Item 1 - Business
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS
COMPANY OVERVIEW
ELECTRIC UTILITY OPERATIONS
Overview
Summary of Recent Regulatory Developments
Public Utility Regulation
Capacity and Demand
Energy Sources and Related Transmission Initiatives
Fuel Supply and Costs
Commodity Marketing Operations
Electric Operating Statistics
NATURAL GAS UTILITY OPERATIONS
Summary of Recent Regulatory Developments
Capability and Demand
Natural Gas Supply and Costs
Natural Gas Operating Statistics
ENVIRONMENTAL MATTERS
EMPLOYEES
Item 1A
Item 1A - Risk Factors
Risks Associated with Our Business
Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.
We are subject to comprehensive regulation by federal and state utility regulatory agencies. The state utility commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service and the sale of electric energy in interstate commerce.
Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers. We currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our expenses incurred in a test year. Thus, the rates we are allowed to charge may or may not match our expenses at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers. If all of our costs are not recovered through customer rates, we could incur financial operating losses, which, over the long term, could jeopardize our ability to meet our financial obligations.
Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. 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 and 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 and Poor’s methodology. Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs.
We are subject to interest rate risk.
If interest rates increase, we may incur increased interest expense on variable interest debt or short-term borrowings, which could have an adverse impact on our operating results.
We are subject to capital market risk.
PSCo’s operations require significant capital investment in plant, property and equipment; consequently, PSCo is an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous events throughout the world economy. Capital market disruption events, as evidenced by the collapse in the U.S. sub-prime mortgage market, could prevent PSCo from issuing new securities or cause PSCo to issue securities with less than ideal terms and conditions.
We are subject to credit risks.
Credit risk includes the risk that counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.
We are subject to commodity risks and other risks associated with energy markets.
We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a monthly basis (mark-to-market accounting), which may cause earnings volatility. We utilize quoted observable market prices to the maximum extent possible in determining the value of these derivative commodity instruments. For positions for which observable market prices are not available, we utilize observable quoted market prices of similar assets or liabilities or indirectly observable prices based on forward price curves of similar markets. For positions for which the company has unobservable market prices, the company incorporates estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations. Actual experience can vary significantly from these estimates and assumptions and significant changes from our assumptions could cause significant earnings variability.
If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs. Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers.
We are subject to environmental laws and regulations, compliance with which could be difficult and costly.
We are subject to a number of environmental laws and regulations 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, 2007, these sites included:
· The sites of former manufactured gas plants operated by our subsidiaries or predecessors; and
· Third party sites, such as landfills, at which we are alleged to be a potentially responsible party that sent hazardous materials and wastes.
We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. These mandates are designed in part to mitigate the potential environmental impacts of utility operations. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the
operating and maintenance costs incurred to comply with the mandates, it could also have a material adverse effect on our results of operations.
In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.
We are subject to physical and financial risks associated with climate change.
There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. PSCo does not serve any coastal communities so the possibility of sea level rises does not directly affect PSCo or its customers. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of the company’s service territory could also have an impact on PSCo’s revenues. PSCo buys and sells electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers. Severe weather impacts PSCo’s service territories, primarily through thunderstorms, tornadoes and snow or ice storms. We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.
To the extent climate change impacts a region’s economic health, it may also impact PSCo’s revenues. PSCo’s financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation, would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause PSCo to receive less than ideal terms and conditions.
We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.
Legislative and regulatory responses related to climate change create financial risk. Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress. PSCo’s electric generating facilities are likely to be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. PSCo is advocating with state and federal policy makers to help design climate change regulation that is effective, flexible, low-cost and consistent with the our environmental leadership strategy.
Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap. Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a “cap and trade” structure, on PSCo and its customers will depend on a
number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. An important factor is PSCo’s 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 PSCo. 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.
Economic conditions could negatively impact our business.
Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.
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. 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 and customer response. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand.
Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.
Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel.
The insurance industry has also been affected by these events and the availability of insurance covering risks 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 an event (severe storm, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation) within our operating systems or on a neighboring system or the actions of a neighboring utility. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results.
We are subject to business continuity risks associated with the company’s ability to respond to unforeseen events.
The company’s 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 the company to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information. We are unable to quantify the potential impact of such an event.
Rising energy prices could negatively impact our business.
Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. We are unable to predict the future prices or the ultimate impact of such prices on our results of operations or cash flows.
Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.
Our electric utility and natural gas businesses are seasonal and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. 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. Effective June 2007, 83 electric reliability standards that were historically subject to voluntary compliance became mandatory and subject to potential civil penalties for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.
Increasing costs associated with our defined benefit retirement plans and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.
We have defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual stock market performance, changes in interest rates and any 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, 2007, Xcel Energy had approximately $6.3 billion of long-term debt and $1.7 billion of short-term debt or 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, 2007, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $76.2 million and $0.1 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, 2007, was approximately $31.6 million. Xcel Energy’s total exposure under these indemnities cannot be determined at this time. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.
We are a wholly owned subsidiary of Xcel Energy. Xcel Energy can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.
Our boards 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 2007, 2006 and 2005 we paid $263.9 million, $195.6 million and $62.6 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 also limited to some extent by our indenture for our first mortgage bonds.
Item 1B
Item 1B - Unresolved SEC 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) Based on PSCo’s ownership interest of 9.7 percent.
(b) Based on PSCo’s ownership interest of 75.5 percent of unit 1 and 37.4 percent of unit 2.
Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2007:
PSCo had 216 electric utility transmission and distribution substations at Dec. 31, 2007.
Natural gas utility mains at Dec. 31, 2007:
Item 3
Item 3 - Legal Proceedings
In the normal course of business, various lawsuits and claims have arisen against PSCo. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.
For a discussion of legal claims and environmental proceedings, see Note 13 to the consolidated financial statements under Item 8, incorporated by reference. For a discussion of proceedings involving utility rates, see Pending and Recently Concluded Regulatory Proceedings under Item 1 and Note 12 to the consolidated financial statements under Item 8, incorporated by reference.
Item 4
Item 4 - Submission of Matters to a Vote of Security Holders
This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
PART II
Item 5
Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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 debt agreements and FERC rules. PSCo’s mortgage bonds prohibit dividends or other similar distributions unless covenants relating to PSCo’s capitalization are met. 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 2007 and 2006 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. 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, have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of PSCo’s Form 10-K for the year ended Dec. 31, 2007.
