarizes the components of the changes in electric revenues and margin for the year ended Dec. 31:
Electric Revenues
Electric Margin
Natural Gas Revenues and Margin
The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases. PSCo has a GCA mechanism for natural gas sales, which recognizes the majority of the effects of changes in the cost of natural gas purchased for resale and adjusts revenues to reflect such changes in costs upon request by PSCo. Therefore, fluctuations in the cost of natural gas have little effect on natural gas margin.
Natural Gas - The following table details the natural gas revenues and margin:
The following summarizes the components of the changes in natural gas revenues and margin for the year ended Dec. 31:
Natural Gas Revenues
Natural Gas Margin
Non-Fuel Operating Expenses and Other Items
Other Operating and Maintenance Expenses - Other operating and maintenance expenses increased by approximately $24.0 million, or 4.0 percent for 2009, compared to 2008. The following summarizes the components of the changes in other operating and maintenance expenses for the year ended Dec. 31:
Demand Side Management (DSM) Program Expenses - DSM program expenses increased by approximately $71.9 million for 2009, compared with 2008. The higher expense is attributable to the expansion of programs and regulatory commitments.
Depreciation and Amortization - Depreciation and amortization expense increased by approximately $3.7 million, or 1.5 percent, for 2009 compared with 2008. The increase is primarily due to planned system expansion.
Taxes (Other Than Income Taxes) - Taxes (other than income taxes) increased by approximately $11.0 million for 2009, compared with 2008. The increase is primarily due to an adjustment to 2009 accruals based on higher property value mill levy estimates received in 2009.
Other Income, net - Other income, net, decreased by approximately $12.1 million for 2009, compared with 2008. The decrease is primarily due to lower interest income, deferred compensation and a life insurance refund in 2008.
Interest Charges and Financing Costs - Interest charges and financing costs increased by approximately $11.9 million, or 7.7 percent, for 2009 compared with 2008. The increase is primarily due to the issuance of long-term debt.
Allowance for Funds Used During Construction, Equity and Debt (AFUDC) - AFUDC increased by approximately $5.1 million, or 9.5 percent, for 2009 compared with 2008. The increase is primarily due to the ongoing construction of Comanche 3, which is expected to be completed in the first quarter of 2010.
Income Taxes - Income tax expense increased by approximately $3.8 million for 2009, compared with 2008. The effective tax rate was 34.5 percent for 2009, compared with 32.9 percent for 2008. The increase in income tax expense and the higher effective tax rate for 2009 were primarily due to additional state unitary tax expense in 2009. If state unitary tax expense in 2008 would have been consistent with 2009, the effective tax rate for 2008 would have been 34.4 percent.
The effective tax rates for 2009 and 2008 differ from their statutory federal income tax rates, primarily due to state income tax expense partially offset by tax credits recognized and tax benefit from plant related regulatory differences. See Note 8 to the consolidated 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, PSCo 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. Market risks associated with derivatives are discussed in further detail in Note 11 to the consolidated financial statements.
PSCo is exposed to the impact of changes in price for energy and energy-related products, which is partially mitigated by PSCo’s use of commodity derivatives. Though no material non-performance risk currently exists with the counterparties to PSCo’s commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securities in the master pension trust, as well as PSCo’s ability to earn a return on short-term investments of excess cash.
Commodity Price Risk - PSCo is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. PSCo’s 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 - PSCo conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. PSCo’s risk management policy allows management to conduct the marketing 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.
Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec. 31 were as follows:
At Dec. 31, 2009, the fair values by source for the commodity trading net asset balances were as follows:
1 - Prices actively quoted or based on actively quoted prices.
- Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.
Normal purchases and sales transactions, as defined by ASC 815 Derivatives and Hedging, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.
At Dec. 31, 2009, a 10 percent increase in market prices over the next 12 months for commodity trading contracts would decrease pretax income from continuing operations by approximately $0.1 million, whereas a 10 percent decrease would increase pretax income from continuing operations by approximately $0.1 million.
PSCo’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR). VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis, were as follows:
Interest Rate Risk - PSCo is subject to the risk of fluctuating interest rates in the normal course of business. PSCo’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.
At Dec. 31, 2009, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $1.8 million annually. See Note 11 to the consolidated financial statements for a discussion of PSCo’s interest rate derivatives.
Credit Risk - PSCo is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance of their contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
At Dec. 31, 2009, a 10 percent increase in prices would have resulted in an increase in credit exposure of $23.0 million, while a decrease of 10 percent in prices would have resulted in an increase in credit exposure of $2.4 million.
PSCo conducts standard credit reviews for all counterparties. PSCo 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 financial markets could increase PSCo’s credit risk.
Fair Value Measurements
PSCo adopted new accounting and disclosure guidance on fair value measurements on Jan. 1, 2008 which established a hierarchy for inputs used in measuring fair value, and generally requires that the most observable inputs available be used for fair value measurements. Note 13 to the consolidated financial statements describes the fair value hierarchy, and discloses the amounts of assets and liabilities measured at fair value that have been assigned to Level 3.
Commodity Derivatives - PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2009. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for this credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2009.
Commodity derivatives assets and liabilities assigned to Level 3 consist primarily of forwards and options that are either long-term in nature or related to certain commodities and delivery points with limited observability. Level 3 commodity derivative assets and liabilities represent approximately 17 percent and 14 percent of total assets and liabilities measured at fair value, respectively, at Dec. 31, 2009.
Determining the fair value of these commodity forwards and options can require management to make use of subjective forward price and volatility forecasts for commodities and locations with limited observability, or subjective forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. Level 3 commodity derivatives assets and liabilities include $2.5 million and $1.7 million of estimated fair values, respectively, for commodity forwards and options held at Dec. 31, 2009.
Item 8
Item 8 - Financial Statements and Supplementary Data
See Item 15 -1 in Part IV for an index of financial statements included herein.
See Note 19 to the consolidated financial statements for summarized quarterly financial data.