Management’s Discussion and Analysis of Financial Condition and Results of Operation
Results Of Operations
PSCo’s net income was approximately $296.9 million for 2007, compared with approximately $241.5 million for 2006. During 2007, PSCo settled an ongoing dispute with the U.S. government regarding PSCo’s right to deduct interest expense on policy loans related to its COLI program that insured lives of certain PSCo employees. The total exposure for the tax years in dispute through 2007 was approximately $583 million, which includes income tax, interest and potential penalties. See Note 7 to the consolidated financial statements.
Electric Utility, Short-Term Wholesale and Commodity Trading Margins
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for customers, most fluctuations in these costs do not materially affect electric utility margin.
PSCo has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy-related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from, PSCo’s generation assets or the energy and capacity purchased to serve native load. Commodity trading is not associated with PSCo’s generation assets or the energy and capacity purchased to serve native load. Short-term wholesale and commodity trading activities are considered part of the electric utility segment.
Margins from commodity trading activity conducted at PSCo are partially redistributed to NSP-Minnesota and SPS, both wholly owned subsidiaries of Xcel Energy, pursuant to the JOA approved by the FERC. Margins received pursuant to the JOA are reflected as part of base electric utility revenues. Short-term wholesale and commodity trading margins reflect the impact of regulatory sharing, if applicable. Commodity trading revenues, as discussed in Note 1 to the consolidated financial statements, are reported net of related costs (i.e., on a margin basis) in the consolidated statements of income. Commodity trading expenses include purchased power, transmission, broker fees and other related costs. Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing of margins, if applicable.
The following table details the revenues and margin for base electric utility, short-term wholesale and commodity trading activities:
The following summarizes the components of the changes in base electric revenues and base electric margin for the year ended Dec. 31:
Base Electric Revenues
Base Electric Margin
Natural Gas Utility Revenues and Margin - The following table details the change in 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.
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
Operating and Maintenance Expenses - Operating and maintenance expenses for 2007 increased $38.4 million, or 6.7 percent, compared to 2006. The following summarizes the components of the changes for the year ended Dec. 31:
Depreciation and amortization - Depreciation and amortization expense increased by approximately $25.3 million, or 10.6 percent, for 2007 compared with 2006, primarily due to normal plant additions and the approved change in depreciation rates for 2007 from the 2006 Colorado rate case settlement resulting in an additional depreciation expense of $17.0 million.
Interest and other income (expense), net - Interest and other income (expense), net, increased by approximately $11.8 million, or 83.1 percent, primarily due to lower interest expense, net of interest income on COLI loans and interest income accrued on deferred fuel costs.
Interest charges and financing costs - Interest charges and financing costs increased by approximately $42.7 million, or 31.1 percent, for 2007 compared with 2006, primarily due to interest incurred related to the COLI life insurance settlement.
AFDC - AFDC is a non-cash amount capitalized as a part of construction costs representing the cost of financing the construction. Generally, these costs are recovered from customers, in future rates, as the related property is depreciated. AFDC increased by approximately $11.5 million, or 71.5 percent, for 2007 compared with 2006, primarily due to the construction of Comanche 3. The increase was partially offset by the current recovery from customers of the financing costs related to this construction through base rates, resulting in a lower recognition of AFDC.
Income taxes - Income tax expense increased by approximately $52.7 million for 2007 compared with 2006. The increase was primarily due to an increase in pretax income (excluding COLI) and $16.1 million of tax expense related to the COLI settlement in 2007. The effective tax rate was 31.2 percent for 2007, compared with 25.3 percent for 2006. The higher effective tax rate for 2007 was primarily due to the COLI settlement. Without these charges, the effective tax rate for 2007 would have been 24.1 percent.
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. These risks, as applicable to PSCo, are discussed in further detail below.
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 both 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 capacity, energy and energy related instruments. These marketing activities generally have terms of less than one year in length. 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.
The fair value of the commodity trading contracts at Dec. 31, 2007, were as follows:
At Dec. 31, 2007, the fair values by source for the commodity trading net asset or liability balances were as follows:
(1) - Prices actively quoted or based on actively quoted prices.
(2) - 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 SFAS No. 133 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.
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 VaR. VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time, with a given confidence interval under normal market conditions. PSCo utilizes the variance/covariance approach in calculating VaR. The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption, delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas.
VaR is calculated on a consolidated basis. The VaRs for the commodity trading operations were:
(a) Comprises transactions for NSP-Minnesota, PSCo and SPS.
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, subject to regulatory approval when required.
At Dec. 31, 2007, a 100-basis-point change in the benchmark rate on PSCo’s variable rate debt would impact pretax interest expense by approximately $2.0 million.
Credit Risk - PSCo is also exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. PSCo maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.
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.
At Dec. 31, 2007, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $16.0 million, while a decrease of 10 percent would have resulted in a decrease of $9.4 million.
Item 8
Item 8 - Financial Statements and Supplementary 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, 2007. 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, 2007, the company’s internal control over financial reporting is effective based on those criteria.
This annual report does not include an attestation report of PSCo’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit PSCo to provide only management’s report in this annual report.
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 statements of capitalization of Public Service Company of Colorado and subsidiaries (the “Company”) as of December 31, 2007 and 2006, 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, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of Colorado and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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.
As discussed in Note 7 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109,” as of January 1, 2007.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 20,
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
(Thousands)
See Notes to Consolidated Financial Statements
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(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 the regulatory of the FERC and state utility commissions. 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 aspects.
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 has various rate-adjustment mechanisms in place that currently provide for the recovery of purchased natural gas and electric fuel and purchased energy costs. These cost adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically, for any difference between the total amount collected under the clauses and the recoverable costs incurred. Where applicable under governing state regulatory commission rate orders, fuel costs over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets. In addition, PSCo presents its revenue net of any excise or other fiduciary-type taxes or fees. A summary of significant rate-adjustment mechanisms follows:
· PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through the ECA. The ECA is an incentive adjustment mechanism that compares actual fuel and purchased energy expense in a calendar year to a benchmark formula. Effective January 2007, the ECA has been modified to include an incentive adjustment to encourage efficient operation of base load coal plants and encourage cost reductions through purchases of economical short-term energy. The total incentive payment to PSCo in any calendar year will not exceed $11.25 million. The ECA mechanism is revised quarterly and interest accrues monthly on the average deferred balance. The ECA will expire at the earlier of rates taking effect after Comanche 3 is placed in service or Dec. 31, 2010.
· PSCo’s rates include annual adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually. 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 SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). In addition, commodity-trading results include the impacts of all margin-sharing mechanisms. For more information, see Note 10 to the consolidated financial statements.
Types of and Accounting for Derivative Instruments - PSCo uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation. The classification of the fair value for those derivative instruments is dependent on the designation of
a qualifying hedging relationship. The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations.
Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas 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 designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income (OCI), to the extent effective.
SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. PSCo formally documents all hedging relationships in accordance with SFAS No. 133. The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedged 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 either the fair value or 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, 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 underlying debt and the dollar offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis. The fair value of interest rate derivatives is determined through counterparty valuations, internal valuations and broker quotes. Gains and losses related to discontinued hedges that were previously accumulated in OCI will remain in OCI until the underlying contract is reflected in earnings; unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in OCI 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. SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales.
PSCo evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS No. 133. None of the contracts entered into within the commodity trading operations qualify for a normal designation. For further discussion of PSCo’s risk management and derivative activities see Note 10 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. Removal costs associated with regulatory obligations 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 other 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, 2007, 2006 and 2005 was 2.7 percent, 2.6 percent and 2.6 percent, respectively.
AFDC - AFDC represents the cost of capital used to finance utility construction activity. AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility construction cost is credited to other income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized are included in PSCo’s rate base for establishing utility service rates.
Environmental Costs - Environmental costs are recorded on an undiscounted basis when it is probable PSCo is liable for the costs and the liability can be reasonably estimated. Costs may be deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.
Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for 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 under FAS 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. 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 turn around, or reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.
Investment tax credits are deferred and their benefits amortized over the estimated lives of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 14 to the consolidated financial statements. For more information on income taxes, see Note 7 to the consolidated financial statements.
In July 2006, the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax positions that such company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, PSCo adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which was reported as an adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.
PSCo reports interest and penalties related to income taxes within the interest charges section in the consolidated statements of income.
Xcel Energy and its utility subsidiaries, including PSCo, file consolidated federal and combined and separate state income tax returns. Income taxes for consolidated or combined subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss. The holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company in the consolidated federal or combined state returns as a contribution of capital.
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 is obtained or actual amounts are determinable. Those revisions can affect operating results. Each year the depreciable lives of certain plant assets are reviewed and revised, if appropriate.
Cash and Cash Equivalents - 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.
Restricted Cash - At Dec. 31, 2007 and 2006, PSCo had restricted cash of $23.7 million and $11.1 million, respectively. The restricted cash balances primarily represent margin deposits held in conjunction with electric futures trading contracts. These balances are presented as a component of other long-term assets on the consolidated balance sheets.
Inventory - All inventories are recorded at average cost.
Regulatory Accounting - PSCo accounts for certain income and expense items in accordance with statement of financial accounting standards SFAS No. 71 - “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). Under SFAS No. 71:
· Certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and
· Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.
Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.
If restructuring or other changes in the regulatory environment occur, 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 14 to the consolidated financial statements.
Deferred Financing Costs - Other assets include deferred financing costs, net of amortization, of approximately $12.7 million and $11.4 million at Dec. 31, 2007 and 2006, respectively. PSCo is amortizing these financing costs over the remaining maturity periods of the related debt.
Debt premiums, discounts, expenses and amounts received or incurred to settle hedges are amortized over the life of the related debt. The premiums and costs associated with modified debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. If PSCo extinguishes the debt, all unamortized balances shall be expensed at the time of the redemption.
Accounts Receivable and Allowance for Bad Debts - Accounts receivable are stated at the actual billed amount net of the allowance for uncollectibles. PSCo establishes an allowance for uncollectibles based on a reserve policy that reflects its expected exposure to the credit risk of customers.
Renewable Energy Credits - Renewable Energy Credits (RECs) are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. These credits can be bought and sold. RECs are typically used as a form of measurement of compliance to Renewable Portfolio Standards (RPS) 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 the load obligation, they are recorded as inventory at actual cost. RECs acquired for trading purposes are recorded as other investments at actual cost. The cost of RECs that are retired for compliance purposes are recorded as electric fuel and purchased power. The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues net of any margin sharing requirements. As a
result of state regulatory orders, we reduce recoverable fuel costs for the value of certain RECs and record the cost of RECs to satisfy future compliance requirements that are recoverable in future rates as regulatory assets under the criteria of SFAS No. 71.
Emission Allowances - Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA. PSCo follows the inventory 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 - Certain amounts in the consolidated statements of cash flows have been reclassified from prior-period presentation. The reclassifications reflect the presentation of net regulatory assets and liabilities as separate items rather than components of other assets and other liabilities within net cash provided by operating activities. In addition, activity related to derivative transactions have been combined into net realized and unrealized hedging and derivative transactions. These reclassifications did not affect total net cash provided by (used in) operating, investing or financing activities within the consolidated statements of cash flows.
2. Recently Issued Accounting Pronouncements
Fair Value Measurements (SFAS No. 157) - In September 2006, the FASB issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007. PSCo is evaluating the impact of SFAS No. 157 on its consolidated financial statements and does not expect the impact of implementation to be material.
The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (SFAS No. 159) - In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after Nov. 15, 2007, effective Jan. 1, 2008. PSCo adopted SFAS No. 159 and the adoption did not have a material impact on its consolidated financial statements.
Business Combinations (SFAS No. 141 (revised 2007)) - In December 2007, the FASB issued SFAS No. 141R, which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. PSCo is evaluating the impact of SFAS No. 141R on its consolidated financial statements for any potential business combinations subsequent to Jan. 1, 2009.
Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51(SFAS No. 160) - In December 2007, the FASB issued SFAS No. 160, 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. This statement is effective for fiscal years beginning on or after Dec. 15, 2008. PSCo is evaluating the impact of SFAS No. 160 on its consolidated financial statements.
3. Short - Term Borrowings
Commercial Paper - At Dec. 31, 2007 and 2006, PSCo had commercial paper outstanding of approximately $271.0 million and $372.5 million, respectively. The weighted average interest rates at Dec. 31, 2007 and 2006, were 5.64 percent and 5.43 percent, respectively.
Money Pool - Xcel Energy has established a utility money pool arrangement that allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. PSCo has approval to borrow up to $250 million under the arrangement. At Dec. 31, 2007, PSCo had money pool loans outstanding of $100.6 million with a weighted average interest rate of 5.64 percent.