Management Report on Internal Controls Over Financial Reporting
The management of PSCo is responsible for establishing and maintaining adequate internal control over financial reporting. PSCo’s 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.
PSCo 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.
PSCo’s independent auditors have issued an audit report on the company’s internal control over financial reporting. Their report appears herein.
/S/ DAVID L. EVES
/S/ DAVID M. SPARBY
David L. Eves
David M. Sparby
President and Chief Executive Officer
Vice President and Chief Financial Officer
March 1, 2010
March 1, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholder
Public Service Company of Colorado
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated 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 consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their 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 consolidated 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, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholder
Public Service Company of Colorado
We have audited the internal control over financial reporting of Public Service Company of Colorado and subsidiaries (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 consolidated 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, 2010
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(amounts in thousands of dollars)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands of dollars)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(amounts in thousands of dollars)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME
(amounts in thousands of dollars, except share data)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands of dollars)
(a) Pollution control financing
See Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Business and System of Accounts - PSCo is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. PSCo is subject to regulation by the FERC and the CPUC. All of PSCo’s 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.
Principles of Consolidation - PSCo has subsidiaries, which have been consolidated and for which all intercompany transactions and balances have been eliminated.
Revenue Recognition - Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their 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. PSCo presents its revenue net of any excise or other fiduciary-type taxes or fees.
PSCo has various rate-adjustment mechanisms in place that currently provide for the recovery of natural gas and 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:
· PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through the ECA for the company’s retail jurisdiction. The ECA mechanism was extended in 2009 and went into effect in January 2010. The ECA allows for sharing of margins on short term energy sales.
· PSCo generally recovers all purchased capacity costs through the PCCA for the company’s retail jurisdiction. The PCCA mechanism is revised annually. The PCCA was recently extended by CPUC order in PSCo’s most recent rate case.
· PSCo’s rates include annual adjustments for the recovery of conservation and energy-management program costs, as well as a financial incentive based on its performance in achieving established goals. PSCo is allowed to recover certain costs associated with renewable energy resources through a specific retail rate rider. In January 2008, a new recovery mechanism for transmission commenced. The TCA permits PSCo to recover costs associated with investment in transmission facilities made after March 2007 through a rate rider.
· PSCo 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 consolidated statements of income.
Pursuant to the JOA approved by the FERC, some of the commodity trading margins from PSCo are apportioned to NSP-Minnesota and SPS. Commodity trading activities are not associated with energy produced from PSCo’s 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 11 to the consolidated financial statements.
Fair Value Measurements - PSCo presents cash equivalents, interest rate derivatives, and commodity derivatives at estimated fair values in its consolidated 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 as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, PSCo may use quoted prices for similar contracts, or internally prepared valuation models as primary inputs to determine fair value.
Types of and Accounting for Derivative Instruments - PSCo uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by ASC 815 Derivatives and Hedging, are recorded on the consolidated 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; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; hedge transactions for vehicle fuel costs are recorded as a component of capital projects or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense. PSCo is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.
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. PSCo 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, PSCo 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. PSCo 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 - PSCo 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 as normal purchases or normal sales.
PSCo 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 PSCo’s risk management and derivative activities see Note 11 to the consolidated 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.
PSCo 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 percent, 2.7 percent and 2.7 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 PSCo’s rate base for establishing utility service rates.
Environmental Costs - Environmental costs are recorded when it is probable PSCo 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 PSCo’s expected share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.
Legal Costs - Litigation accruals are recorded when it is probable PSCo is liable for the costs and the liability can be reasonably estimated. External legal fees related to settlements are expensed as incurred.
Income Taxes - PSCo 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. PSCo defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. PSCo 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 16 to the consolidated financial statements. For more information on income taxes, see Note 8 to the consolidated financial statements.
PSCo follows the guidance in ASC 740 Income Taxes to measure and disclose uncertain tax positions that PSCo has taken or expects to take in its income tax returns. In accordance with this guidance, PSCo recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.
PSCo reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.
Xcel Energy and its subsidiaries, including PSCo, 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, PSCo 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 - PSCo 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 inventories are recorded at average cost.
Regulatory Accounting - PSCo 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, PSCo 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 PSCo’s results of operations in the period the write-off is recorded. See more discussion of regulatory assets and liabilities at Note 16 to the consolidated financial statements.
Deferred Financing Costs - Other assets included deferred financing costs, net of amortization, of approximately $17.5 million and $16.4 million at Dec. 31, 2009 and 2008, respectively. PSCo 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. PSCo 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, PSCo 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.
Emission Allowances - Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA. PSCo follows the inventory accounting model for all allowances. The sales of allowances are reported in the operating activities section of the consolidated 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 depreciation and amortization within the consolidated statements of cash flows. Pension and employee benefit obligations were reclassified as a separate item from change in other noncurrent liabilities within the consolidated statements of cash flows. The reclassifications did not have an impact on 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 consolidated 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. PSCo implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated 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. PSCo implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated 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. PSCo implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 11 to the consolidated 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. PSCo implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated 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. PSCo implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated 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. PSCo implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated 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. PSCo 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 PSCo’s consolidated 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 expands 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. PSCo implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements. For further discussion and the required disclosures, see Note 9 to the consolidated 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. PSCo implemented the guidance on Sept. 1, 2009, and the implementation did not have a material impact on its consolidated 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. PSCo does not expect the implementation of the guidance to have a material impact on its consolidated 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. PSCo does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.
3. Selected Balance Sheet Data
4. Short-Term Borrowings
Commercial Paper - At Dec. 31, 2009 and 2008, PSCo had commercial paper outstanding of approximately $95.0 million and $40.0 million, respectively. PSCo has approval by the Board of Directors to issue up to $700 million of commercial paper. The weighted average interest rates at Dec. 31, 2009 and 2008 were 0.35 percent and 1.55 percent, respectively.
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. PSCo has approval to borrow up to $250 million under the arrangement. At Dec. 31, 2009 and 2008, PSCo had money pool borrowings of $84.0 million and $41.0 million, respectively. The weighted average interest rates at Dec. 31, 2009 and 2008 were 0.36 percent and 3.48 percent, respectively.