4. Long-Term Debt
Credit Facilities - At Dec. 31, 2007, PSCo had the following committed credit facility in effect, in millions of dollars:
* Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings.
The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. 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 with which PSCo was in compliance at Dec. 31, 2007. 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.
· At Dec. 31, 2007, PSCo had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $271.0 million of commercial paper outstanding and $5.1 million of letters of credit.
· At Dec. 31, 2006, PSCo had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $372.5 million of commercial paper outstanding and $6.0 million of letters of credit.
· At Dec. 31, 2007, $5.1 million letters of credit were outstanding, of which $5.1 million were outstanding under the above credit facility.
· At Dec. 31, 2006, $6.0 million letters of credit were outstanding, of which $6.0 million were outstanding under the above credit facility.
Long-Term Borrowings
On Aug. 15, 2007, PSCo issued $350 million of 6.25 percent first mortgage bonds, series due Sept. 1, 2037. PSCo added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper, including commercial paper incurred to fund the payment at maturity of $100 million of 7.11 percent secured medium-term notes, which matured on March 5, 2007.
Maturities of long-term debt are:
5. Preferred Stock
PSCo has authorized the issuance of preferred stock.
6. Joint Plant Ownership
Following are the investments by PSCo in jointly owned plants and the related ownership percentages as of Dec. 31, 2007:
PSCo’s current operational assets include approximately 320 MWs of jointly owned generating capacity. PSCo’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for funding 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 3, is expected to be completed in the fall of 2009. PSCo is the operating agent under the joint ownership agreement.
7. Income Taxes
COLI - As previously disclosed, 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. In September 2007, Xcel Energy and the United States finalized a settlement, which terminated the tax litigation pending between the parties. 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.
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. Xcel Energy paid the settlement as follows:
· $32.2 million was satisfied by tax and interest amounts that Xcel Energy had previously paid or deemed under the terms of the settlement to have been paid.
· $32.2 million was paid by Xcel Energy on Oct. 31, 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.
Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN 48) -PSCo adopted FIN 48 as of Jan. 1, 2007. PSCo is a member of the Xcel Energy affiliated group that files consolidated income tax returns. Xcel Energy has been audited by the IRS through tax year 2003, with a limited exception for 2003 research tax credits. The IRS commenced an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003) in the third quarter of 2006, and that examination is anticipated to be complete by March 31, 2008. As of Dec. 31, 2007, the IRS had not proposed any material adjustments to tax years 2003 through 2005. The statute of limitations applicable to Xcel Energy’s 2000 through 2002 federal income tax returns expired as of June 30, 2007.
As previously disclosed, Xcel Energy was in litigation with the federal government to establish its right to deduct interest expense on COLI policy loans incurred since 1993. Xcel Energy and the IRS have reached a final settlement regarding this litigation (see above discussion of COLI).
In the fourth quarter of 2007, the state of Colorado concluded an income tax audit through tax year 2005. As of Dec. 31, 2007, PSCo’s earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2002.
The amount of unrecognized tax benefits was $11.4 million on Jan. 1, 2007 and $8.8 million on Dec. 31, 2007. A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
These unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss and tax credit carryovers of $7.5 million and $3.8 million as of Jan. 1, 2007 and Dec. 31, 2007, respectively.
The unrecognized tax benefit balance included $4.5 million and $2.8 million of tax positions on Jan. 1, 2007 and Dec. 31, 2007, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $6.9 million and $6.0 million of tax positions on Jan. 1, 2007 and Dec. 31, 2007, 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 $2.6 million from Jan. 1, 2007 to Dec. 31, 2007, was due to the addition of similar uncertain tax positions related to ongoing activity, and the resolution of certain federal and state audit matters. PSCo’s amount of unrecognized tax benefits could significantly change in the next 12 months as audits progress. 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. However, as the IRS completes the audit that is currently in progress and as statutes of limitations expire, it is reasonably possible that the amount of unrecognized tax benefits could decrease up to $2.0 million.
The liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with net operating loss and tax credit carryovers. The amount of interest expense related to unrecognized tax benefits reported within interest charges in 2007 was $44.8 million. The liability for interest related to unrecognized tax benefits was $3.8 million on Dec. 31, 2007.
The amount of penalty expense related to unrecognized tax benefits reported within interest charges in 2007 was $3.2 million. The liability for penalties related to unrecognized tax benefits was $1.0 million on Dec. 31, 2007.
Other Income Tax Matters - PSCo’s federal net operating loss and tax credit carry forwards are estimated to be $102.6 million and $11.1 million, respectively, as of Dec. 31, 2007. The carry forward periods expire between 2021 and 2027. PSCo also has state net operating loss and tax credit carry forwards of $72.3 million and $4.4 million, respectively, as of Dec. 31, 2007. The state carry forward periods expire between 2016 and 2026.
Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following is a table reconciling such differences for the years ending Dec. 31:
The components of income tax expense (benefit) for the years ending Dec. 31 were:
The components of deferred income tax at Dec. 31 were:
The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:
8. Benefit Plans and Other Postretirement Benefits
Pension and other postretirement disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to PSCo.
Xcel Energy offers various benefit plans to its benefit employees, including those of PSCo. Approximately 52 percent of Xcel Energy employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2007, PSCo had 2,194 bargaining employees covered under a collective-bargaining agreement, which expires in May 2009.
Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans-an amendment of FASB Statements No. 87, 88, 106 and 132(R) (SFAS No. 158) - In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income. PSCo applied regulatory accounting treatment for unrecognized amounts of regulated utility subsidiary employees, which allowed recognition as a regulatory asset rather than as a charge to accumulated other comprehensive income, as future costs are expected to be included in rates. The effect of adopting in 2006 for the remaining unrecognized amounts was an increase in accumulated other comprehensive income of $88.8 million.
Pension Benefits
Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees, including those of PSCo. Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.
Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.
Pension Plan Assets - Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities. The target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments and 20 percent in nontraditional investments, such as real estate, private equity and a diversified commodities index.
The actual composition of pension plan assets at Dec. 31 was:
Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 11.8 percent, which is greater than the current assumption level. The pension cost determination assumes the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments. A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year. Investment returns in 2007 were below the assumed level of 8.75 percent while returns in 2006 and 2005 exceeded the assumed level of 8.75 percent. Xcel Energy continually reviews its pension assumptions. In 2008, Xcel Energy will continue to use an investment-return assumption of 8.75 percent.
Benefit Obligations - A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:
At Dec. 31, 2007, PSCo Bargaining Pension Plan had projected benefit obligations of $732.7 million, which exceeded plan assets of $688.1 million. At Dec. 31, 2006, the projected benefit obligations of $728.1 million, exceeded plan assets of $658.2 million. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected benefit obligations of $1.9 billion on Dec. 31, 2007.
Cash Flows - Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2005 through 2007 for Xcel Energy’s pension plans and are not expected to require cash funding in 2008. Voluntary contributions were made to the PSCo Bargaining Pension Plan of $35 million in 2007, $30 million in 2006 and $15 million in 2005. During 2008, Xcel Energy expects to voluntarily contribute approximately $35 million to the PSCo pension plan for bargaining employees.
Plan Changes - The Pension Protection Act of 2006 (PPA) was effective Dec. 31, 2006. PPA requires a change in the conversion basis for lump-sum payments, three-year vesting for plans with account balance or pension equity benefits. These changes are reflected as a plan amendment for purposes of SFAS No. 87 - “Employers’ Accounting for Pensions” (SFAS No. 87).
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 2008 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.
Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.
Defined Contribution Plans
Xcel Energy maintains 401(k) plans that cover substantially all employees. The contributions for PSCo were approximately $7.9 million in 2007, $6.2 million in 2006 and $6.2 million in 2005.
Postretirement Health Care Benefits
Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. Employees of the former New Century Energies, Inc. (NCE) who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE, who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
In conjunction with the 1993 adoption of SFAS No. 106 - “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (SFAS No. 106), Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.
Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106. PSCo transitioned to full accrual accounting for SFAS No. 106 costs between 1993 and 1997, consistent with the accounting requirements for rate-regulated enterprises. The Colorado jurisdictional SFAS No. 106 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 SFAS No. 106 costs. PSCo is required to fund SFAS No. 106 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 non-bargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.
The actual composition of postretirement benefit plan assets at Dec. 31 was:
Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio. Investment-return volatility is not considered to be a material factor in postretirement health care costs.
Benefit Obligations - A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:
Effective Dec. 31, 2007, Xcel Energy reduced its initial medical trend assumption from 9.0 percent to 8.0 percent. The ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached is six years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.
A 1-percent change in the assumed health care cost trend rate would have the following effects on PSCo:
Plan Changes - The employer subsidy for retiree medical coverage was eliminated for former NCE non-bargaining employees who retire after July 1, 2003.
Cash Flows - The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute approximately $49 million during 2008.
Benefit Costs - The components of net periodic postretirement benefit cost are:
Projected Benefit Payments
The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans.
9. Detail of Interest and Other Income (Expense), Net
Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 consisted of the following:
10. Derivative Instruments
In the normal course of business, 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. PSCo utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations.
Commodity Price Risk - PSCo is exposed to commodity price risk in its electric and natural gas operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy and other energy-related products and for various fuels used in the generation of electricity and natural gas utility operations. Commodity risk is also managed through the use of financial derivative instruments. PSCo utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though regulatory jurisdiction may provide for recovery of actual costs. The use of derivative instruments is done consistently with the local jurisdictional cost-recovery mechanism. 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 and energy and other energy-related instruments. PSCo’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by our risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.
Interest Rate Risk - 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, subject to regulatory approval when required.
Types of and Accounting for Derivative Instruments
PSCo uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The types of qualifying hedging transactions that PSCo is currently engaged in are discussed below.
Cash Flow Hedges
Commodity Cash Flow Hedges - PSCo enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes. At Dec. 31, 2007, PSCo had various commodity-related contracts designated as cash flow hedges extending through December 2009.
At Dec. 31, 2007, PSCo had $0.3 million in accumulated other comprehensive income that is expected to be recognized in earnings during the next 12 months as the hedged transactions settle.
PSCo had immaterial ineffectiveness related to commodity cash flow hedges during 2007 and 2006.
Interest Rate Cash Flow Hedges - PSCo enters into interest rate lock agreements, including treasury-rate locks and forward starting swaps that effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash flow hedges for accounting purposes.
At Dec. 31, 2007, PSCo had net gains of approximately $1.5 million in accumulated other comprehensive income that it expects to recognize in earnings during the next 12 months.
PSCo had no ineffectiveness related to interest rate cash flow hedges during 2007 and 2006.
The following table shows the major components of the derivative instruments valuation in the consolidated balance sheets at Dec. 31:
In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, 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 the first quarter of 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 cash flow hedges on PSCo’s accumulated other comprehensive income, included in the consolidated statements of common stockholder’s equity and comprehensive income, is detailed in the following table:
11. Financial Instruments
The estimated Dec. 31 fair values of 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 long-term investments are 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, 2007 and 2006. 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, 2007 and 2006, there were $5.1 million and $6.0 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.
12. Rate Matters
Pending and Recently Concluded Regulatory Proceedings - CPUC
Base Rate
Natural Gas Rate Case - In December 2006, PSCo filed with the CPUC, a request to increase natural gas rates by $41.9 million, or 2.96 percent. The request assumed a common equity ratio of 60.17 percent, an ROE of 11 percent and a rate base is approximately $1.1 billion.
In July 2007, the CPUC approved with modifications a comprehensive settlement between PSCo, the CPUC staff, the OCC and Seminole Energy Services, LLC, providing for, among other things, the following:
· An annual revenue increase of $32.3 million, based on a 10.25 percent ROE and a 60.17 percent equity ratio.
· A modification to the partial decoupling mechanism to allow PSCo recovery of additional revenues in future years to compensate for the portion of the decline in weather normalized residential use per customer that exceeds the first 1.3 percent in annual decline in use (to be reflective of 50 percent of the historic average annual decline in use).
Final rates were implemented effective July 30, 2007. Under the provisions of this settlement, PSCo will be filing its Phase II (cost allocation and rate design) on or before March 31, 2008, to spread among PSCo’s customer classes the settled revenue requirement from this case.
Electric, Purchased Gas and Resource Adjustment Clauses
Transmission Cost Adjustment Rider - On Sept. 7, 2007, PSCo filed with the CPUC a request to implement a transmission cost adjustment rider (TCA), which would recover approximately $18.2 million in 2008. This filing is pursuant to recently enacted legislation which entitled public utilities to recover, through a separate rate adjustment clause, the costs that it prudently incurs in planning, developing and completing the construction or expansion of transmission. This legislation further encourages utilities to invest in transmission facilities by allowing the recovery of the total balance of construction work in progress related to those transmission investments at PSCo’s weighted average cost of capital including its most recently authorized rate of ROE. The CPUC staff and certain other parties challenged the scope of PSCo’s requested cost recovery under the rider during 2008.