5. Long-Term Debt
Credit Facilities - At Dec. 31, 2009, PSCo 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. PSCo 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 PSCo’s debt-to-total capitalization ratio be less than or equal to 65 percent. PSCo was in compliance as its debt-to-total capitalization ratio was 45 percent and 42 percent at Dec. 31, 2009 and 2008, respectively. If PSCo 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 credit facility has a cross default provision that provides the borrower will be in default on its borrowings under the facility if any of its subsidiaries, comprising more than 15 percent of the consolidated assets, defaults on any of its indebtedness greater than $50 million.
· The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as based on PSCo’s senior unsecured credit ratings from Moody’s, Standard & Poor’s and Fitch. Based on PSCo’s current credit ratings the borrowing margin is 35 points. The commitment fees are calculated for the unused portion of the credit facility at 8 basis points for PSCo.
· At Dec. 31, 2009, PSCo had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $95.0 million of commercial paper outstanding and $4.6 million of letters of credit. At Dec. 31, 2008, PSCo had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $40.0 million of commercial paper outstanding and $4.9 million of letters of credit.
Long-Term Borrowings
In June 2009, PSCo issued $400 million of 5.125 percent first mortgage bonds, series due 2019. PSCo added the proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the net proceeds to fund the payment at maturity of $200 million of 6.875 percent unsecured senior notes due July 15, 2009.
In August 2008, PSCo issued $300 million of 5.80 percent first mortgage bonds, series due Aug. 1, 2018 and $300 million of 6.50 percent first mortgage bonds, series due Aug. 1, 2038. PSCo added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of such net proceeds to fund the payment at maturity of $300 million of 4.375 percent first mortgage bonds due Oct. 1, 2008.
Maturities of long-term debt are:
6. Preferred Stock
PSCo has authorized the issuance of preferred stock.
7. Joint Plant Ownership
Following are the investments by PSCo in jointly owned plants and the related ownership percentages as of Dec. 31, 2009:
PSCo’s current operational assets include approximately 320 MWs of jointly owned generating capacity, excluding Comanche Unit 3. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for the issuance of its own securities to finance its portion of the construction costs. PSCo began major construction on a new jointly owned 750 MW, coal-fired unit in Pueblo, Colo. in January 2006. Major construction on the new unit, Comanche Unit 3, was still underway in 2009 and in-service is expected by the end of the first quarter of 2010. The plant experienced certain boiler tube leaks in the start-up process that are being resolved. PSCo is the operating agent under the joint ownership agreement.
8. Income Taxes
COLI - In 2007, Xcel Energy and the U.S. government settled an ongoing dispute regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. These COLI policies were owned and managed by PSRI, a wholly owned subsidiary of PSCo. The total exposure for the tax years in dispute through 2007 was approximately $583 million, which includes income tax, interest and potential penalties. As a result of the settlement, the lawsuit filed by Xcel Energy in the United States District Court has been dismissed and the Tax Court proceedings are in the process of being dismissed. We anticipate these proceedings to be dismissed in 2010.
Terms of the Final Settlement
1. Xcel Energy paid the government a total of $64.4 million in full settlement of the government’s claims for tax, penalty, and interest for tax years 1993-2007.
2. The recognition of this settlement resulted in total expense of $59.5 million, including federal and state tax, interest on the federal and state tax liabilities, penalties, and tax benefits on the interest expense for the nine months ended Sept. 30, 2007. The expense of $59.5 million includes $43.4 million of interest and penalties and income tax of $16.1 million (net of tax benefit on the interest expense of $14.3 million).
3. Xcel Energy surrendered the policies to its insurer on Oct. 31, 2007, without recognizing a taxable gain.
Federal Audit - PSCo 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 - PSCo is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2009, PSCo’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.
Unrecognized Tax Benefits - The amount of unrecognized tax benefits was $7.2 million and $10.3 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 unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryovers of $4.0 million and $5.8 million on Dec. 31, 2009 and Dec. 31, 2008, respectively.
The unrecognized tax benefit balance included $1.0 million and $1.4 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 $6.2 million and $8.9 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 $3.1 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. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months when the IRS and 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 2016 and 2029.
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) at Dec. 31 were as follows:
9. Benefit Plans and Other Postretirement Benefits
Pension and other postretirement disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to PSCo.
Xcel Energy, which includes PSCo, offers various benefit plans to its employees. At Dec. 31, 2009, PSCo had 2,124 bargaining employees covered under a collective-bargaining agreement, which expires in May 2014.
Effective Jan. 1, 2009, Xcel Energy and PSCo 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 PSCo, 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 PSCo’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 PSCo base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the 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 PSCo continually review the 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 PSCo’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 allocations for 2009 and 2008:
In 2009, Xcel Energy and PSCo 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. 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 PSCo, 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 PSCo, 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, which includes PSCo, maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for PSCo were approximately $6.4 million in 2009, $6.1 million in 2008 and $7.9 million in 2007.
Postretirement Health Care Benefits
Xcel Energy, which includes PSCo, has a contributory health and welfare benefit plan that provides health care and death benefits to most retirees. Employees of the former New Century Energies, Inc. (NCE) who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE, who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
In 1993, Xcel Energy and PSCo 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. PSCo transitioned to full accrual accounting for postretirement benefit costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional postretirement benefit costs deferred during the transition period are being amortized to expense on a straight-line basis over the 15-year period from 1998 to 2012.
Plan Assets - Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. PSCo is required to fund postretirement benefit costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits. 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 PSCo base the 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 PSCo’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 and PSCo 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 PSCo 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 PSCo:
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 PSCo, contributed $62.2 million during 2009 and $55.6 million in 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.
10. Other Income (Expense), Net
Other income (expense), net for the years ended Dec. 31 consisted of the following:
11. Derivative Instruments
Effective Jan. 1, 2009, PSCo 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 consolidated balance sheet for derivatives, the gains and losses on derivative instruments included in the consolidated statement of income or deferred, and information regarding certain credit-risk-related contingent features in derivative contracts.