In November 2007, PSCo updated its estimate of costs to be recovered through the TCA commencing Jan. 1, 2008, reducing its requested recovery during 2008 to $8.7 million.
In December 2007, the CPUC issued its initial decision approving PSCo’s application to implement the TCA. However, the CPUC limited the scope of the costs that could be recovered through the rider during 2008 to only those costs associated with transmission investment made after the new legislation authorizing the rider became effective on March 26, 2007. The CPUC also will require PSCo to base its revenue requirement calculation on a thirteen month average net transmission plant balance. As a result of the CPUC’s decision, PSCo will implement a rider on Jan. 1, 2008 to recover approximately $4.5 million in 2008. PSCo sought reconsideration of that aspect of the decision requiring it to base the rider on a thirteen-month
average net transmission plant balance. In February 2008, the CPUC voted to deny rehearing.
Enhanced DSM Program - In October 2007, PSCo filed an application with the CPUC for approval to implement an expanded DSM program and to revise its DSMCA to include current cost recovery and incentives designed to reward PSCo for successfully implementing cost-effective DSM programs and measures. Under the DSM program currently in place, PSCo is committed to using its best efforts to acquire, on average, 40 MW of demand reduction and 100 GWh of energy savings per year from cost-effective DSM programs over the period beginning Jan. 1, 2006 and ending Dec. 31, 2013, so that by Jan. 1, 2014 PSCo will have achieved a cumulative level of 320 MW of total demand reduction and 800 GWh of annual energy savings. With this application, PSCo proposes to expand and extend its commitment to acquire a cumulative level of 694 MW of peak demand reduction and 2,351 GWh of energy savings, including achievements associated with its existing DSM programs over the period Jan. 1, 2009 through Dec. 31 2009. Under the proposed revision to the DSMCA, PSCo would recover 100 percent of its forecasted expenses associated with the DSM program during the year in which the rider is in effect as well as an incentive based upon the net economic benefits achieved during the prior year up to 20 percent of the net present vales of the benefits achieved.
Interruptible Service Option Credit Program - In November 2007 PSCo requested to expand its interruptible service option credit program (ISOC) to make it available to customers with interruptible demands of 300 KW and above. PSCo also seeks to change the basis upon which it pays credits to customers who participate in the program and to obtain approval for current recovery of those credits through the DSM Adjustment Clause. Lastly, PSCo seeks authority to recover an incentive in addition to receiving reimbursement of the credits paid to customers to reward it for successful implementation of a program that reduces overall costs to its retail customers.
Other
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 an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered. Subsequent to the ruling, the FERC has allowed the parties to request additional evidence regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed that the total amount of transactions with PSCo subject to refund are $34 million. 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 United States Court of Appeals for the Ninth Circuit.
In an order issued on Aug. 24, 2007, the Ninth Circuit issued an order remanding the proceeding back to the FERC. The court of appeals determined that it had jurisdiction to review the FERC’s decision not to order refunds and remanded the case back to the FERC, directing that the FERC consider evidence that had been presented regarding intentional market manipulation in the California markets and its potential ties to transactions in the Pacific Northwest. The court of appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.
13. Commitments and Contingent Liabilities
Leases - PSCo leases a variety of equipment and facilities used in the normal course of business. Two of these leases qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2028. 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.
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. Rental expense under operating lease obligations was approximately $44.6 million, $17.1 million and $19.6 million for 2007, 2006 and 2005, respectively. Purchase power agreements contributed $26.1 million in 2007.
Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with Emerging Issues Task Force 01-8, “Determining whether an Arrangement Contains a Lease” and SFAS No. 13, “Accounting for Leases.” Future commitments under operating and capital leases for continuing operations are:
Capital Commitments - The estimated cost, as of Dec. 31, 2007, of the capital expenditure programs and other capital requirements of PSCo is approximately $825 million in 2008, $505 million in 2009 and $530 million in 2010. PSCo’s capital expenditure forecast includes the following major project:
Comanche 3 - Comanche 3, a 750-MW coal-fired plant being built in Colorado is expected to cost approximately $1.35 billion, with major construction initiated in 2006 and expected to be completed in the fall of 2009. The CPUC has approved sharing one-third ownership of this plant with other parties. Consequently, PSCo’s investment in Comanche 3 will be approximately $1 billion.
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 2008 and 2028. 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.
The estimated minimum purchase obligation for PSCo under these contracts as of Dec. 31, 2007, is 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 2027. 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.
PSCo has also executed three additional purchase power agreements that are conditional upon achievement of certain conditions, including becoming operational. Estimated payments under these conditional obligations are $13.6 million for 2008, $18.2 million for 2009 through 2011, $28.8 million for 2012 and $477.7 million thereafter, respectively.
At Dec. 31, 2007, the estimated future payments for capacity, accounted for as executory contracts, that PSCo is obligated to purchase, subject to availability, were as follows:
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 potentially responsible parties 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 and some other parties have caused environmental contamination. Environmental contingencies could arise from various situations including the following categories of sites:
· Site of a former MGP operated by PSCo, its predecessors, or other entities; and
· Third party sites, such as landfills, to which PSCo is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.
PSCo records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially from the initial estimate.
To estimate the remediation cost for these sites, assumptions are made where facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.
Estimates are revised as facts become known. At Dec. 31, 2007, the liability for the cost of remediating these sites was estimated to be $1.7 million, of which $0.6 million was considered to be a current liability. Some of the cost of remediation may be recovered from:
· Insurance coverage;
· Other parties that have contributed to the contamination; and
· Customers.
Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for PSCo’s future costs for these sites.
Manufactured Gas Plant Site
Fort Collins Manufactured Gas Plant Site - Prior to 1926, the Poudre Valley Gas Co. operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the assets of the Poudre Valley Gas Co., PSCo shut down the MGP site and has subsequently sold most of the property. In 2002, an oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. In November 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co. under which PSCo performed remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring.
In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of cleanup costs at the Fort Collins MGP site spent through March 2005, which amounted to $6.2 million, to be amortized over four years. PSCo reached a settlement agreement with the parties in the case. In January 2006, the CPUC approved the settlement agreement, rates were effective Feb. 6, 2006.