PSCo enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices. See additional information pertaining to the valuation of derivative instruments in Note 13 to the consolidated financial statements.
Interest Rate Derivatives - PSCo enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes.
At Dec. 31, 2009, accumulated other comprehensive income related to interest rate derivatives included $1.5 million of net gains expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.
Commodity Derivatives - PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale, and vehicle fuel.
At Dec. 31, 2009, PSCo had vehicle fuel contracts designated as cash flow hedges extending through December 2012. PSCo also enters into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. PSCo recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the years ended Dec. 31, 2009 and 2008.
At Dec. 31, 2009, accumulated other comprehensive income related to vehicle fuel cash flow hedges included $1.2 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.
Additionally, PSCo enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in income subject to applicable customer margin-sharing mechanisms.
PSCo had no derivative instruments designated as fair value hedges during the year ended Dec. 31, 2009. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for the period.
The following table shows the major components of derivative instruments valuation in the consolidated 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, PSCo 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, PSCo 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 and vehicle fuel cash flow hedges on PSCo’s accumulated other comprehensive income, included as a component of common stockholder’s equity, is detailed in the following tables:
The following table details the fair value of commodity derivatives recorded to derivative instruments valuation in the consolidated balance sheet, by category:
(a) ASC 815, Derivatives and Hedging, permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between PSCo and a counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.
The following table details the impact of derivative activity during the year ended Dec. 31, 2009, on other comprehensive income, regulatory assets and liabilities, and income:
(a) Recorded to other operating and maintenance expenses.
(b) Recorded to electric operating revenues. Portions of these gains and losses are shared with electric customers through margin-sharing mechanisms and deducted from gross income, as appropriate.
(c) Recorded to cost of natural gas sold and transported; these derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(d) Recorded to interest charges.
At Dec. 31, 2009, commodity derivatives recorded to derivative instruments valuation included derivative contracts with gross notional amounts of approximately 3,559,000 megawatt (MW) hours of electricity, 45,352,000 MMBtu of natural gas, and 1,559,000 gallons of vehicle fuel. These amounts reflect the gross notional amounts of futures and forwards, and are not reflective of net positions in the underlying commodities. Notional amounts for options are also included on a gross basis, but are weighted for the probability of exercise.
Credit Related Contingent Features - Contract provisions of PSCo’s derivative instruments may require the posting of collateral or settlement of the contracts for various reasons, including if PSCo is unable to maintain its credit rating. If the credit rating of PSCo at Dec. 31, 2009 were downgraded below investment grade, contracts underlying $0.6 million of derivative instruments in a liability position would have required PSCo to post collateral or settle applicable contracts, which would have resulted in payments to counterparties of $3.4 million. At Dec. 31, 2009, there was no collateral posted on these specific contracts.
Certain of PSCo’s derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that PSCo’s ability to fulfill its contractual obligations is reasonably expected to be impaired. As of Dec. 31, 2009, PSCo had no collateral posted related to adequate assurance clauses in derivative contracts.
12. Financial Instruments
The estimated Dec. 31 fair values of PSCo’s recorded financial instruments are as follows:
The fair value 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 PSCo’s other investments is estimated based on quoted market prices for those or similar investments. The fair value of PSCo’s 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 consolidated financial statements since that date and current estimates of fair values may differ significantly.
Letters of Credit
PSCo use 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 $4.6 million and $4.9 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.
13. Fair Value Measurements
Effective Jan. 1, 2008, PSCo 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, such as commodity derivative contracts listed on the New York Mercantile Exchange.
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 contracts, such as energy forwards with pricing interpolated from recent trades at a similar location, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
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, such as the long-term commodity price forecasts used to determine the fair value of long-term energy forwards.
PSCo continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of PSCo’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities presented in the consolidated balance sheets.
The following tables present, for each of these hierarchy levels, PSCo’s assets and liabilities that are measured at fair value on a recurring basis:
The following table presents the changes in Level 3 recurring fair value measurements for the year ended Dec. 31:
Gains on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2009, include $2.6 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2009. Losses on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2008, include $0.8 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2008. Realized and unrealized gains and losses on commodity trading activities are included in electric utility revenues. Realized and unrealized gains and losses on short-term wholesale activities reflect the impact of regulatory recovery and are deferred as regulatory assets and liabilities.
14. Rate Matters
Pending and Recently Concluded Regulatory Proceedings - CPUC
Base Rate
PSCo 2009 Electric Rate Case - In November 2008, PSCo filed a request with the CPUC to increase Colorado electric rates by $174.7 million annually, or approximately 7.4 percent. The rate filing was based on a 2009 forecast test year, an electric rate base of $4.2 billion, a requested ROE of 11.0 percent and an equity ratio of 58.08 percent. PSCo’s request included a return of approximately $40 million for CWIP associated with incremental expenditures on the Comanche Unit 3 since Jan. 1, 2007. PSCo does not record AFUDC income for the months this return is actually received from customers.
In March 2009, PSCo filed rebuttal testimony and revised its rate increase request to $159.3 million to reflect updated data. In May 2009, the CPUC approved a blackbox settlement agreement which provided for an overall $112.2 million increase in base rates. The settlement provides that incremental CWIP not included in existing rates for the Comanche Unit 3 be removed from rate base and that PSCo would be allowed to continue to record AFUDC income on this balance until the Comanche Unit 3 is placed into service. New rates went into effect on July 1, 2009.
PSCo 2010 Electric Rate Case - In May 2009, PSCo filed with the CPUC a request to increase Colorado electric rates by $180.2 million, or 6.8 percent, effective in 2010. The request was based on a 2010 forecast test year, an 11.25 percent ROE, a rate base of $4.4 billion and an equity ratio of 58.05 percent, In October 2009, PSCo filed rebuttal testimony and revised the requested rate increase to $177.4 million.