In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional clean-up costs at the Fort Collins MGP site spent through September 2006, plus unrecovered amounts previously authorized from the last rate case, which amounted to $10.8 million to be amortized over four years. In June 2007, PSCo entered into a settlement agreement that included recovery of the full $10.8 million, but with a five year amortization period. The CPUC approved the agreement on June 18, 2007. The total amount to be recovered from customers is $13.1 million. Estimated future project costs, based upon an assumed 30-year system operating life, including EPA oversight costs, are approximately $3.9 million.
In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases caused MGP byproducts to migrate to the Cache la Poudre River, thereby substantially increasing the scope and cost of remediation. PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River. In December 2005, the court denied Schrader’s request to dismiss the PSCo suit. Schrader thereafter filed a response to the PSCo complaint and a counterclaim against PSCo for its response costs under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and under the Resource Conservation and Recovery Act (RCRA). Schrader alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as defined by RCRA. PSCo filed a motion for partial summary judgment to dismiss Schrader’s RCRA claim. In October 2007, the court granted PSCo’s motion for partial summary judgment and dismissed Schrader’s RCRA claim. Schrader also filed a motion for summary judgment seeking to dismiss PSCo’s CERCLA claim. PSCo believes this motion is without merit and will vigorously defend its claim. Any costs recovered from Schrader are expected to operate as a credit to ratepayers.
Third Party and Other Environmental Site Remediation
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
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.
The EPA requires states to develop implementation plans to comply with BART by December 2007. 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 promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART technology or an approved BART alternative to make reasonable progress toward meeting the national visibility goal. PSCo estimates that implementation of the BART alternatives will cost approximately $211 million in capital costs, which includes approximately $62 million in environmental upgrades for the existing Comanche Station project, 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 2011 and 2014. On June 4, 2007, the CAPCD approved PSCo’s BART analysis and obtained public comment on its BART determination and PSCo’s BART permits. The Air Quality Control Commission approved the CAPCD’s BART determination for PSCo during a public hearing in December 2007. CAPCD’s BART determinations and corresponding provisions of the regional haze state implementation plan will be submitted to the EPA for approval in 2008. In addition, in early 2008, the CAPCD plans to embark on a stakeholder process to develop presumptive standards for significant source categories and establish reasonable progress goals for Colorado’s Class I areas. To meet these goals, more controls may be required from certain sources, which may or may not include those sources previously controlled under BART.
CAMR - In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. On Feb. 8, 2008, the D.C. Circuit Court of Appeals vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury legislation and rules. Colorado’s mercury rule requires mercury emission controls capable of achieving 80 percent capture be installed at Pawnee Station by 2012 and all other Colorado units by 2014. PSCo is in the process of installing mercury monitors on seven Colorado units at an estimated aggregate cost of approximately $2.6 million. PSCo is evaluating the mercury emission controls required to meet the new rule and is currently unable to provide a 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” 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 challenging the phase II rulemaking. In January 2007, the court issued its decision and remanded virtually every aspect of 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 court-ordered remand. As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved.
Notice of Violation - In July 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source Review (NSR) requirements of the Clean Air Act (CAA) at the Comanche and Pawnee plants 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. It 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.
Cherokee Station Alleged Clean Air Act Violations - In January 2008, Xcel Energy received a notice letter from Rocky Mountain Clean Air Action stating that the group intends to sue Xcel Energy for alleged Clean Air Act violations at Cherokee Station. The group claims that Cherokee Station’s opacity emissions have exceeded allowable limits over the past five years and that its opacity monitors exceeded downtime limits. Xcel Energy disputes these claims and believes they are without merit. The Clean Air Act requires notice be given 60 days prior to filing a lawsuit. If the group does in fact file its threatened lawsuit, Xcel Energy will vigorously defend itself against these claims.
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 SFAS No. 143 - “Accounting for Asset Retirement Obligations” (SFAS No. 143). This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.
Recorded ARO - ARO’s have been recorded for steam production, electric transmission and distribution and natural gas distribution. The steam production obligation includes asbestos and ash-containment facilities. 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.
PSCo recognized an ARO for the retirement costs of its natural gas mains. In addition, an ARO was recognized 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, 2007 and 2006, respectively:
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 under SFAS No. 71. Removal costs as of Dec. 31, 2007 and Dec. 31, 2006 were $374 million and $389 million, respectively.
Legal Contingencies
In the normal course of business, PSCo is party to routine claims and litigation arising from prior and current operations. PSCo is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition, when it can be reasonably estimated.
Environmental Litigation
Comanche 3 Permit Litigation - In August 2005, Citizens for Clean Air and Water in Pueblo and Southern Colorado and Clean Energy Action filed a complaint in Colorado state court against the CAPCD alleging that the division improperly granted permits to PSCo under Colorado’s Prevention of Significant Deterioration program for the construction and operation of Comanche 3. PSCo intervened in the case. In June 2006, the court ruled in PSCo’s favor and held that the Comanche 3 permits had been properly granted and plaintiffs’ claims to the contrary were without merit. Plaintiffs appealed the decision. In February 2008, the Colorado Court of Appeals affirmed the state court’s ruling.
Carbon Dioxide Emissions Lawsuit - In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. In June 2007 the Second Circuit Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 ( April 2, 2007) on the issues raised by the parties on appeal. Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “ pollutant” subject to regulation by the EPA under the Clean Air Act. In response to the request of the Second Circuit Court of Appeals, in June 2007, the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.
Comer vs. Xcel Energy Inc. et al. - In April 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. In September 2007, plaintiffs filed a notice of appeal to the Fifth Circuit Court of Appeals. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.
Employment, Tort and Commercial Litigation
Qwest vs. Xcel Energy Inc. - In June 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 Denver state court. In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo. Pursuant to this agreement, Qwest asserted PSCo had an affirmative duty to properly train and instruct its employees on pole
safety, including testing the pole for soundness before climbing. In May 2006, PSCo filed a counterclaim against Qwest asserting Qwest had a duty to PSCo and an obligation under the contract to maintain its poles in a safe and serviceable condition. 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. In January 2008, Qwest filed a notice of appeal.