In November 2009, PSCo reached a settlement agreement with certain intervenors. The settlement included an electric rate increase of approximately $136 million, effective Jan. 1, 2010. The settlement was based on a 10.5 percent ROE and reflects PSCo’s actual capital structure. The settlement was based on an historic test year, adjusted for 2010 known and measurable changes related to plant investment as well as certain operating costs.
In December 2009, the CPUC approved a rate increase of approximately $128.3 million. The difference between the settlement rate increase and the approved amount was primarily related to adjustments related to rate base for non-major projects and an adjustment to interest on long-term debt.
In December 2009, due to the delay in Comanche Unit 3 coming online, the CPUC approved PSCo’s proposal to phase in the approved electric rate increase to reflect the actual cost of service. This decision is not expected to have a material impact on PSCo or Xcel Energy’s financial results. Under the plan the following increases will be implemented:
· A rate increase of $67 million was implemented on Jan. 1, 2010. The adjustments to the rate increase, as a result of the delay of the in-service date of Comanche Unit 3, include reduced O&M, property taxes, the impact of a delay in changes to jurisdictional allocators and depreciation expenses.
· Base rates will increase to $121 million, once Comanche Unit 3 goes into service (currently expected by the end of the first quarter of 2010).
· Finally, base rates will increase to $128.3 million on Jan. 1, 2011 to reflect 2011 property taxes.
Several parties, including the Office of Consumer Counsel, have filed motions for reconsideration. The CPUC has denied those requests that would change the initial order approving the rate increase, with the exception of PSCo’s request to not include long-term debt interest in the working capital calculation. The CPUC will reconsider PSCo’s request after parties have filed additional comments. A written order is pending.
Unreasonable Rates for Natural Gas Formal Complaint - In July 2009, the trial advocacy staff of the CPUC proposed a formal draft complaint against PSCo for unjust and unreasonable rates for natural gas service associated with earnings in excess of PSCo’s authorized return that occurred in 2008. In January 2010, the CPUC opened a proceeding and assigned this matter to an ALJ.
The procedural schedule in the case has been set as follows:
· Direct testimony of CPUC staff on May 10, 2009;
· PSCo answer testimony on June 28, 2010;
· Staff rebuttal testimony on July 19, 2010;
· Surrebuttal testimony on Aug. 9, 2010; and
· Hearings on Aug. 23 - 27, 2010.
TCA Rider - PSCo filed its annual update to the TCA rider in November 2008, and new rates went into effect on Jan. 1, 2009, to recover approximately $18.0 million on an annual basis until the rates in the 2009 rate case take effect. Coincident with the implementation of new electric rates on July 1, 2009, approximately $16.0 million from the TCA rider were included in base rates with a corresponding reduction in the TCA rider.
Renewable Energy Credit (REC) Sharing Settlement - In August 2009, PSCo filed an application seeking approval of treatment of margins associated with certain sales of Colorado RECs bundled with energy into California. PSCo’s request sought 45 percent of the margins on these specific transactions for both the customers and PSCo with the remaining ten percent being used to fund a program to develop carbon offset projects and expertise. On Jan. 20, 2010, PSCo, the Office of Consumer Council, the CPUC staff, the Colorado governor’s energy office and Western Resource Advocates entered into a unanimous settlement in this case. The settlement establishes a pilot program and defines certain margin splits during this pilot period. The settlement provides that 10 percent of margins will go to carbon offsets, 40 percent of the first $10 million in margins, 35 percent of the next $20 million and 30 percent of all remaining margins will go to PSCo with all remaining margins going to Colorado retail the customers as a credit toward renewable energy projects. The unanimous settlement also clarified that margins associated with RECs bundled with Colorado energy would be shared 20 percent to PSCo and 80 percent to customers and margins associated with sales of stand-alone renewable energy credits without energy would be credited 100 percent to customers. It is expected that PSCo will file an application by Aug. 31, 2010 for future treatment of margins from transactions for RECs bundled with energy after the end of the pilot program. On Feb. 18, 2010, the CPUC approved the settlement.
Pending and Recently Concluded Regulatory Proceedings - FERC
Pacific Northwest FERC Refund Proceeding - In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001. PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence. Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million. In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the U. S. Court of Appeals for the Ninth Circuit.
In an order issued in August 2007, the Court of Appeals remanded the proceeding back to the FERC. The Court of Appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets. The Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued. The FERC has yet to act on this order on remand; currently, certain motions concerning procedures on remand are pending before the FERC.
Wholesale Rate Case - In 2009, PSCo proposed to increase Colorado wholesale rates by $30 million based on a 12.5 percent ROE, a 58 percent equity ratio and an electric production rate base of $315 million. PSCo has requested that FERC suspend action on the filing to allow time for settlement negotiations. Settlement discussions with PSCo’s wholesale customers are continuing. PSCo expects rates subject to refund to go into effect in the second quarter of 2010.
15. Commitments and Contingent Liabilities
Capital Commitments - As of Dec. 31, 2009, the estimated cost of the capital expenditure programs and other capital requirements of PSCo is approximately $610 million in 2010, $600 million in 2011 and $710 million in 2012.
The capital expenditure programs of PSCo are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth regulatory decisions, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting PSCo’s long-term energy needs. In addition, PSCo’s ongoing evaluation of compliance with future requirements to install emission-control equipment and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.
Fuel Contracts - PSCo 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 2040. In addition, PSCo 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 to customers.
The estimated minimum purchases for PSCo under these contracts as of Dec. 31, 2009, are as follows:
Purchased Power Agreements - PSCo 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. PSCo has various pay-for-performance contracts with expiration dates through the year 2033. 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 PSCo is obligated to purchase, subject to availability, were as follows:
Leases - PSCo leases a variety of equipment and facilities used in the normal course of business. Three of these leases qualify as capital leases and are accounted for accordingly. The assets and liabilities acquired under capital leases are recorded at the lower of fair-market value or the present value of future lease payments and are amortized over their actual contract term in accordance with practices allowed by regulators.