Mallon v. Xcel Energy Inc. - In July 2007, Theodore Mallon and TransFinancial Corporation filed a declaratory judgment action against Xcel Energy in U.S. District Court in Colorado (Mallon Federal Action). In this lawsuit, plaintiffs seek a determination that Xcel Energy is not entitled to assert claims against plaintiffs related to the 1984 and 1985 sale of COLI to PSCo, a predecessor of Xcel Energy. In August 2007, Xcel Energy, PSCo and PSRI commenced a lawsuit in Colorado state court against Mallon and TransFinancial Corporation (Mallon State Action). In the Mallon State Action, Xcel Energy, PSCo and PSRI seek damages against Mallon and TransFinancial for, among other things, breach of contract and breach of fiduciary duties associated with the sale of the COLI policies. In August 2007, Xcel Energy also filed a motion to stay or, in the alternative, to dismiss the Mallon Federal Action. In September, a motion to stay the Mallon State Court action was subsequently filed by Mallon and TransFinancial. In November 2007, the U.S. District Court in Colorado dismissed the complaint in the Mallon Federal Action and Mallon and TransFinancial subsequently withdrew their motion to stay the Mallon State Court Action.
14. Regulatory Assets and Liabilities
PSCo’s consolidated financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the consolidated financial statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting. If changes in the utility industry or the business of PSCo no longer allow for the application of SFAS No. 71 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) Included in other current liabilities of $108,979 and $74,381 at Dec. 31, 2007 and 2006, respectively, on the consolidated balance sheets.
15. Segments and Related Information
PSCo has two reportable segments, regulated electric utility and regulated natural gas utility.
· PSCo’s regulated electric utility 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 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 (CODM) 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 are separately determined for each segment.
16. 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 3 for further discussion of this borrowing arrangement.
Utility Engineering Corp. (UE), a former Xcel Energy subsidiary, provided construction services to PSCo, for which it was paid $3.3 million in 2005. UE was sold in April 2005.
Cheyenne Light, Fuel and Power (Cheyenne), a former Xcel Energy subsidiary, purchased all of its electricity requirements from PSCo. During 2004, Xcel Energy reached an agreement to sell Cheyenne. The sale was completed in January 2005.
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:
17. Summarized Quarterly Financial Data (Unaudited)
Item 9
Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
During 2006 and 2007, 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(T)
Item 9A(T) - 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 Securities and Exchange Commission 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, 2007, based on an evaluation carried out under the supervision and with the participation of PSCo’s management, including the CEO and the CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that PSCo’s disclosure controls and procedures are effective.
Internal Control 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, 2007 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.
This annual report does not include an attestation report of PSCo’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by PSCo’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit PSCo to provide only management’s report in this annual report.
Item 9B
Item 9B - Other Information
None.
PART III
Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for 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, Related Transactions and Director Independence
Item 14
Item 14 - Principal Accounting Fees and Services
Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2008 Annual Meeting of Shareholders, which is incorporated by reference.
PART IV
Item 15
Item 15 - Exhibits, Financial Statement Schedules
1. Consolidated Financial Statements:
Management Report on Internal Controls - For the year ended Dec. 31, 2007.
Report of Independent Registered Public Accounting Firm - For the years ended Dec. 31, 2007, 2006 and 2005.
Consolidated Statements of Income - For the three years ended Dec. 31, 2007, 2006 and 2005.
Consolidated Statements of Cash Flows - For the three years ended Dec. 31, 2007, 2006 and 2005.
Consolidated Balance Sheets - As of Dec. 31, 2007 and 2006.
2. Schedule II - Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2007, 2006 and 2005.
3. Exhibits
*Indicates incorporation by reference
+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
2.01*
Merger Agreement and Plan of Reorganization dated Aug. 22, 1995 (Form 8-K, dated Aug. 22, 1995, File No. 1-3280 - Exhibit 2).
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:
4.03*
Indenture dated July 1, 1999, between Public Service Co. of Colorado 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*
$700,000,000 Credit Agreement dated Dec. 14, 2006 between PSCo and various lenders (Exhibit 99.01 to Form 8-K (file no. 001-03280) dated Dec. 14, 2006).
4.06*
Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust National Association, as successor Trustee. (Exhibit 4.01 to PSCo Form 8-K (file no 001-3280) dated Aug. 14, 2007).
10.01*+
Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+
Employment Agreement dated March 24, 1999, among Northern States Power Co. (a Minnesota corporation), New Century Energies, Inc. and Wayne H. Brunetti (Exhibit 10(b) to New Century Energies, Inc. Form 10-Q, (file no. 001-12927) dated March 31, 1999).
10.03*+
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*+
Supplemental Executive Retirement Plan (Exhibit 10(e) (1) to New Century Energies, Inc. Form 10-K (file no. 001-12927) dated Dec. 31, 1998).
10.06*+
Supplemental Executive Retirement Plan for Key Management Employees, as amended and restated March 26, 1991 (Exhibit 10(e)(2) to PSCo Form 10-K (file no. 001-3280) dated Dec. 31, 1991).
10.07*+
Supplemental Retirement Income Plan as amended July 23, 1991 (Exhibit 10(d) to SPS Form 10-K, (file no. 001-03789) dated Aug. 31, 1996).
10.08*+
Xcel Energy Senior Executive Severance and Change-in-Control Policy dated Oct. 22, 2003 (Exhibit 10.10 to SPS Form S-4, (file no. 333-112032) dated Jan. 21, 2004).
10.09*+
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2004 (Exhibit B to Form DEF-14A (file no. 001-03034) dated Apr. 9, 2004).
10.10*+
Xcel Energy Nonqualified Deferred Compensation Plan (2002 restatement) (Exhibit 10.23 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
10.11*+
Xcel Energy Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (file no. 001-03034) dated March 15, 2004).
SCHEDULE II
PUBLIC SERVICE CO. OF COLORADO AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2007, 2006 and 2005
(Thousands of Dollars)
1) Recovery of amounts previously written off.
2) Principally bad debts written off or transferred.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF COLORADO
/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Chief Financial Officer
(Principal Financial Officer)
February 25,
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/ TIM E. TAYLOR
/s/ RICHARD C. KELLY
Tim E. Taylor
Richard C. Kelly
President, Chief Executive Officer and Director
Chairman and Director
(Principal Executive Officer)
/s/ TERESA S. MADDEN
/s/ BENJAMIN G.S. FOWKE III
Teresa S. Madden
Benjamin G.S. Fowke III
Vice President and Controller
Vice President, Chief Financial Officer and Director
(Principal Accounting Officer)
(Principal Financial Officer)
/s/ PAUL J. BONAVIA
Paul J. Bonavia
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.