In 1999, WYCO was formed as a joint venture between Xcel Energy and Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. In 2009, WYCO’s Totem gas storage facilities were placed in service. WYCO leases the facilities to CIG, and CIG operates the facilities, providing natural gas storage services to PSCo under a service arrangement that commenced on July 1, 2009.
PSCo accounts for its Totem natural gas storage service arrangement with CIG as a capital lease in accordance with the authoritative guidance on lease accounting. As a result, PSCo has a $141.1 million capital lease obligation, net of amortization, recorded for the arrangement as of Dec. 31, 2009. WYCO is expected to incur approximately $14 million of additional construction costs, 50 percent of which will be paid by Xcel Energy, to finalize construction and make Totem operational at full storage capacity.
Following is a summary of assets held under capital leases:
The remainder of the leases, primarily for office space, railcars, generating facilities, trucks, cars and power-operated equipment are accounted for as operating leases. Total rental expense under operating lease obligations was approximately $80.9 million, $85.6 million and $44.6 million for 2009, 2008 and 2007, respectively. Included in total rental expense were purchase power agreement payments of $64.8 million, $67.5 million and $26.1 million in 2009, 2008 and 2007, respectively.
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 and capital leases are:
(a) Amounts not included in purchase power agreement estimated future payments above.
(b) Purchase power agreeement operating leases contractually expire through 2028.
Environmental Contingencies
PSCo has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, PSCo believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, PSCo is pursuing, or intends to pursue, recovery from other PRPs and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for PSCo, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, PSCo would be required to recognize an expense.
Site Remediation - PSCo must pay all or a portion of the cost to remediate sites where past activities of PSCo or other parties have caused environmental contamination. Environmental contingencies could arise from various situations including sites of former MGPs operated by PSCo, its predecessors, or other entities; and third party sites, such as landfills, to which PSCo 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 $0.9 million, of which $0.3 million was considered to be a current liability.
Asbestos Removal - Some of PSCo’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated. PSCo 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 GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs 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.
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 PSCo generating facilities will be subject to BART requirements.
States are required to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities. In May 2006, the Colorado Air Quality Control Commission (AQCC) promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal. PSCo estimates that the remaining cost for implementation of BART emission control projects is approximately $141 million in capital costs, which are included in the capital budget.
PSCo expects the cost of any required capital investment will be recoverable from customers. Emissions controls are expected to be installed between 2012 and 2015. Colorado’s BART state implementation plan has been submitted to the EPA for approval. In January 2009, the Colorado Air Pollution Control Division (CAPCD) initiated a joint stakeholder process to evaluate what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado’s Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals. The CAPCD has indicated that it expects to have a final plan for additional point-source NOx controls by the end of 2010.
CAMR - In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. 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 mercury legislation and 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 PSCo, anticipates that the EPA will require affected facilities to demonstrate compliance within 18 to 36 months thereafter.
Colorado Mercury Regulation - In Colorado, AQCC passed a mercury rule, which requires mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 2012 and other specified units by 2014. The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for absorbent expense. PSCo is evaluating the emission controls required to meet the state rule for the remaining units and is currently unable to provide a total capital cost estimate.
Federal Clean Water Act - The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts. In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants. Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit (Court of Appeals) challenging the phase II rulemaking. In January 2007, the Court of Appeals issued its decision and remanded the rule to the EPA for reconsideration. In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the remand. In April 2008, the U. S. Supreme Court granted limited review of the Second Circuit’s opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA. On April 1, 2009, the U. S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA. The decision overturned only one aspect of the Court of Appeals, earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules. Until the EPA fully responds to the Court of Appeals’ decision, the rule’s compliance requirements and associated deadlines will remain unknown. As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.
Notice of Violation (NOV) - In July 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station in Colorado. The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo believes it has acted in full compliance with the CAA and NSR process. PSCo believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position.
Asset Retirement Obligations
PSCo 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, electric transmission and distribution and natural gas distribution. The steam production obligation includes asbestos, ash-containment facilities and radiation sources. The asbestos recognition associated with the steam production includes certain plants at PSCo. Generally, this asbestos abatement removal obligation originated in 1973 with the Clean Air Act, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for PSCo 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. Additional AROs have been recorded for steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.
PSCo recognized an ARO for the retirement costs of its natural gas mains and for the removal of electric, transmission and distribution equipment. 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 and natural gas 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 PSCo’s AROs is shown in the table below for the 12 months ended Dec. 31, 2009 and 2008, respectively:
PSCo revised ash-containment facilities, radiation sources and electric transmission and distribution asset retirement obligations due to new estimates and end of life dates.
Indeterminate AROs - PSCo has underground natural gas storage facilities that have special closure requirements for which the final removal date cannot be determined, therefore an ARO has not been recorded.
Removal Costs - PSCo 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, PSCo 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 $375 million and $379 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 PSCo’s 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 PSCo, 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 the 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 PSCo, 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 PSCo, 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.
Comanche Unit 3 CAA Lawsuit - On July 2, 2009, WildEarth Guardians (WEG) filed a lawsuit against PSCo alleging that PSCo violated the CAA by constructing Comanche Unit 3 without a final MACT determination from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD). The state has proposed a more stringent case-by-case MACT determination for Comanche Unit 3 that, if final, could increase the operating costs of Comanche Unit 3. PSCo disputes these claims and has filed a motion to dismiss the suit. Comanche Unit 3 was constructed with state-of-the-art emission controls and pursuant to a valid air permit issued by the APCD. On Oct. 28, 2009, WEG filed a motion for a preliminary injunction, seeking to enjoin PSCo from constructing, modifying, or operating Comanche Unit 3 prior to receiving a final MACT determination. PSCo strongly opposes the injunction. Among other issues, PSCo believes that WEG has failed to establish a substantial likelihood of prevailing on the merits of the suit and that therefore there is no valid legal basis upon which an injunction should be issued. The court has yet to rule on WEG’s motion and the group sought a temporary restraining order to stop Comanche Unit 3 from coming on-line. The court denied WEG’s request for a temporary restraining order on Jan. 26, 2010. On Feb. 23, 2010, the court held a hearing on PSCo’s motion to dismiss. It is uncertain when the court will render a decision.
Employment, Tort and Commercial Litigation
Qwest vs. Xcel Energy Inc. - In 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned. In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver. In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million. On April 30, 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo. Qwest filed a petition for rehearing with the Colorado Supreme Court in June 2009. On Feb. 22, 2010 issued a ruling where it will review the Court of Appeals’ decision as to the punitive damages issue and will not review the Court of Appeals’ decision as it relates to PSCo.
Mallon vs. Xcel Energy Inc. - In August 2007, Xcel Energy, PSCo and PSR Investments, Inc. (PSRI) ( hereafter “ Plaintiffs”) commenced a lawsuit in Colorado state court against Theodore Mallon and TransFinancial Corporation seeking damages for, among other things, breach of contract and breach of fiduciary duties associated with the sale of COLI policies. In May 2008, Plaintiffs filed an amended complaint that, among other things, adds Provident Life & Accident Insurance Company (Provident) as a defendant and asserts claims for breach of contract, unjust enrichment and fraudulent concealment against the insurance company. On June 23, 2008, Provident filed a motion to dismiss the complaint. On Oct. 22, 2008, the court granted Provident’s motion in part, but denied the motion with respect to a majority of the core causes of action asserted by Plaintiffs. In September 2009, Plaintiffs reached a settlement with Mallon and TransFinancial Corporation. Pursuant to the terms of the agreement, Mallon agreed to pay Plaintiffs a specified amount and the parties agreed to mutually release each other from all claims. Plaintiffs continue to prosecute their claims against Provident. In November 2009, Plaintiffs and Provident filed motions for partial summary judgment, which the court subsequently granted in part in favor of Plaintiffs with respect to an interpretation of the policies. On Feb. 11, 2010, the court denied Provident’s motion for partial summary judgment. Trial for this lawsuit was continued to Aug. 16, 2010.
Cabin Creek Hydro Generating Station Accident - In October 2007, employees of RPI Coatings Inc. (RPI), a contractor retained by PSCo, were applying an epoxy coating to the inside of a penstock at PSCo’s Cabin Creek Hydro Generating Station near Georgetown, Colo. A fire occurred inside a pipe used to deliver water from a reservoir to the hydro facility. Five RPI employees were unable to exit the pipe and rescue crews confirmed their deaths. The accident was investigated by several state and federal agencies, including the federal Occupational Safety and Health Administration (OSHA) and the U. S. Chemical Safety Board and the Colorado Bureau of Investigations.
In March 2008, OSHA proposed penalties totaling $189,900 for twenty-two serious violations and three willful violations arising out of the accident. In April 2008, Xcel Energy notified OSHA of its decision to contest all of the proposed citations. On May 28, 2008, the Secretary of Labor filed its complaint, and Xcel Energy subsequently filed its answer on June 17, 2008. The Court ordered this proceeding stayed until March 3, 2009 and subsequently extended the stay to October 2009. The Court is currently considering whether to extend the stay.
A lawsuit was filed in Colorado state court in Denver on behalf of four of the deceased workers and four of the injured workers (Foster, et. al. v. PSCo, et. al.). PSCo and Xcel Energy were named as defendants in that case, along with RPI Coatings and related companies and the two other contractors who also performed work in connection with the relining project at Cabin Creek. A second lawsuit (Ledbetter et. al vs. PSCo et. al) was also filed in Colorado state court in Denver on behalf of three employees allegedly injured in the accident. A third lawsuit was filed on behalf of one of the deceased RPI workers in the California state court (Aguirre v. RPI, et. al.), naming PSCo, RPI, and the two other contractors as defendants. The court subsequently dismissed the Aguirre lawsuit. Settlements were subsequently reached in all three lawsuits. These confidential settlements are not expected to have a material effect on the financial statements of Xcel Energy or its subsidiaries.
On Aug. 28, 2009, the U. S. Government announced that Xcel Energy and PSCo have been charged with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007. RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI have also been indicted. On Sept. 22, 2009, both Xcel Energy and PSCo entered a not guilty plea, and both will vigorously defend against these charges. In December 2009, Xcel Energy and PSCo filed two separate motions to dismiss. It is uncertain when the court will rule on these motions.
Stone & Webster, Inc. vs. PSCo - On July 14, 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal fired plant in Pueblo, Colo. Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleges, among other things, that PSCo was responsible for and mismanaged the construction of Comanche Unit 3. Shaw further claims that this alleged mismanagement caused delays and damages in excess of $55 million. The complaint also alleges that Xcel Energy and related entities, including PSCo, guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement. Shaw alleges that it will not receive the $10 million to which it is entitled. Accordingly, Shaw seeks an amount up to $10 million relating to the 2003 settlement agreement. PSCo denies these allegations and believes the claims are without merit. PSCo filed an answer and counterclaim in August 2009, denying the allegations in the complaint and alleging that Shaw has failed to discharge its contractual obligations and has caused delays, and that PSCo is entitled, among other things, to liquidated damages and excess costs incurred. It is not anticipated that this lawsuit will affect Comanche Unit 3’s scheduled in-service date.
Connie DeWeese vs. PSCo - In November 2008, there was an explosion in Pueblo, Colo. which destroyed a tavern and a neighboring store. The explosion killed one person and injured seven people. The Pueblo Fire Department and the Federal Bureau of Alcohol, Tobacco and Firearms (ATF) have determined a natural gas leak from a pipeline under the street led to the explosion, stating that natural gas passed through the soil and built up in the tavern’s basement. On Feb. 8, 2010 a wrongful death lawsuit was filed in Colorado District Court in Pueblo, Colorado against PSCo and the City of Pueblo by several parties that were allegedly injured, as a result of this explosion. The plaintiffs are also alleging economic and noneconomic damages. Among other things, the lawsuit alleges that the accident occurred as a result of PSCo’s negligence. PSCo denies liability for this accident and intends to file an answer to the complaint on or before March 1, 2010.
16. Regulatory Assets and Liabilities
PSCo’s consolidated financial statements are prepared in accordance with the provisions of ASC 980 Regulated Operations, as discussed in Note 1 to the consolidated 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 and natural gas rates. Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of PSCo no longer allow for the application of regulatory accounting guidance under GAAP, PSCo would be required to recognize the write-off of regulatory assets and liabilities in its consolidated statement of income.
The components of unamortized regulatory assets and liabilities on the consolidated balance sheets of PSCo 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 $11.7 million of unamortized prior service costs and $4.2 million of regulatory assets related to the non-qualified pension plan.
17. Segments and Related Information
PSCo has two reportable segments, regulated electric utility and regulated natural gas utility.
· PSCo’s regulated electric utility segment generates, transmits and distributes electricity in Colorado. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes PSCo’s commodity trading operations.
· PSCo’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Colorado.
Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services and nonutility real estate activities.
Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of PSCo.
To report net income for regulated electric and regulated natural gas utility segments, PSCo must assign or allocate all costs and certain other income. In general, costs are:
· Directly assigned wherever applicable;
· Allocated based on cost causation allocators wherever applicable; or
· Allocated based on a general allocator for all other costs not assigned by the above two methods.
The accounting policies of the segments are the same as those described in Note 1 to the consolidated financial statements. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery which is separately determined for each segment.
18. Related Party Transactions
Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including PSCo. 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, was:
19. Summarized Quarterly Financial Data (Unaudited)
Due to the seasonality of PSCo’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results. Summarized quarterly unaudited financial data is as follows:
Item 9
Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
During 2008 and 2009, and through the date of this report, there were no disagreements with the independent public accountants for PSCo on accounting principles or practices, financial statement disclosures or audit scope or procedures.
Item 9A
Item 9A - Controls and Procedures
Disclosure Controls and Procedures
PSCo 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 PSCo’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures were effective.
Internal Controls Over Financial Reporting
No change in PSCo’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, PSCo’s internal control over financial reporting. PSCo maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. PSCo 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, PSCo conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, PSCo 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 PSCo 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. Consolidated 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.
Consolidated Statements of Income - For the three years ended Dec. 31, 2009, 2008 and 2007.
Consolidated Statements of Cash Flows - For the three years ended Dec. 31, 2009, 2008 and 2007.
Consolidated 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 July 15, 1998 (Form 10-K, Dec. 31, 1998, Exhibit 3(a)(1)).
3.02*
By-laws dated Nov. 20, 1997 (Form 10-K, Dec. 31, 1997, Exhibit 3(b)(1)).
4.01*
Indenture, dated as of Oct. 1, 1993, providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 - Exhibit 4(a)).
4.02*
Indentures supplemental to Indenture dated as of Oct. 1, 1993:
Dated as of
Previous Filing:
Form; Date or
file no.
Exhibit
No.
Nov. 1, 1993
S-3, (33-51167)
4(b)(2)
Jan. 1, 1994
10-K, 1993
4(b)(3)
Sept. 2, 1994
8-K, September 1994
4(b)
May 1, 1996
10-Q, June 30, 1996
4(b)
Nov. 1, 1996
10-K, 1996 (001-03280)
4(b)(3)
Feb. 1, 1997
10-Q, March 31, 1997 (001-03280)
4(a)
April 1, 1998
10-Q, March 31, 1998 (001-03280)
4(b)
Aug. 15, 2002
10-Q, Sept. 30, 2002 (001-03280)
4.03
Sept. 1, 2002
8-K, Sept. 18, 2002(001-03280)
4.01
Sept. 15, 2002
10-Q, Sept. 30, 2002(001-03280)
4.04
March 1, 2003
S-3, April 14, 2003 (333-104504)
4(b)(3)
April 1, 2003
10-Q May 15, 2003 (001-03280)
4.02
May 1, 2003
S-4, June 11, 2003 (333-106011)
4.9
Sept. 1, 2003
8-K, Sept. 2, 2003 (001-03280)
4.02
Sept. 15, 2003
Xcel 10-K, March 15, 2004 (001-03034)
4.100
Aug. 1, 2005
PSCo 8-K, Aug. 18, 2005 (001-03280)
4.02
Aug. 1, 2007
PSCo 8-K, Aug. 14, 2007 (001-03280)
4.01
4.03*
Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
4.04*
Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129,500,000 Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A. (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file number 001-3280).
4.05*
Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U. S. Bank Trust NA, as successor Trustee. (Exhibit 4.01 to PSCo Form 8-K (file no 001-3280) dated Aug. 14, 2007).
4.06*
Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U. S. Bank Trust NA, as successor Trustee, creating $300,000,000 principal amount of 5.80% First Mortgage Bonds, Series No. 18 due 2018 and $300,000,000 principal amount of 6.50% First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)).
4.07*
Supplemental Indenture dated as of May 1, 2009 between PSCo and U. S. Bank Trust NA, as successor Trustee, creating $400,000,000 principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).
10.01*+
Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+
Xcel Energy Inc. Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+
Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+
New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+
Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008)
10.06*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+
Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+
Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+
Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+
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 Xcel Energy Form (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 Xcel Energy Form (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*
Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 - Exhibit 10I(1)).
10.19*
First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 - Exhibit 10I(2)).
10.20*
Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.21*
Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
10.22*
Amendment dated as of April 13, 2009 to the PSCo Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.23*
Credit Agreement dated Dec. 14, 2006 between PSCo and various lenders (Exhibit 10.03 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.24*+
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).
10.25*+
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).
10.26*+
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).
10.27*+
Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.28*+
Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
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
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
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.
PUBLIC SERVICE COMPANY OF COLORADO
/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 the date indicated above.
/s/ DAVID L. EVES
/s/ RICHARD C. KELLY
David L. Eves
Richard C. Kelly
President, Chief Executive Officer and Director
Chairman and Director
(Principal Executive Officer)
/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
PSCo has not sent, and does not expect to send, an annual report or proxy statement to its security holder.